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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 [NO FEE REQUIRED]
For the fiscal year ended December 31, 1999 or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from to
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Commission file number 1-7176
THE COASTAL CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 74-1734212
(State or other jurisdiction of
incorporation or organization) (I.R.S. Employer Identification No.)
Coastal Tower
Nine Greenway Plaza
Houston, Texas 77046-0995
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (713) 877-1400
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Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
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Common Stock ($.33 1/3 par value)
$1.19 Cumulative Convertible Preferred Stock,
Series A ($.33 1/3 par value)
$1.83 Cumulative Convertible Preferred Stock,
Series B ($.33 1/3 par value)
8.375 % Coastal Trust Preferred Securities
issued by Coastal Finance I
Growth PRIDES
Income PRIDES
10-1/4% Senior Debentures 7-3/4% Senior Debentures New York
10-3/8% Senior Notes 7.42% Senior Debentures Stock Exchange
10-3/4% Senior Debentures 6.70% Senior Debentures
10% Senior Notes 6.50% Senior Debentures
9-3/4% Senior Debentures 6.95% Senior Debentures
9-5/8% Senior Debentures 6.375% Senior Debentures
8-1/8% enior Notes 6-5/8% Senior Denbentures
Securities registered pursuant to Section 12(g) of the Act:
Class A Common Stock ($.33-1/3 par value)
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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, 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. [ ]
As of February 1, 2000, there were outstanding 213,317,184 shares of
common stock, 343,732 shares of Class A common stock, 52,938 shares of $1.19
Cumulative Convertible Preferred Stock, Series A, 57,655 shares of $1.83
Cumulative Convertible Preferred Stock, Series B and 26,680 shares of $5.00
Cumulative Convertible Preferred Stock, Series C, of the Registrant. The
aggregate market value on such date of the voting stock of the Registrant held
by non- affiliates was an estimated $6.96 billion, based on the closing prices
in the daily composite list for transactions on the New York Stock Exchange and
other markets.
Documents incorporated by reference:
Portions of the Registrant's Proxy Statement for the 2000 Annual Meeting
of Stockholders, to be filed pursuant to Regulation 14A under the Securities
Exchange Act of 1934 on or before April 30, 2000, or in an amendment to this
Form 10-K Annual Report, referred to in Part III hereof.
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TABLE OF CONTENTS
Item No. Page
Glossary.....................................................(ii)
PART I
1. Business..................................................... 1
Introduction............................................. 1
Recent Development....................................... 1
Natural Gas Systems...................................... 1
Operations........................................... 1
ANR Pipeline......................................... 3
Colorado............................................. 3
ANR Storage Company.................................. 4
Gas System Reserves.................................. 4
Alliance Pipeline Project............................ 5
Gulfstream Natural Gas System........................ 5
Wyoming Interstate Company, Ltd...................... 5
Great Lakes Gas Transmission Limited Partnership..... 6
Unregulated Gas Operations........................... 6
Regulations Affecting Gas Systems.................... 7
Refining, Marketing and Distribution, and Chemicals...... 9
Exploration and Production............................... 12
Coal..................................................... 16
Power.................................................... 17
Competition.............................................. 20
Environmental............................................ 20
2. Properties................................................... 20
3. Legal Proceedings............................................ 21
4. Submission of Matters to a Vote of Security Holders.......... 22
PART II
5. Market for the Registrant's Common Equity and Related
Stockholder Matters ......................................... 23
6. Selected Financial Data...................................... 24
7. Management's Discussion and Analysis of Financial Condition
and Results of Operations.................................... 24
7A. Quantitative and Qualitative Disclosures About Market Risk... 25
8. Financial Statements and Supplementary Data.................. 25
9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure..................................... 25
PART III
10. Directors and Executive Officers of the Registrant........... 26
11. Executive Compensation....................................... 27
12. Security Ownership of Certain Beneficial Owners and
Management................................................... 27
13. Certain Relationships and Related Transactions............... 27
PART IV
14. Exhibits, Financial Statement Schedules, and Reports on
Form 8-K..................................................... 28
(i)
<PAGE>
GLOSSARY
"AICPA" means American Institute of Certified Public Accountants
"ANR Pipeline" means ANR Pipeline Company and its subsidiaries
"ANR Storage" means ANR Storage Company and its subsidiaries
"Bcf" means billion cubic feet "BTU" means British thermal unit
"CIG" or "Colorado" means Colorado Interstate Gas Company and its subsidiaries
"Coastal" or "Company" means The Coastal Corporation and its subsidiaries
"East Breaks" means East Breaks Gathering Company, L.L.C.
"Empire State Pipeline" means Empire State Pipeline Company, Inc.
"EPA" means U.S. Environmental Protection Agency
"FAS" means Statement of Financial Accounting Standards
"FASB" means Financial Accounting Standards Board
"FERC" means Federal Energy Regulatory Commission
"Great Lakes" means Great Lakes Gas Transmission Limited Partnership
"HIOS" means High Island Offshore System, L.L.C.
"Huddleston" means Huddleston & Co., Inc., Houston, Texas - (Volumes in the
Huddleston Report are at 14.65 pounds per square inch absolute and 60
degrees Fahrenheit)
"Mcf" means thousand cubic feet
"MMcf" means million cubic feet
"NGA" means Natural Gas Act of 1938, as amended
"Order 636" means FERC Order No. 636 which required significant changes in
services provided by interstate natural gas pipelines, including the
unbundling of services
"Stingray" means Stingray Pipeline Company, L.L.C.
"TransCanada" means TransCanada PipeLines Limited
"UTOS" means U-T Offshore System, L.L.C.
"WIC" means Wyoming Interstate Company, Ltd.
"working gas" means that volume of gas available for withdrawal from natural gas
storage fields and use by the Company's customers
NOTES:
The terms "Coastal" and "Company" are used in this Annual Report for purposes of
convenience and are intended to refer to The Coastal Corporation and/or its
subsidiaries either individually or collectively, as the context may require.
These references are not intended to suggest that the various Coastal companies
referred to are not independent corporate entities having their separate
corporate identities and managements.
This Annual Report includes certain forward-looking statements. The
forward-looking statements reflect the Company's expectations, objectives and
goals with respect to future events and financial performance and are based on
assumptions and estimates which the Company believes are reasonable. However,
actual results could differ materially from anticipated results. Important
factors which may affect the actual results include, but are not limited to,
commodity prices, political developments, market and economic conditions,
industry competition, the weather, changes in financial markets and changing
legislation and regulations. The forward-looking statements contained in this
Report are intended to qualify for the safe harbor provisions of Section 21E of
the Securities Exchange Act of 1934, as amended.
Unless otherwise noted, all natural gas volumes presented in this Annual Report
are stated at a pressure base of 14.73 pounds per square inch absolute and 60
degrees Fahrenheit.
(ii)
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PART I
Item 1. Business.
INTRODUCTION
Coastal, acting through its subsidiaries, is a diversified energy holding
company with subsidiary operations in natural gas gathering, marketing,
processing, storage and transmission; petroleum refining, marketing and
distribution and chemicals; gas and oil exploration and production; coal mining;
and power. The Company was incorporated under the laws of Delaware in 1972 to
become the successor parent, through a corporate restructuring, of a corporate
enterprise founded in 1955. The Company employed approximately 13,000 persons as
of December 31, 1999.
Annual Reports on Form 10-K for the year ended December 31, 1999 will also
be filed by Coastal's subsidiaries, ANR Pipeline and Colorado. Such reports
contain additional details concerning the reporting organizations.
Selected financial information of the Company by industry segment for the
years ended December 31, 1999, 1998 and 1997, is set forth in Note 9 of the
Notes to Consolidated Financial Statements included herein. Information
concerning inventories is set forth in Note 2 of the Notes to Consolidated
Financial Statements included herein.
RECENT DEVELOPMENT
Coastal and El Paso Energy Corporation ("El Paso Energy") announced on
January 18, 2000 the execution of definitive agreements for the merger of
Coastal and El Paso Energy. Each share of Coastal common stock and Class A
common stock will be converted on a tax-free basis (except for cash paid in lieu
of fractional shares) into 1.23 shares of El Paso Energy common stock. The
outstanding convertible preferred stock of Coastal will be exchanged tax free
(except for cash paid in lieu of fractional shares) for El Paso Energy common
stock on the same basis as if the preferred stock had been converted into
Coastal common stock immediately prior to the merger. It is expected that the
merger will be completed during the fourth quarter of 2000 and be accounted for
as a pooling of interests. The merger is subject to various conditions,
particularly federal regulatory approval.
NATURAL GAS SYSTEMS
OPERATIONS
General
Natural gas operations involve the production, purchase, gathering,
processing, transportation, balancing, storage, marketing and sale of natural
gas to and for utilities, industrial customers, marketers, producers,
distributors, other pipeline companies and end users.
ANR Pipeline is involved in the "open access" transportation, storage,
gathering and balancing of natural gas owned by third parties. ANR Pipeline
provides these services for various customers through its facilities located in
Arkansas, Illinois, Indiana, Iowa, Kansas, Kentucky, Louisiana, Michigan,
Mississippi, Missouri, Nebraska, Ohio, Oklahoma, Tennessee, Texas, Wisconsin and
offshore in the Gulf of Mexico.
ANR Pipeline's two interconnected, large-diameter multiple pipeline
systems transport gas for markets in the Midwest and the Northeast regions of
the United States from (a) the Hugoton Field and other fields in the Anadarko
Basin in Texas and Oklahoma, (b) the Louisiana onshore and the offshore Gulf of
Mexico areas and (c) Canada and other basins received through interconnections
with other pipelines located throughout its system. ANR Pipeline has an indirect
50%-ownership interest in HIOS, UTOS, East Breaks and Stingray, all of which own
pipeline systems
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located in the Gulf of Mexico. In addition, ANR Pipeline operates Empire State
Pipeline's intrastate pipeline in which an affiliate has a 50% interest and
which extends from Niagara Falls to Syracuse, New York.
ANR Pipeline's principal pipeline facilities at December 31, 1999
consisted of 10,580 miles of pipeline and 75 compressor stations with 1,022,217
installed horsepower. At December 31, 1999, the design peak day delivery
capacity of the transmission system, considering supply sources, storage,
markets and transportation for others, was approximately 6 Bcf per day.
ANR Pipeline has approximately 202 Bcf of underground working gas storage
capacity, with a maximum day delivery capacity of 3 Bcf. Working gas storage
capacity operated by ANR Pipeline of 126.3 Bcf is available from five owned and
five leased underground storage facilities in Michigan. In addition, ANR
Pipeline has the contracted rights for 75.4 Bcf of working gas storage capacity
of which 45.4 Bcf is provided by Blue Lake Gas Storage Company and 30 Bcf is
provided by ANR Storage.
Colorado is involved in the production, purchase, gathering, processing,
transportation, storage and sale of natural gas. Colorado's gas transmission
system extends from gas production areas in the Texas Panhandle, western
Oklahoma and western Kansas, northwesterly through eastern Colorado to the
Denver area, and from production areas in Montana, Wyoming and Utah,
southeasterly to the Denver area. Colorado's gas gathering and processing
facilities are located throughout the production areas adjacent to its
transmission system. Most of Colorado's gathering facilities connect directly to
its transmission system, but some gathering systems are connected to other
pipelines. Colorado owns four underground gas storage fields - three located in
Colorado and one in Kansas.
Colorado's principal transmission and storage pipeline facilities,
including certain facilities in the Panhandle Field of Texas ("Panhandle
Field"), at December 31, 1999 consisted of 4,405 miles of pipeline and 58
compressor stations with approximately 296,000 installed horsepower. Colorado is
directly or indirectly connected to every major supply basin in the Rocky
Mountain region, and at December 31, 1999, the design peak day gas delivery
capacity of the transmission system was approximately 2.2 Bcf per day. The
underground gas storage facilities have a working capacity of approximately 29
Bcf and a peak day delivery capacity of approximately 775 MMcf.
Colorado's gathering facilities, excluding certain FERC regulated
facilities in the Panhandle Field, consist of 2,400 miles of gathering lines and
approximately 52,000 horsepower of compression. Colorado owned and operated four
gas processing plants in 1999. These plants, with a total operating capacity of
approximately 477 MMcf daily, recover mainly propane, butanes, natural gasoline,
sulfur and other by-products, which are sold to refineries, chemical plants and
other customers.
Competition
Natural gas competes with other forms of energy available to customers,
primarily on the basis of price paid by end users. These competitive forms of
energy include electricity, coal, propane and fuel oils. Changes in the
availability or price of natural gas or other forms of energy, as well as
changes in business conditions, conservation, legislation or governmental
regulations, capability to convert to alternate fuels, the weather, changes in
rate structure, taxes and other factors may affect the demand for natural gas in
the areas served by ANR Pipeline and Colorado.
In recent years, the FERC issued orders designed to increase competition
in the natural gas industry. These orders have resulted in: (1) pipelines
offering more service options and pricing flexibility in order to maintain and
increase business volumes, and (2) pipelines competing with their customers, who
are now allowed to resell, i.e., release, their unused firm capacity. In
addition, firm contracts traditionally had terms of five to ten years; however,
due to increased competition, new firm contracts are of a shorter average
duration.
ANR Pipeline competes in its historical market areas of Wisconsin and
Michigan with other interstate and intrastate pipeline companies and local
distribution companies in the transportation and storage of natural gas. ANR
Pipeline also faces competition in the Northeast markets from other interstate
pipelines in serving both electric generation and local distribution companies.
Increasingly, ANR Pipeline also competes with independent producers and other
companies seeking to construct interstate transmission facilities and with a
number of marketing companies which
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aggregate capacity released by firm shippers for the purpose of managing gas
requirements for end users. Additionally, Colorado competes with interstate and
intrastate pipeline companies in the sale, transportation and storage of natural
gas and with independent producers, brokers, marketers, and other pipelines in
the gathering, processing and sale of gas within its service area.
ANR PIPELINE
Transportation and Storage Services
ANR Pipeline transports and stores gas owned by third parties, including
distributors, intrastate and interstate pipelines, producers, brokers, marketers
and end users, for markets both on and off its system. Transportation service
revenues amounted to $431 million for 1999 compared to $481 million for 1998 and
$497 million for 1997. Gas storage revenues amounted to $136 million for 1999 as
compared to $139 million for 1998 and $146 million for 1997.
During 1999, approximately 26% of ANR Pipeline's transportation service
revenues were from its three largest customers: Wisconsin Gas Company, Wisconsin
Electric Power Company Inc. and Michigan Consolidated Gas Company. Wisconsin Gas
Company serves the Milwaukee metropolitan area and numerous other communities in
Wisconsin. Wisconsin Electric Power Company Inc. serves the cities of Racine,
Kenosha, Appleton and their surrounding areas in Wisconsin. Michigan
Consolidated Gas Company serves the city of Detroit and certain surrounding
areas, the cities of Grand Rapids and Muskegon, the communities of Ann Arbor and
Ypsilanti and numerous other communities in Michigan. In 1999, ANR Pipeline
provided approximately 67% and 35% of the total gas requirements of Wisconsin
and Michigan, respectively.
ANR Pipeline's system deliveries for the years 1999, 1998 and 1997 were as
follows:
Total System Daily Average
Year Deliveries System Deliveries
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(Bcf) (MMcf)
1999 1,362 3,732
1998 1,354 3,710
1997 1,424 3,901
COLORADO
Gas Sales, Storage and Transportation
Colorado's gas sales consist primarily of Colorado-owned production.
Additionally, Colorado engages in "open access" storage and transportation of
gas owned by third parties.
Colorado's deliveries for the years 1999, 1998 and 1997 were as follows:
Total System Daily Average
Year Deliveries System Deliveries
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(Bcf) (MMcf)
1999 454 1,245
1998 480 1,315
1997 486 1,333
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Gas Gathering and Processing
Colorado provides gathering and processing services on an "unbundled," or
stand-alone basis. Colorado's processing terms are not regulated by the FERC,
but Colorado is required to provide "open access" to its regulated processing
facilities. The gathering that Colorado provides in the Panhandle Field
continues to be regulated by the FERC, and Colorado is limited to charging rates
between minimum and maximum levels approved by the FERC. The gathering and
processing that Colorado's subsidiary, CIG Field Services Company, provides is
not regulated by the FERC.
The gas processing plants recovered approximately 38 million gallons of
liquid hydrocarbons in 1999 compared to 46 million gallons in 1998 and 55
million gallons in 1997. Additionally, Colorado processed approximately 24
million gallons of liquid hydrocarbons owned by others in 1999 compared to 25
million gallons in 1998 and 24 million gallons in 1997.
ANR STORAGE COMPANY
ANR Storage develops and operates natural gas storage reservoirs to store
gas for customers. ANR Storage owns four underground storage fields and related
facilities in northern Michigan, the working storage capacity of which is
approximately 56 Bcf, including 30 Bcf which is contracted to ANR Pipeline. ANR
Storage also owns indirectly a 50% equity interest in two, and a 75% equity
interest in one, joint venture-owned and -operated storage facilities located in
Michigan and New York with a total working storage capacity of approximately 65
Bcf. All of the jointly owned capacity is committed under long-term contracts,
including 45.4 Bcf which is contracted to ANR Pipeline by Blue Lake Gas Storage
Company.
GAS SYSTEM RESERVES
ANR Pipeline
Access to Gas Supply
Shippers on ANR Pipeline have direct access to the two most prolific
United States gas producing areas, the Gulf Coast and Mid-Continent. Statistics
published by the Energy Information Agency, Office of Oil and Gas, U. S.
Department of Energy, indicate that approximately 76% of all natural gas in the
lower 48 states is produced from these two areas.
In addition, interconnecting pipelines provide shippers, in general, with
access to all other major gas producing areas in the United States and Canada.
An interconnection with Colorado, an affiliate of ANR Pipeline, provides ANR
Pipeline shippers with access to the Rocky Mountain producing area. Rocky
Mountain production contributes approximately 15% of the total gas production in
the lower 48 states. Gas produced in Western Canada, nearly 100% of all Canadian
gas production, is accessible to ANR Pipeline shippers through existing
interconnections with Great Lakes, Viking Gas Transmission Company and Northern
Border Pipeline Company, the latter two companies being unaffiliated.
Gas deliverability available to shippers on ANR Pipeline's system from the
Mid-Continent, Rocky Mountain, Western Canada and Gulf Coast producing areas
through direct connections and interconnecting pipelines and gatherers is
approximately 4,900 MMcf per day. ANR Pipeline remains active in locating and
connecting new sources of natural gas to facilitate transportation arrangements
made by third-party shippers. During 1999, field development, newly connected
gas wells, gas production facilities and pipeline interconnections contributed
approximately 1,100 MMcf per day to total deliverability accessible to shippers
on ANR Pipeline's system.
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Colorado
Colorado will report in its Form 10-K for the year ended December 31,
1999, its Natural Gas System reserves based on information prepared by
Huddleston, the Company's independent engineers, while its Exploration and
Production segment reserves are as prepared by the Company and reviewed by
Huddleston.
Reserves Dedicated to a Particular Customer
Colorado is committed to sell gas to Pioneer Natural Resources, USA, Inc.,
("Pioneer"), a customer, under a 1928 agreement, as amended, from specific owned
gas reserves in the West Panhandle Field of Texas. Under an amendment which
became effective January 1, 1991, a cumulative 23% of the total net production
from this Field may be taken for customers other than Pioneer.
ALLIANCE PIPELINE PROJECT
Coastal, through subsidiaries, has a 14.4% equity interest in the
corporations and partnerships comprising the Alliance Pipeline Project
("Alliance"). Alliance, when completed, will be a 1,900-mile pipeline initially
designed to carry 1.325 Bcf of natural gas per day and associated liquids from
western Canada to the Chicago-area market center. In 1998, both the FERC and the
Canadian National Energy Board granted approval to proceed with the construction
and operation of Alliance. The project is scheduled to be in service by the end
of 2000. Alliance will interconnect with the ANR Pipeline system, among other
pipelines.
GULFSTREAM NATURAL GAS SYSTEM
Coastal, through subsidiaries, plans to construct and operate the proposed
Gulfstream Natural Gas System ("Gulfstream System"), consisting of 744 miles of
pipeline and related facilities, originating near Mobile, Alabama, crossing the
Gulf of Mexico in a southeasterly direction, and ultimately terminating near
Florida's East Coast in West Palm Beach, Florida. Coastal intends to add equity
investors to the project. With an anticipated initial capacity of 1.1 Bcf per
day, the Gulfstream System is expected to be in service in June 2002, subject to
receipt of satisfactory governmental approvals.
WYOMING INTERSTATE COMPANY, LTD.
WIC, a limited partnership owned by two wholly owned Coastal subsidiaries,
owns an interstate pipeline system located primarily in Wyoming. The main WIC
pipeline is a 269-mile, 36-inch diameter pipeline that is the center section of
the 800-mile Trailblazer pipeline system built by a group of companies to move
gas from the Overthrust Belt and other Rocky Mountain areas to supply midwestern
and eastern markets. WIC is also connected to Colorado's pipeline facilities and
Colorado has received FERC approval to continue to hold its capacity on WIC for
Colorado's operational needs as well as for certain third parties. Colorado and
other companies for which the WIC line transports gas have entered into
long-term contracts having forward-haul reservation volumes totaling 1,033 MMcf
daily. In 1999, the WIC line transported an average of 632 MMcf daily, compared
to 622 MMcf daily and 546 MMcf daily in 1998 and 1997, respectively. In late
November 1999, WIC placed in service the Medicine Bow Lateral, a 150-mile
pipeline for transporting coal-bed methane gas from the Powder River Basin to
WIC's main line west of Cheyenne, Wyoming. WIC has long-term transportation
commitments for the Medicine Bow Lateral beginning at 273 MMcf per day and
increasing to 400 MMcf per day by October 2000. On September 16, 1999, WIC filed
with the FERC for approval to construct additional facilities on the Medicine
Bow Lateral to increase capacity to meet such contractual commitments.
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GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
Coastal and TransCanada, a non-affiliated company, each own 50% of Great
Lakes, which in turn owns a 2,101-mile, 36-inch diameter gas pipeline system
from the Manitoba-Minnesota border to an interconnection on the Michigan-Ontario
border at St. Clair, Michigan. Great Lakes transported 937 Bcf in 1999 as
compared to 907 Bcf in 1998 and 910 Bcf in 1997. Great Lakes has long-term
contract commitments to transport a total of 1.68 Bcf per day for TransCanada
and affiliates. It also transports up to 1.1 Bcf per day primarily for United
States markets, including 224 MMcf per day to Coastal affiliates. Great Lakes
exchanges gas with ANR Pipeline by delivering gas in the upper peninsula of
Michigan and receiving an equal amount of gas in the lower peninsula of
Michigan.
UNREGULATED GAS OPERATIONS
Coastal's unregulated natural gas business includes certain of Coastal's
natural gas midstream activities (i.e., gathering, processing, natural gas
liquids ("NGL") pipelines, NGL storage, fractionation, gas supply and gas and
NGL marketing), and is operated primarily through two subsidiaries, Coastal
Field Services Company ("CFSC") and Coastal Gas International Company ("CGI").
CFSC owns, or operates for various affiliates, domestic midstream assets
in Alabama, Colorado, Kansas, Louisiana, Mississippi, Oklahoma, Texas, Utah,
Wyoming and offshore in the Gulf of Mexico. These assets include interests in
over 3,900 miles of gathering pipelines, which collect gas from over 3,900
wells. CFSC gathered approximately 0.9 Bcf of gas per day in 1999 and
approximately 1 Bcf per day in each of 1998 and 1997. CFSC and its affiliates
also have an ownership interest in 14 gas processing plants, 11 of which are
operated by CFSC. CFSC's processing plant capacity is approximately 3.2 Bcf per
day. Fractionation capacity is approximately 106,000 barrels per day. In
addition, CFSC owns approximately 450 miles of NGL pipelines and operates an NGL
storage facility with a capacity of 2.4 million barrels. NGLs produced at
CFSC-operated plants and from gas processed by others for CFSC averaged more
than 25,000 barrels per day in 1999, as compared to more than 23,000 barrels per
day in 1998 and 25,000 barrels per day in 1997.
CFSC holds a 14.6% interest in the 270-mile Dauphin Island Gathering
Partners ("DIGP") pipeline system which gathers and transports natural gas from
major producing areas offshore in the eastern Gulf of Mexico. DIGP transports
gas onshore to Louisiana and Mobile Bay, Alabama, where CFSC holds an interest
in a 600-MMcf-per-day-gas processing plant and a 40-megawatt cogeneration plant.
The cogeneration plant provides power and process heat for the gas plant. The
gas plant and associated cogeneration plant commenced operations in April 1999.
In 1999, CFSC increased its ownership interest in the gas processing and
cogeneration plants from 13.6% to 42.4% and also acquired an indirect interest
of 7% in the Tri States NGL pipeline system ("Tri States"). Tri States, which
commenced operation in April 1999, is a 217-mile system that transports NGLs
from Mobile Bay area gas processing plants to fractionators and markets in
Louisiana.
In late December 1999, CFSC acquired TransCanada Gas Processing U.S.A., a
fully-integrated, midstream company, with primary operations in Louisiana and
assets that include four gas processing plants with net working interest
capacity of over 2 Bcf per day, three NGL fractionation plants with a capacity
of 90,000 barrels per day, 2.4 million barrels of salt cavern NGL storage, about
380-miles of NGL pipelines, plus marine docks, rail and truck loading and
related distribution facilities that provide market access for ethane, propane,
butanes and natural gasoline products. CFSC operates all but one of the gas
processing plants. During 1999, NGLs produced at the plants averaged more than
35,000 barrels per day.
In November 1999, CFSC acquired the 125-MMcf-per-day Gilmore No. 3 gas
processing plant in Hidalgo County in South Texas. Gilmore No. 3 processes gas
produced by Coastal in the Jeffress and Monte Cristo Fields and other nearby
producing fields. CFSC also completed, in December 1999, construction of a
150-MMcf-per-day gas treatment plant in La Vaca County, Texas, which removes
carbon dioxide from the gas produced by Coastal from the Dry Hollow and Brushy
Creek Fields.
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In the Rocky Mountain region, CFSC, in March 1999, increased its ownership
in the Bluebell gas processing plant in Utah from 28% to 100% and acquired a
fractionator in Altonah, Utah. CFSC also completed major expansions of its Ouray
gathering system in the Uinta Basin in Utah and its Dragon Trail gathering
system in the Piceance Basin in Colorado. The expansions included additional
pipeline and compression facilities to provide capacity to receive gas from
wells to be drilled by Coastal in the Piceance and Uinta Basins. CFSC also
entered the Powder River Basin of Wyoming in 1999 with the construction of a
gathering system, the Rawhide Buttes system. The Rawhide Buttes system gathers
gas from coal-bed methane wells and delivers the gas to an interstate pipeline
in Campbell County, Wyoming.
An affiliate of CFSC owns a 14.4% interest in the Aux Sable gas processing
and fractionation complex located near Chicago at the terminus of the Alliance
Pipeline System. Aux Sable has exclusive rights to process natural gas and
extract NGLs transported on Alliance and is expected to commence operations in
late 2000. The Aux Sable facilities are initially designed to process up to 1.6
Bcf of natural gas per day and recover approximately 70,000 barrels of NGLs per
day.
CGI conducts the international natural gas operations of the Company. In
1998, Coastal Gas Pipelines Victoria Pty Ltd, an affiliate of CGI, completed
construction and placed into operation a 113-mile natural gas transmission line
in Victoria, Australia. CGI and its affiliates are pursuing additional gas
projects in Canada and Latin America.
Engage Energy US, L.P. and Engage Energy Canada, L.P. (together, "Engage")
handle unregulated natural gas and power marketing for Coastal in North America.
Engage provides wholesale energy services to natural gas and power clients and
marketing services to various Coastal segments, including refining, chemicals
and exploration and production. Engage is a joint venture of Coastal (50%) and
Westcoast Energy Inc. (50%), a major Canadian natural gas company. In 1999,
Engage had physical sales volumes averaging 5.6 Bcf per day of natural gas
compared to 7 Bcf per day in 1998, and annual power sales of over 10 million
megawatt hours in 1999 compared to approximately 36 million megawatt hours in
1998.
REGULATIONS AFFECTING GAS SYSTEMS
General
Under the NGA, the FERC has jurisdiction over ANR Pipeline, Colorado, WIC,
ANR Storage, Great Lakes, HIOS, UTOS and Stingray as to rates and charges for
the transportation, storage and balancing of natural gas, the construction of
new facilities, the extension or abandonment of service and facilities, accounts
and records, depreciation and amortization policies and certain other matters.
In addition, the FERC has certificate authority over gas sales for resale in
interstate commerce, but under Order 636, has determined that it will not
regulate pipeline sales rates. Additionally, the FERC has asserted
rate-regulation (but not certificate regulation) over gathering services
provided by interstate pipeline companies such as Colorado. ANR Pipeline,
Colorado, WIC, ANR Storage, Great Lakes, HIOS, UTOS and Stingray hold
certificates of public convenience and necessity issued by the FERC covering
their jurisdictional facilities, activities and services. Certain other
affiliates of the Company are subject to the jurisdiction of state regulatory
commissions in states where their facilities are located.
ANR Pipeline, Colorado, WIC, ANR Storage, Great Lakes, HIOS, UTOS and
Stingray are also subject to regulation with respect to safety requirements in
the design, construction, operation and maintenance of their interstate gas
transmission and storage facilities by the U.S. Department of Transportation.
Additionally, subsidiaries of the Company are subject to similar safety
requirements from the U.S. Department of Labor's Occupational Safety and Health
Administration related to their processing plants. Operations on United States
government land are regulated by the U.S. Department of the Interior.
Rate Matters
Certain of the Company's subsidiaries' service options are subject to rate
regulation by the FERC. Under the NGA, these subsidiaries must file with the
FERC to establish or adjust their services and their rates. The FERC may also
initiate proceedings to determine whether these subsidiaries' rates are "just
and reasonable."
7
<PAGE>
On July 29, 1998, the FERC issued a "Notice of Proposed Rulemaking," in
which the FERC has proposed a number of significant changes to the industry,
including, among other things, removal of price caps in the short-term market
(less than one year), capacity auctions, changed reporting obligations, the
ability to negotiate terms and conditions of all services, elimination of the
requirement of a matching term cap on the renewal of existing contracts, and a
review of its policies for approving capacity construction. On the same day, the
FERC also issued a "Notice of Inquiry" soliciting industry input on various
matters affecting the pricing of long-term service and certificate pricing in
light of changing market conditions. On February 9, 2000, the FERC issued a
final rule implementing certain of the changes that were discussed in these two
proposals. Among other things, the final rule: (a) removes the price ceilings
for short-term secondary market capacity releases for a trial period through
September 30, 2002; (b) permits pipelines to propose seasonally and
term-differentiated rates; (c) revises requirements relating to pipeline
scheduling procedures, capacity segmentation and penalties; (d) narrows the
right-of-first-refusal granted to long-term shippers to retain their capacity;
and (e) expands pipeline reporting requirements. Coastal's interstate pipeline
subsidiaries will seek clarification of certain aspects of the final rule.
On September 15, 1999, the FERC issued a Policy Statement addressing the
certification and pricing of new pipeline construction projects. Under the
Policy Statement, applicants must first satisfy a threshold pricing requirement
of demonstrating that their projects can be constructed without subsidies from
existing customers. Second, the applicants must show that any adverse impacts of
the project on identified interests (existing customers of the applicant, other
existing pipelines and their captive customers, landowners and the surrounding
communities) are outweighed by its benefits. On October 19, 1999, Coastal's
interstate pipeline subsidiaries sought clarification and/or rehearing of the
Policy Statement insofar as it does not apply directly to those projects filed
for approval under the FERC's "optional certificate" regulations. Other parties
also sought rehearing of this and other aspects of the Policy Statement. On
February 9, 2000, the FERC issued an order which, among other things, held that
the Policy Statement balancing criteria would apply to new optional certificate
applications while it receives comments on its companion notice proposing to
eliminate its optional certificate regulations.
On May 30, 1997, WIC filed with the FERC to increase its rates by
approximately $5.7 million annually. On June 27, 1997, the FERC accepted the
filing effective as of December 1, 1997, subject to refund. The FERC staff and
certain participants in the proceeding raised a number of issues relating to
WIC's costs, revenue requirements and the treatment of an "exit fee" which WIC
had received in conjunction with the termination of a transportation service
agreement. WIC and most of the parties subsequently reached a settlement
resolving all issues in the case. That settlement was ultimately approved by the
FERC on June 21, 1999 (the "June 21, 1999 settlement"). Two parties opposed the
settlement and the FERC initially severed them from the settlement and ordered a
separate hearing on their issues. However, on October 13, 1999, the FERC
determined that the settlement should also apply to those parties as well,
inasmuch as WIC had filed a new rate case (discussed below) which would become
effective before any decision could be reached and implemented. The FERC denied
rehearing of the October 13, 1999 Order on December 21, 1999. The two parties
who had objected to the settlement have the right to seek judicial review of
this order.
On July 1, 1999, WIC filed with the FERC a new rate case to increase its
rates by approximately $8 million annually (based on the rates determined under
the June 21, 1999 settlement). On July 29, 1999, the FERC issued its order
accepting the rate filing and suspending it for five months to become effective
on January 1, 2000. The order also set the case for hearing, which is currently
scheduled to commence in the second half of 2000. WIC has filed to place its new
rates into effect on January 1, 2000, and is collecting those rates subject to
refund.
Certain other regulatory issues remain unresolved among CIG, ANR Pipeline,
ANR Storage Company and WIC, their customers, their suppliers and the FERC. The
Company has made provisions which represent management's assessment of the
ultimate resolution of these issues. As a result, the Company anticipates that
these regulatory matters will not have a material adverse effect on its
consolidated financial position or results of operations. While the Company
estimates the provisions to be adequate to cover potential adverse rulings on
these and other issues, it cannot estimate when each of these issues will be
resolved.
8
<PAGE>
REFINING, MARKETING AND DISTRIBUTION, AND CHEMICALS
The Company has subsidiary operations involved in the purchase,
transportation and sale of refined products, crude oil, condensate and natural
gas liquids; the operation of refineries and chemical plants; the sale at retail
of gasoline, petroleum products and convenience items; petroleum product
terminaling and marketing of crude oil and refined products worldwide.
Unless stated otherwise, the operating statistics provided in this
Refining, Marketing and Distribution, and Chemicals Section are as of December
31, 1999.
Refining
Subsidiaries of the Company operated their refineries at 93% of average
combined capacity in 1999 compared to 85% in 1998 and at 89% in 1997. The
aggregate sales volumes (millions of barrels) of Coastal's wholly owned
refineries for the three years ended December 31, 1999 were 171.3 (1999), 154.4
(1998) and 160.7 (1997). Of the total refinery sales in 1999, 29% was gasoline,
46% was middle distillates, such as jet fuel, diesel fuel and home heating oil,
and 25% was heavy industrial fuels and other products.
At December 31, 1999, average daily throughput and storage capacity at the
Company's wholly owned refineries are set forth below:
<TABLE>
<CAPTION>
Average Daily
Daily Throughput (Barrels) Storage
Capacity -------------------------- Capacity
Refinery Location (Barrels) 1999 1998 (Barrels)
- -------- -------- --------- ----------- ----------- ---------
<S> <C> <C> <C> <C> <C>
Aruba Aruba 225,000 195,000 162,300 15,300,000
Corpus Christi Corpus Christi, Texas 100,000 100,000 88,600 7,100,000
Eagle Point Westville, New Jersey 140,000 143,000 140,400 10,600,000
Mobile Mobile, Alabama 18,000 13,000 10,400 600,000
------- ------- ------- ----------
Total 483,000 451,000 401,700 33,600,000
</TABLE>
In addition, Coastal's international operations include a minority
interest, through a foreign subsidiary, in a refinery located in Hamburg,
Germany which has a refining capacity of 100,000 barrels per day and a storage
capacity of 1.8 million barrels for crude oil and 5.2 million barrels for
products.
The Company's refineries produce a full range of petroleum products
ranging from transportation fuels to paving asphalt. The refineries are operated
to produce the particular products required by customers within each refinery's
geographic area. In 1999, the products emphasized included premium gasolines and
products for specialty markets such as petrochemical feedstocks, aviation fuels
and asphalt.
On July 30, 1998, the Company, through a subsidiary, entered into an
agreement with a subsidiary of Petroleos Mexicanos, Mexico's national oil
company, for the supply of up to 100,000 barrels per day ("bpd") of crude oil to
support an upgrade of the Company's Aruba refinery. The upgrade at the refinery
will include the installation of a new 30,000 bpd delayed coking unit and other
modifications aimed at increasing the refinery's heavy crude refining and
conversion capacity to approximately 280,000 bpd. The upgrade is projected to be
in service during the first half of the year 2000.
Chemicals
Coastal Chem, Inc. ("Coastal Chem"), a Coastal subsidiary, operates a
plant near Cheyenne, Wyoming, which produces anhydrous ammonia, ammonium
nitrate, nitric acid, liquid carbon dioxide and urea for use as agricultural
fertilizers, livestock feed supplements, blasting agents and various other
industrial applications. This plant has the capacity to produce 550 tons per day
of anhydrous ammonia, 875 tons per day of ammonium nitrate, 275 tons per day of
urea, 700 tons per day of nitric acid and 400 tons per day of liquid carbon
dioxide. Coastal Chem also owns a plant
9
<PAGE>
at Table Rock, Wyoming, which has a production capacity of 150 tons of liquid
fertilizer per day. In addition, Coastal Chem operates a low density ammonium
nitrate ("LoDAN(R)") facility in Battle Mountain, Nevada, which has the capacity
to produce 400 tons per day. The LoDAN(R) product is used primarily as a
blasting agent in surface mining.
Coastal Chem also operates an integrated methyl tertiary butyl ether
("MTBE") plant in Cheyenne, Wyoming, with a production capacity of 4,200 barrels
per day. MTBE is a gasoline additive which adds oxygen and boosts octane of the
blended mixture.
Coastal's St. Helens chemical plant, located in St. Helens, Oregon, has
the capacity to produce 300 tons per day of anhydrous ammonia, 370 tons per day
of urea and 185 tons per day of urea/ammonium nitrate solutions. Approximately
55% of the plant's production is sold as industrial products and 45% as
agricultural products.
Sales volumes for Coastal Chem and St. Helens for the three years ended
December 31, 1999, are set forth below (thousands of tons):
<TABLE>
<CAPTION>
1999 1998 1997
-------- -------- ---------
<S> <C> <C> <C>
Agricultural Sales................................................... 326 346 340
Industrial Sales..................................................... 608 550 566
MTBE................................................................. 209 210 223
-------- -------- ---------
Total .......................................................... 1,143 1,106 1,129
======== ======== =========
</TABLE>
Coastal Chem and the St. Helens plant compete with many nitrogen and MTBE
producers across the United States and Canada. The Company's strengths are
product quality, service, and dependability. Coastal Chem and the St. Helens
plant produce commodity products with strong price competition from producers
worldwide.
In November 1998, the Company suspended operations at its petrochemical
facility in Montreal East, Quebec, Canada. Operations will be resumed when
supply/demand conditions provide the necessary economic support. The
petrochemical facility has the capacity to produce 330,000 tons per year of
paraxylene, a component used in the manufacturing of polyester fibers and
containers. Production (in tons) shipped and sold from the plant for the three
years ended December 31, 1999, was 11,400 (1999), 203,500 (1998) and 338,400
(1997).
The Company's 660-tons-per-day anhydrous ammonia facility located in
Oyster Creek, Texas began operation in the first quarter of 1998. Production (in
tons) sold from the facility for the year ended December 31, 1999, was 137,800
as compared to 45,000 in 1998. This plant is located adjacent to and supplies a
number of major chemical facilities.
Marketing and Distribution
Refined Products Marketing. Sales volumes for distribution activities of
Coastal subsidiaries, including products from Company refineries and purchases
from other suppliers, for the three years ended December 31, 1999, are set forth
below (thousands of barrels):
<TABLE>
<CAPTION>
Type of Sale 1999 1998 1997
- ------------ -------- --------- ---------
<S> <C> <C> <C>
Company Produced Refined Products........................................ 171,310 154,427 160,703
Refined Products Purchased from Others................................... 104,733 131,508 101,495
Natural Gas Liquids...................................................... 10,629 14,292 16,593
-------- --------- ---------
Total............................... 286,672 300,227 278,791
======== ========= =========
</TABLE>
Subsidiaries of the Company market refined products and liquefied
petroleum gas at wholesale in 31 states plus Canada, El Salvador, Bahamas and
Panama through 171 terminals. Coastal Refining & Marketing, Inc. ("CR&M") serves
customers primarily in the Midwest, Mississippi Valley and the Southwest through
104 product and liquefied
10
<PAGE>
petroleum gas terminals in 20 states. On the Gulf and East Coasts, divisions of
CR&M serve home, industry, utility, defense and marine energy needs. In 1999,
these divisions' sales volumes were 65.4 million barrels, which accounted for
approximately 23% of the total marketing and distribution sales. International
subsidiaries that acquire feedstocks for the refineries and products for the
distribution system are located in Aruba, London and Singapore.
A subsidiary of Coastal leases petroleum storage facilities located at the
former U.S. naval base at Subic Bay in the Philippines. Coastal is leasing 304
acres of land, with 68 individual storage tanks totaling 2.4 million barrels of
storage, most of which are underground, and 40 miles of pipeline connecting the
terminal with other facilities within the Subic Bay Freeport Zone. A joint
venture between a Coastal subsidiary and the Petroleum Authority of Thailand
rehabilitated the petroleum products pipeline between the Subic Bay Freeport
Zone and the Clark Special Economic Zone (formerly Clark Air Force Base), along
with a petroleum storage facility in the Clark Special Economic Zone. Both
facilities are used to support the joint venture's marketing activities in the
Philippines.
Coastal Baltica Holding Company Ltd., a joint venture in which a Coastal
subsidiary is a 50% partner, operates a terminal and port facilities near
Tallinn, Estonia on the Baltic Sea. The terminal operation handled imports and
exports of approximately 27.7 million barrels of petroleum products in 1999,
primarily from Russia and the former republics of the Soviet Union to markets in
Europe, North and South America and the Caribbean.
The Company, through Coastal Mart, Inc. and branded marketers, conducts
retail marketing, using the C-MART(R), C and Design and/or COASTAL(R)
trademarks, in 34 states and Aruba through 1,649 Coastal branded outlets, with
389 of those outlets operated by the Company. Fleet fueling operations include
23 outlets in Texas and six in Florida.
Coastal Unilube, Inc., based in West Memphis, Arkansas, blends, packages
and distributes lubricants and automotive products under the COASTAL(R), C and
Design and other trademarks through 11 warehouses servicing customers in 46
states, plus the District of Columbia, Puerto Rico and 28 foreign countries.
Transportation. The Company's transportation facilities include petroleum
liquids pipelines, tank cars, tankers, tank trucks and barges. Coastal operates
almost 1,900 miles of pipeline for gathering and transporting an average of
249,406 barrels daily of crude oil, condensate, natural gas liquids and refined
products. These pipelines include 304 miles of crude oil pipelines, 848 miles of
refined products pipelines, and 582 miles of natural gas liquids pipelines, all
located principally in Texas and in which the Company has approximately a 28%
ownership interest. Coastal has a 50% ownership in 13 miles of refined products
pipelines located in New Jersey and New York. Coastal also has a 33.3% interest
in 80 miles of refined products pipelines in New Jersey and 35 miles of crude
pipelines in Louisiana. Coastal acquired 100% of a 26-mile crude pipeline
located in Utah and Wyoming during January 1999. In 1999, throughput of crude
oil pipelines averaged 38,877 barrels per day, compared to 15,323 barrels per
day in 1998 and 13,117 barrels per day in 1997. In 1999, throughput of refined
products and natural gas liquid pipelines averaged 210,529 barrels per day,
compared to 207,800 barrels per day in 1998 and 216,204 barrels per day in 1997.
The marine transportation fleet at December 31, 1999 consisted of 14 tug
boats, 17 oil barges, five owned tankers and five time-chartered tankers.
Competition
The petroleum industry is highly competitive in the United States and
throughout most of the world. The Company's subsidiary operations involved in
refining, marketing and distribution of petroleum products and chemicals compete
with other industries in supplying the energy needs of various types of
consumers. Principle factors affecting sales are price, location and service.
Overall performance is impacted by industry margins, and supply and demand for
both feedstocks and finished products.
11
<PAGE>
EXPLORATION AND PRODUCTION
Gas and Oil Properties
Coastal subsidiaries are engaged in gas and oil exploration, development
and production operations principally in Colorado, Kansas, Louisiana, New
Mexico, Oklahoma, Texas, Utah, Wyoming and offshore in the Gulf of Mexico. In
addition, Coastal subsidiaries have exploration and production rights in
Australia, Brazil, Canada, Hungary and Indonesia.
In 1999, the Company's domestic exploration and production operations sold
approximately 13% of all the gas it produced to certain of Coastal's wholly
owned natural gas system subsidiaries and approximately 78% to Engage. The
Company's domestic operations also make short-term gas sales directly to
industrial users and distribution companies. Oil is sold primarily under
short-term contracts at field prices posted by the principal purchasers of oil
in the areas in which the producing properties are located.
Acreage held under gas and oil mineral leases as of December 31, 1999 is
summarized as follows:
<TABLE>
<CAPTION>
Undeveloped Developed
Area Gross Net Gross Net
------------------------------------------------------------ --------- -------- --------- --------
(Thousands of Acres)
<S> <C> <C> <C> <C>
Exploration and Production
--------------------------
United States (Domestic)
Onshore.......................................... 1,138 754 1,326 586
Offshore......................................... 473 401 362 245
--------- -------- --------- ---------
Total Domestic................................... 1,611 1,155 1,688 831
--------- -------- --------- ---------
Canada................................................. 93 92 15 14
--------- -------- --------- ---------
Total North America.............................. 1,704 1,247 1,703 845
--------- -------- --------- ---------
International
Australia........................................ 1,770 614 - -
Brazil........................................... 1,742 1,260 - -
Hungary.......................................... 568 568 - -
Indonesia........................................ 1,374 443 - -
--------- -------- --------- ---------
Total International.............................. 5,454 2,885 - -
--------- -------- --------- ---------
Total Exploration and Production....................... 7,158 4,132 1,703 845
--------- -------- --------- ---------
Natural Gas Systems
-------------------
Domestic Onshore....................................... - - 263 259
--------- -------- --------- ---------
Total Acreage............................................... 7,158 4,132 1,966 1,104
========= ======== ========= =========
</TABLE>
The domestic net developed acreage is concentrated principally in Texas
(30%), Utah (31%), offshore Gulf of Mexico (22%), Colorado (9%) and Kansas (4%).
Approximately 13%, 9% and 7% of the Company's total domestic net undeveloped
acreage is under leases that have minimum remaining primary terms expiring in
2000, 2001 and 2002, respectively.
12
<PAGE>
Productive wells as of December 31, 1999 are as follows (domestic):
<TABLE>
<CAPTION>
Type of Well Gross Net
------------------------------------------------------------------------------------- --------- ---------
<S> <C> <C>
Exploration and Production
--------------------------
Oil............................................................................ 527 353
Gas............................................................................ 2,825 2,040
--------- ---------
Total Exploration and Production............................................... 3,352 2,393
--------- ---------
Natural Gas Systems
-------------------
Oil............................................................................ 9 8
Gas............................................................................ 805 793
--------- ---------
Total Natural Gas Systems...................................................... 814 801
--------- ---------
Total.................................................................... 4,166 3,194
========= =========
</TABLE>
Exploration and Drilling
During 1999, Coastal's domestic subsidiaries participated in drilling 276
gross wells, 206.7 net wells, to the Company's interest. Coastal's participation
in wells drilled in the three years ended December 31, 1999, is summarized as
follows:
<TABLE>
<CAPTION>
Exploration and Production 1999 1998 1997
-------------------------- ------------------- ------------------- --------------------
Exploratory Wells Gross Net Gross Net Gross Net
----------------- -------- -------- --------- -------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
Oil...................... - - - - - -
Gas...................... 9 7.4 7 5.1 8 3.3
Dry Holes................ 5 4.5 7 3.4 5 2.9
-------- -------- --------- -------- --------- ---------
14 11.9 14 8.5 13 6.2
======== ======== ========= ======== ========= =========
Development Wells
-----------------
Oil...................... 1 1.0 4 2.9 2 1.7
Gas...................... 238 179.7 186 139.5 128 96.7
Dry Holes................ 1 1.0 2 1.4 4 2.2
-------- -------- --------- -------- --------- ---------
240 181.7 192 143.8 134 100.6
======== ======== ========= ======== ========= =========
Natural Gas Systems
-------------------
Development Wells
-----------------
Oil...................... - - - - - -
Gas...................... 22 13.1 6 6.0 3 3.0
Dry Holes................ - - - - - -
-------- -------- --------- -------- --------- ---------
22 13.1 6 6.0 3 3.0
======== ======== ========= ======== ========= =========
Total.......................... 276 206.7 212 158.3 150 109.8
======== ======== ========= ======== ========= =========
</TABLE>
13
<PAGE>
Wells in progress as of December 31, 1999 are as follows (domestic):
<TABLE>
<CAPTION>
Type of Well Gross Net
------------------------------------------------------------------------------------ --------- ---------
<S> <C> <C>
Exploration and Production
--------------------------
Exploratory.................................................................... 8 6.3
Development.................................................................... 60 52.9
--------- ---------
Total Exploration and Production............................................... 68 59.2
========= =========
</TABLE>
There were no exploratory or development wells in progress for natural gas
systems as of December 31, 1999.
Coastal's domestic exploration and development operations are focused on
three core areas: the Texas Coastal Plain, the Gulf of Mexico and the Rocky
Mountains.
In 1999, the Texas Coastal Plain continued its significant contribution
with net average natural gas production of approximately 329 MMcf per day
compared with 220 MMcf per day in 1998. Proved reserve inventory for the area at
the end of 1999 amounted to 1,255 Bcf equivalent compared to the year end 1998
level of 1,056 Bcf equivalent. Activities on the Texas Coastal Plain focused on
two major production trends, the Wilcox trend and the Frio/Vicksburg trend.
At the end of 1999, Coastal held interests in 185 blocks and 83 platforms
in the Gulf of Mexico. Net annual average natural gas production increased to
193 MMcf per day in 1999 compared to 191 MMcf per day in 1998. The Company
operates 63 of the platforms as compared with 41 at the end of the previous
year. Proved reserve inventory for the Gulf of Mexico at the end of 1999
amounted to 804 Bcf equivalent compared to 578 Bcf equivalent as of the end of
1998.
In 1999, the Rocky Mountain region increased its contribution with net
average natural gas production of approximately 93 MMcf per day compared with 79
MMcf per day in 1998. Proved reserve equivalent inventory for the area at the
end of 1999 was 1,455 Bcf compared to 902 Bcf in 1998. Activities in the region
focus on three major production basins, Uinta, Piceance, and Douglas Arch.
In Canada, Coastal is developing and acquiring production to support its
shipping commitment on the Alliance Pipeline. At year end 1999, the Company held
interests in 108,564 gross acres (105,566 net acres), had completed 6.6
successful net gas wells and has about 78 Bcf equivalent of proved reserve
inventory. Capital expenditures for Canadian development in 1999 were
approximately $26 million.
In addition, during the course of 1999 Coastal positioned itself for
active exploration and development programs in Australia and Brazil. Activity in
Australia involves two operated leases off the continent's northern coast in the
Timor Sea. Brazilian activity was directed towards preparing for drilling on
Coastal's BAS-97 and BCAM-2 blocks, located offshore south of Salvador, and the
award of the BPAR-10 license, located onshore southeast of Sao Paulo. Drilling
operations in Brazil are planned to commence during the second quarter of 2000.
Gas and Oil Production
Natural gas production during 1999 averaged 729 MMcf daily, compared to
616 MMcf daily in 1998. Production from non-pipeline owned wells averaged 632
MMcf daily in 1999, compared to 509 MMcf daily in 1998. Crude oil, condensate
and natural gas liquids production averaged 12,326 barrels daily in 1999,
compared to 15,401 barrels daily in 1998.
14
<PAGE>
The following table shows gas, oil, condensate and natural gas liquids
production volumes attributable to Coastal's domestic interest in gas and oil
properties for the three years ended December 31, 1999:
<TABLE>
<CAPTION>
Natural Gas
Oil Condensate Liquids
Gas (Thousands (Thousands (Thousands
Year (MMcf) of Barrels) of Barrels) of Barrels)
---- ------ ----------- ----------- -----------
<S> <C> <C> <C> <C>
Exploration and Production
--------------------------
1999 230,542 2,190 1,713 572
1998 185,732 3,725 1,633 220
1997 159,127 3,425 1,224 308
Natural Gas Systems
-------------------
1999 35,634 24 - -
1998 39,058 44 - -
1997 38,135 57 - -
</TABLE>
Many of Coastal's domestic gas wells are situated in areas near, and are
connected to, its gas systems. In other areas, gas production is sold to
pipeline companies and other purchasers.
Generally, Coastal's domestic production of crude oil, condensate and
natural gas liquids is purchased at the wellhead by its marketing and refinery
affiliates. Some quantities are delivered via Coastal's gathering and
transportation lines to its refineries, but most quantities are redelivered to
Coastal through various exchange agreements.
The following table summarizes sales price and production cost information
for domestic exploration and production operations during the three years ended
December 31, 1999:
<TABLE>
<CAPTION>
1999 1998 1997
-------- -------- ---------
<S> <C> <C> <C>
Average sales price:
Gas - per Mcf................................................. $ 2.19 $ 1.95 $ 2.40
Oil - per barrel.............................................. 16.25 11.87 18.01
Condensate - per barrel....................................... 16.30 11.08 18.37
Natural Gas Liquids - per barrel.............................. 18.00 15.24 28.41
Average production cost per unit (equivalent Mcf)................ 0.40 0.41 0.49
</TABLE>
Company-Owned Reserves
Coastal's estimated domestic proved reserves of crude oil, condensate and
natural gas liquids at December 31, 1999, as estimated by the Company and
reviewed by Huddleston, the Company's independent engineers, were 57.1 million
barrels, compared to 52.3 million barrels at the end of 1998. Proved gas
reserves as of December 31, 1999, net to Coastal's interest, were estimated by
the Company and reviewed by Huddleston to be 3,466.7 Bcf compared to 2,527.1 Bcf
as of December 31, 1998. For the fifth consecutive year, Coastal added proved
reserves in 1999 that were more than triple the production volumes.
For information as to Company-owned reserves of oil and gas, see
"Supplemental Information on Oil and Gas Producing Activities (Unaudited)," as
set forth in Item 14(a)1 hereof.
15
<PAGE>
Competition
In the United States, the Company competes with major integrated oil
companies and independent oil and gas companies for suitable prospects for oil
and gas drilling operations. The availability of a ready market for gas
discovered and produced depends on numerous factors frequently beyond the
Company's control. These factors include the extent of gas discovery and
production by other producers, crude oil imports, the marketing of competitive
fuels, and the proximity, availability and capacity of gas pipelines and other
facilities for the transportation and marketing of gas. The production and sale
of oil and gas is subject to a variety of federal and state regulations,
including regulation of production levels.
Regulation
In all states in the United States in which Coastal engages in oil and gas
exploration and production, its activities are subject to regulation. Such
regulations may extend to requiring drilling permits, the spacing of wells, the
prevention of waste and pollution, the conservation of natural gas and oil, and
various other matters. Such regulations may impose restrictions on the
production of natural gas and crude oil by reducing the rate of flow from
individual wells below their actual capacity to produce. Likewise, oil and gas
operations on all federal lands are subject to regulation by the U.S. Department
of the Interior and other federal agencies.
COAL
Through the operations of Coastal Coal Company, LLC and its affiliates
(collectively "Coastal Coal") in the eastern United States, the Company produces
and markets high quality bituminous coal from reserves in Kentucky, Virginia and
West Virginia. In addition, Coastal Coal leases interests in its reserves to
unaffiliated producers and markets third-party coal through brokerage sales
operations.
At December 31, 1999, coal properties consisted of the following:
<TABLE>
<CAPTION>
Coal Holdings (Acres)
------------------------------------------------------------ Clean,
Owned Leased Recoverable
-------------------------------- Exchanged Total Tons
Fee Mineral Surface (Net) Acres (Millions)(1)
-------- ------- ------- ------------- -------- -------------
<S> <C> <C> <C> <C> <C> <C>
Kentucky......................... 14,146 76,250 2,442 28,849 121,687 214.2
Virginia......................... 24,365 36,846 2,090 16,590 79,891 162.6
West Virginia.................... 1,081 52,293 5,307 106,587 165,268 160.4
-------- --------- -------- -------- -------- -------
Total...................... 39,592 165,389 9,839 152,026 366,846 537.2
======== ========= ======== ======== ======= =======
<FN>
- ------------------------
(1) Based on a 65% recovery rate.
</FN>
</TABLE>
At December 31, 1999, the Company controlled approximately 537 million
recoverable tons of bituminous coal reserves and resources. Production in 1999
from Coastal Coal's reserves totaled 11.0 million tons, of which 7.2 million
tons were produced from captive operations and 3.8 million tons were produced by
lessees under royalty agreements. In its captive operations, Coastal Coal has 11
Company mines in Kentucky, Virginia and West Virginia which provide for the
majority of its production. Captive production and clean coal processed from
these mines totaled 4.2 million tons in 1999. The remaining production is
derived from contracts with independent mine operators to deliver coal to
Company-owned and -operated processing and loading facilities.
16
<PAGE>
Captive sales by Coastal Coal were 9.0 million tons in 1999, as compared
to 8.2 million tons in 1998. Brokerage sales in which the Company receives a
commission totaled 0.5 million tons for 1999 and 0.8 million tons for 1998.
In 1999, approximately 84% of the captive sales were to domestic
utilities, 6% of the sales were to domestic industrial customers and 10% of the
sales were to export markets in Europe and Canada. Of the total 1999 tonnage
sold, 6.7 million tons (74%) were sold under long-term contracts. At December
31, 1999, the weighted average remaining life of these contracts was 41 months.
The Company had approximately 11.6 million tons of annual production
capacity at December 31, 1999 from four coal preparation plants and six loading
facilities it owns and operates in the central Appalachian coal fields.
In addition to its bituminous coal operations, the Company controls
overriding royalty interests in approximately 416 million tons of lignite
reserves in North Dakota. Production from these reserves in 1999 totaled 8.9
million tons.
The Company, through its captive operations, leasing programs and
brokerage activities, participates in all aspects of the bituminous coal
industry. A significant portion of its reserves are low-sulfur, compliance coal
which will allow the Company to remain a major supplier of steam coal to
domestic utilities under the Clean Air Act Amendments of 1990.
Competition
The Company competes with a large number of coal producers and land
holding companies in the eastern United States. The principal factors affecting
the Company's coal sales are price, quality (BTU, sulfur and ash content),
royalty rates, employee productivity and rail freight rates.
POWER
Coastal Power Company ( "Coastal Power") and certain of its affiliates
develop, operate and own various equity interests in cogeneration and
independent power projects. The projects produce and sell electrical energy and,
in the case of cogeneration projects, thermal energy as well. Affiliates of
Coastal Power have interests in five operating domestic cogeneration projects
and 12 foreign operating independent power projects, as well as interests in
other projects in various stages of construction and development.
Capitol District Energy Center Cogeneration Associates ("CDECCA"), located
in Hartford, Connecticut, owns a combined-cycle cogeneration facility with a
capacity of approximately 56 megawatts. An affiliate of Coastal Power owns a 50%
equity interest in CDECCA and is the project manager and Coastal Technology,
Inc. ("CTI"), a Coastal subsidiary, is the operator of the plant. Electricity
from the facility is sold to a local utility under a long-term contract. Gas
supply is provided to the cogeneration plant by other Coastal affiliates.
Thermal energy from the plant is sold both to a local heating and cooling
supplier in the city of Hartford and an affiliate of the equity partner of
CDECCA.
Affiliates of Coastal Power include the managing partner and 50% ownership
of a combined-cycle cogeneration plant at Coastal's Eagle Point, New Jersey
refinery. The plant has a capacity of approximately 225 megawatts. Power from
the plant is sold to a local utility and Coastal's refinery under long-term
contracts. Steam from the plant is also sold to the refinery under a long-term
contract. Gas supply and transportation is provided to the cogeneration plant by
other Coastal affiliates. CTI is the operator of the cogeneration plant.
Fulton Cogeneration Associates, L.P. ("Fulton") leases a cogeneration
facility with a capacity of approximately 47 megawatts, located in Fulton, New
York. This partnership is 100% owned by Coastal Power and another Coastal
subsidiary. Electricity from this project is sold to a New York utility under a
long-term contract and to an affiliate of Fulton that resells into the wholesale
market. Thermal energy is sold to a local confections manufacturer adjacent to
the project, also under a long-term contract. CTI is the operator of the
cogeneration plant.
17
<PAGE>
Coastal, through direct and indirect subsidiaries, holds an equity
interest in the Midland Cogeneration Venture Limited Partnership, a
1,500-megawatt, gas-fired cogeneration project in Michigan, which is the largest
cogeneration facility in the United States. Power from the project is sold to a
local utility and the project's thermal host under long-term contracts. Steam
from the project is also sold to the thermal host and its affiliate under
long-term contracts. Coastal's affiliates provide gas supply and transportation
services for a portion of the project's fuel requirements. In January 2000,
Coastal subsidiaries acquired an additional 23.1% ownership interest in the
Midland Cogeneration project, increasing the aggregate Coastal equity interest
to 43.5%.
In March 1999, Fulton acquired the 79.6-megawatt Rensselaer
combined-cycle, cogeneration facility near Albany, New York. The facility is
natural gas fired, but is capable of utilizing No. 2 fuel oil. Electricity from
the facility is sold primarily to a New York utility under a long-term contract.
In May 1999, Fulton also acquired a 100% interest in a 265-megawatt
project in an advanced stage of development ("ManChief"). Located near Denver,
Colorado, ManChief will be a gas-fired facility and will be selling a
substantial portion of its capacity to a local utility under a long-term
contract. Construction commenced in 1999 and is expected to be completed during
the second quarter of 2000.
Compania de Electricidad de Puerto Plata, S.A. ("CEPP") owns an
independent power project in Puerto Plata, Dominican Republic. Coastal Power
International Ltd. owns a 48.3% equity interest in CEPP. Two unrelated parties
own the remaining equity in CEPP. The project has a total capacity of 66.5
megawatts of which 50 megawatts are barge mounted and 16.5 megawatts are land
based. An affiliate of Coastal Power is involved in arranging the fuel for the
project and another affiliate operates the project pursuant to a contract with
CEPP. The electrical energy is sold to the national electric utility of the
Dominican Republic under a long-term contract.
Coastal Nejapa Ltd. and other affiliates lease an independent power
project near Apopa, El Salvador. The heavy fuel oil plant has a capacity of
approximately 144 megawatts. Coastal Power, through its affiliates, currently
receives approximately 86.6% of the distributable cash flow and an unrelated
investor receives the remainder. Coastal affiliates provide fuel for this
project and another affiliate operates the project pursuant to a long-term
contract. The electrical energy is sold to the national electric utility of El
Salvador under a long-term contract.
The effective ownership interest of Coastal Power Guatemala, a wholly
owned subsidiary of Coastal Power, in Central Generadora Electrica San Jose,
Limitada ("Central Generadora") was reduced from a 46% to a 331/3% interest in
December 1999. Central Generadora constructed, owns and operates a 120-megawatt
coal-fired power plant near San Jose, Guatemala, which commenced operations in
January 2000. In the first quarter of 2000, Coastal Power Guatemala disposed of
its remaining 331/3% interest to an unrelated equity owner in the project.
In late 1997, a subsidiary of Coastal Power won the bid to develop and
operate a 50.9-megawatt (net) heavy fuel oil project in Tipitapa, Nicaragua. The
Coastal Power subsidiary owns a 60% equity interest in the project, with
Nicaraguan partners owning the remaining 40% interest. Operations commenced in
the first quarter of 1999, with power from the project being sold to the
national utility company under a long-term contract. An affiliate of Coastal
Power operates the project pursuant to a long-term contract.
In January 1999, a consortium comprised of a subsidiary of Coastal Power
and Hydro-Quebec International Inc. purchased a 49% interest in Empresa de
Generation Electrica Fortuna, S.A. ("Fortuna"), with the Coastal Power
subsidiary holding approximately 49.9% of the acquired interest in Fortuna.
Fortuna owns and operates a 300-megawatt hydroelectric plant located on the
Chiriqui River in the highlands region of Panama's Chiriqui province. The plant
began operating in 1983.
In September 1999, a consortium, including a subsidiary of Coastal Power,
acquired a 50% interest in the Itabo Generation Company ("Itabo"), with the
Coastal Power subsidiary holding a 50% interest in the acquired interest. Itabo
owns and operates several electric generating facilities in southern Dominican
Republic, aggregating over 580 megawatts of nominal generating capacity.
18
<PAGE>
Coastal Wuxi Power Ltd., an affiliate of Coastal Power, together with two
Chinese partners, formed a Sino-foreign joint venture company to own, construct,
and operate a simple-cycle, diesel-fired peaking plant. The project has a
capacity of approximately 40 megawatts and is located in Wuxi City, Province of
Jiangsu, The People's Republic of China. Coastal Wuxi Power Ltd. owns a 60%
equity interest in the joint venture. The project commenced the sale of
electrical energy in early 1996. Power generated by the plant is sold to the
local utility under a long-term contract.
Coastal Suzhou Power Ltd., a subsidiary of Coastal Power, together with a
Chinese partner, formed a Sino-foreign joint venture to develop, construct, own
and operate an independent power project. The project has a capacity of
approximately 76 megawatts and is located in Suzhou City, Province of Jiangsu,
The People's Republic of China. Coastal Suzhou Power Ltd. owns a 60% equity
interest in the joint venture. The project commenced the sale of electrical
energy in late 1996. Power generated by the plant is sold under a long-term
contract.
Coastal Gusu Heat & Power Ltd., an affiliate of Coastal Power, together
with two Chinese partners, formed a Sino-foreign joint venture to develop,
construct, own and operate a 30-megawatt cogeneration plant adjacent to the
existing Suzhou City 76-megawatt plant. Coastal Gusu Heat & Power Ltd. owns a
60% equity interest in the joint venture. The project commenced commercial
operation in November 1998. Power generated by the plant is sold to the local
utility under a long-term contract.
In December 1995, Coastal Nanjing Power Ltd., a subsidiary of Coastal
Power, together with two Chinese partners, formed a Sino-foreign joint venture
to develop, construct, own and operate an independent power project. The project
has a capacity of approximately 72 megawatts and is located in Nanjing City,
Jiangsu Province, The People's Republic of China. Coastal Nanjing Power Ltd.
owns an 80% equity interest in the joint venture. The project commenced the sale
of electrical energy in July 1997. The power is sold to the local utility under
a long-term contract.
A subsidiary of Coastal Power is currently entitled to approximately 90%
of the profits and cash flows of a 140 megawatt natural gas-fired power plant
being constructed in Quetta, Pakistan, with an unrelated entity entitled to the
remaining 10%. Commercial operations commenced in September 1999. The power from
the project is sold to a national utility under a long-term contract.
A subsidiary of Coastal Power has a financial stake of approximately 93%
of a 125-megawatt, heavy fuel oil project in Farouqabad, Pakistan. Commercial
operations commenced in December 1999 and the power from the project is sold to
a national utility under a long-term contract.
In September 1998, Coastal Power Khulna Ltd., a subsidiary of Coastal
Power, acquired an interest in a 110- megawatt, fuel oil-fired, barge-mounted
power plant located in Khulna in southwestern Bangladesh. The Coastal
subsidiary's interest is 66.7%, net of a pending commitment to sell
approximately 7% at par to an unrelated party. Commercial operation of the
Khulna project began in October 1998. The power generated by the project is
being sold to the national utility under a long-term contract.
Competition
Coastal Power and its affiliates are subject to competition with other
energy organizations and utilities seeking to develop and acquire independent
power operations. Coastal and many other power producers are concentrating their
efforts in the United States and abroad. Competition continues to increase as
the world market for independent power production develops and power purchasers
employ competitive bidding for project awards. In the United States and
international locations, the sale of power and the operation of power
cogeneration facilities are regulated by the applicable laws, rules and
regulations of the respective governments and agencies having jurisdiction. Many
states in the United States are restructuring their applicable laws, rules and
regulations. This restructuring is likely to result in new development
opportunities in the United States and increased competition in response to such
opportunities.
19
<PAGE>
COMPETITION
Coastal and its subsidiaries are subject to competition. In all the
Company's business segments, competition is based primarily on price with
factors such as reliability of supply, service and quality being considered. The
natural gas systems; refining, marketing and distribution, and chemicals;
exploration and production; coal; and power subsidiaries of Coastal are engaged
in highly competitive businesses against competitors, some of which have
significantly larger facilities and market share. See also the discussion of
competition under "Natural Gas Systems," "Refining, Marketing and Distribution,
and Chemicals," "Exploration and Production," "Coal" and "Power" herein.
ENVIRONMENTAL
The Company's operations are subject to extensive and evolving federal,
state and local environmental laws and regulations. Compliance with such laws
and regulations can be costly. Additionally, governmental authorities may
enforce the laws and regulations with a variety of civil and criminal
enforcement measures, including monetary penalties and remediation requirements.
The Company spent approximately $10 million in 1999 on environmental
capital projects and anticipates capital expenditures of approximately $36
million in 2000 in order to comply with such laws and regulations. The majority
of the 2000 expenditures is attributable to projects at the Company's refining,
chemical and terminal facilities. The Company currently anticipates capital
expenditures for environmental compliance of $20 million to $40 million per year
over the next several years.
The Comprehensive Environmental Response, Compensation and Liability Act,
also known as "Superfund," imposes liability for the release of a "hazardous
substance" into the environment. Superfund liability is imposed without regard
to fault and even if the waste disposal was in compliance with the then current
laws and regulations. With the joint and several liability imposed under
Superfund, a potentially responsible party ("PRP") may be required to pay more
than its proportional share of such costs. Certain subsidiaries of the Company
and a company in which Coastal owns a 50% interest have been named as a PRP in
various "Superfund" waste disposal sites. At the nine sites for which there is
sufficient information, total cleanup costs are estimated to be approximately
$609 million, and the Company estimates its pro-rata exposure, to be paid over a
period of years, is approximately $8 million and has made appropriate
provisions. At ten other sites, the EPA is currently unable to provide the
Company with an estimate of total cleanup costs and, accordingly, the Company is
unable to calculate its share of those costs.
Additionally, certain subsidiaries of the Company have been named as PRPs
in four state sites. At one site, the North Carolina Department of Health,
Environmental and Natural Resources has estimated the total cleanup costs to be
approximately $50 million, but the Company believes the subsidiary's activities
at this site were de minimis. At a second state site, the Florida Department of
Environmental Protection has demanded reimbursement of its costs, which total
$100,000, and suitable remediation. The Company believes the subsidiary's
activities at the Florida site were de minimis. At a third site, the owner of
the California site has estimated the total cleanup costs to be approximately
$40 million, but the Company believes the subsidiary's activities at this site
were de minimis. At the fourth site, the Texas Natural Resource Conservation
Commission has estimated the total cleanup costs to be approximately $2 million,
but the Company believes the subsidiary's activities at this site were de
minimis.
Future information and developments, including legislative and enforcement
developments, will require the Company to continually reassess the expected
impact of these environmental matters. However, the Company has evaluated its
total environmental exposure based on currently available data, including its
potential joint and several liability, and believes that compliance with all
applicable laws and regulations will not have a material adverse impact on the
Company's consolidated financial position or results of operations.
Item 2. Properties.
Information on properties of Coastal is included in Item 1, "Business"
included herein.
20
<PAGE>
The real property owned by the Company with regard to its subsidiary
pipelines is owned in fee and consists principally of sites for compressor and
metering stations and microwave and terminal facilities. With respect to the
subsidiary-owned storage fields, the Company holds title to gas storage rights
representing ownership of, or has long- term leases on, various subsurface
strata and surface rights and also holds certain additional mineral rights.
Under the NGA, the Company and its pipeline subsidiaries may acquire by the
exercise of the right of eminent domain, through proceedings in United States
District Courts or in state courts, necessary rights-of-way to construct,
operate and maintain pipelines and necessary land or other property for
compressor and other stations and equipment necessary to the operation of
pipelines.
Item 3. Legal Proceedings.
In December 1992, certain of Colorado's natural gas lessors in the West
Panhandle Field filed a complaint in the U.S. District Court, Northern District
of Texas, claiming underpayment of royalties, breach of fiduciary duty, fraud
and negligent misrepresentation. Management believes that CIG has numerous
defenses to the lessors' claims, including (i) that the royalties were properly
paid, (ii) that the majority of the claims were released by written agreement
and (iii) that the majority of the claims are barred by the statute of
limitations. In March of 1995, the trial court granted a partial summary
judgment in favor of CIG, holding that the four-year statute of limitations had
not been tolled and the releases are valid and dismissing all tort claims and
claims for breach of any duty of disclosure. The remaining claim for
underpayment of royalties was tried to a jury which, in May 1995, made findings
favorable to CIG. On June 7, 1995, the trial court entered a judgment that the
lessors recover no monetary damages from CIG and permanently estopping the
lessors from asserting any claim based on an interpretation of the contract
different than that asserted by CIG in the litigation. The lessors' motion for a
new trial was denied on July 18, 1997, and both parties filed appeals. On June
7, 1996, the same plaintiffs sued CIG in state court in Amarillo, Texas, for
underpayment of royalties. CIG removed the second lawsuit to federal court which
granted a stay of the second suit pending the outcome of the first lawsuit. Oral
arguments were heard before the Fifth Circuit Court of Appeals on December 4,
1998, and the parties are awaiting the Court's decision.
In October 1996, the Company, along with several subsidiaries, was named
as a defendant in a suit filed by several former and current African American
employees in the U.S. District Court, Southern District of Texas ("Texas suit").
The Texas suit alleges racially discriminatory employment policies and
practices. Coastal vigorously denies these allegations and has filed responsive
pleadings. Plaintiffs' counsel are seeking to have the Texas suit certified as a
class action of all former and current African American employees and initially
claimed compensatory and punitive damages of $400 million. In February 1999, in
response to Coastal's motion to deny class certification, plaintiffs' counsel
obtained permission from the Court to delete all claims for compensatory and
punitive damages and to seek equitable relief only.
In January 1998, the plaintiffs in the Texas suit amended their suit to
exclude ANR Pipeline employees from the potential class. A new suit was then
filed in state court in Wayne County, Michigan, seeking to have the Michigan
suit certified as a class action of African American employees of ANR Pipeline
and seeking unspecified damages as well as attorneys and expert fees. ANR
Pipeline has filed responsive pleadings denying these allegations. In August
1999, the court denied plaintiffs' motion to have the Michigan suit certified as
a class action. Plaintiffs filed with the Michigan Court of Appeals an
application for leave to appeal the denial of the class certification. On
November 5, 1999, the Michigan Court of Appeals denied the application for leave
to appeal.
Two legal proceedings, one in federal court and the other in state court,
have been instituted against a number of gas pipeline companies and their
affiliates, including Coastal and several of its subsidiaries. The plaintiffs in
each suit seek damages for the alleged undermeasurement of the heating value and
the volume of natural gas. In the federal proceeding, Jack Grynberg filed 77
separate False Claim Act suits in September 1997 against natural gas
transmission companies and producers, gatherers, and processors of natural gas,
seeking unspecified damages which could include treble damages for the maximum
period permitted by law (potentially as much as ten years) and penalties of up
to $10,000 per false claim. In addition to the measurement claims, these suits
also allege that the defendants undervalued the gas in paying royalties. The
Coastal defendants were sued in the U.S. District Courts of Colorado and the
Eastern District of Michigan. In April 1999, the U.S. Department of Justice
notified the Company that the United States will not intervene in these cases at
this time. The MultiDistrict Litigation Panel has consolidated the Grynberg
suits with
21
<PAGE>
several other Grynberg cases for pre-trial proceedings in Wyoming. The
defendants have filed a motion to dismiss which will be argued in March of 2000.
In the state proceedings, the Quinque Operating Company, on behalf of
itself and subclasses of gas producers, royalty owners, overriding royalty
owners, and state taxing authorities, in May 1999 instituted a legal proceeding
in State Court in Stevens County, Kansas against over 200 gas companies,
including several Coastal subsidiaries. The Quinque suit seeks unspecified
actual, punitive and treble damages for the alleged undermeasurement of all
natural gas measured in the United States from non-federal and non-Indian lands
since 1974. The plaintiffs are seeking certification of a national class of all
similarly situated gas producers, royalty owners, overriding royalty owners, and
state taxing authorities. The suit has been removed to the U.S. District Court
for the District of Kansas. The plaintiffs have filed a motion to remand the
case back to the state court, and several defendants have filed a motion under
the MultiDistrict Litigation rules to have the suit transferred to Wyoming and
consolidated with the Grynberg proceedings for pre-trial proceedings.
Numerous other lawsuits and other proceedings which have arisen in the
ordinary course of business are pending or threatened against the Company or its
subsidiaries.
Although no assurances can be given and no determination can be made at
this time as to the outcome of any particular lawsuit or proceeding, the Company
believes there are meritorious defenses to substantially all such claims and
that any liability which may finally be determined should not have a material
adverse effect on the Company's consolidated financial position or results of
operations.
Item 4. Submission of Matters to a Vote of Security Holders.
None.
22
<PAGE>
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder
Matters.
The principal market on which Coastal Common Stock is traded is the New
York Stock Exchange; Coastal Common Stock is also listed on The Stock Exchange
in London, the Stock Exchanges of Dusseldorf, Frankfurt, Hamburg and Munich in
Germany and on the Amsterdam Stock Exchange. The Class A Common Stock of Coastal
is non-transferable; however, such stock is convertible share-for-share into
Coastal Common Stock. As of February 1, 2000, the approximate number of holders
of record of Common Stock was 12,560 and of the Class A Common Stock was 2,550.
The following table presents the high and low sales prices for Coastal
common shares based on the daily composite listing of transactions for New York
Stock Exchange stocks, adjusted for the 2-for-1 stock split distributed July 1,
1998.
<TABLE>
<CAPTION>
1999 1998
----------------------------------- -------------------
Quarters High Low Dividends High Low Dividends
- -------------------- -------- ----- --------- -------- ----- ---------
<S> <C> <C> <C> <C> <C> <C>
First Quarter $37.38 $29.44 $.0625 $34.13 $26.59 $.0500
Second Quarter 43.88 32.75 .0625 38.25 32.34 .0625
Third Quarter 45.25 37.88 .0625 35.75 25.25 .0625
Fourth Quarter 42.50 31.25 .0625 38.75 30.88 .0625
</TABLE>
Coastal expects to continue paying dividends in the future. Dividends of
$.05625 per share were paid on the Class A Common Stock for each quarter of 1999
and for the last three quarters of 1998, and $.045 per share was paid for the
first quarter of 1998. At December 31, 1999, under the most restrictive of its
financing agreements, the Company was prohibited from paying dividends and
distributions on its Common Stock, Class A Common Stock and preferred stocks in
excess of approximately $781.4 million.
23
<PAGE>
Item 6. Selected Financial Data.
The following selected financial data (in millions of dollars except per
share amounts) is derived from the Consolidated Financial Statements included
herein and Item 6 of the Company's Annual Report on Form 10-K for the fiscal
year ended December 31, 1998, as adjusted for minor reclassifications. The Notes
to Consolidated Financial Statements included herein contain other information
relating to this data.
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------------------------------------------
1999 1998***** 1997 1996**** 1995
----------- -------------- ------------ ------------- ----------
<S> <C> <C> <C> <C> <C>
Operating revenues* $ 8,197.2 $ 7,368.2 $ 9,730.1 $ 12,166.9** $ 10,343.2
Earnings from continuing operations
before extraordinary items 498.9 482.9 398.7 508.0** 285.6
Net earnings 498.9 444.4 301.5 402.6** 270.4
Basic earnings per share from
continuing operations before
extraordinary items*** 2.34 2.24 1.80 2.33** 1.28
Diluted earnings per share from
continuing operations before
extraordinary items*** 2.30 2.21 1.77 2.30** 1.27
Cash dividends per common share*** .25 .2375 .20 .20 .20
Total assets 15,123.0 12,304.1 11,639.7 11,620.4 10,660.5
Debt, excluding current maturities 4,798.2 3,999.3 3,663.2 3,526.1 3,661.7
Securities of subsidiaries 750.9 400.0 100.0 100.0 .6
<FN>
* Amounts for 1997 include revenues for two months while 1995 and 1996
include twelve months of revenues from Coastal's gas marketing
operations which became a part of Engage Energy US, L.P. and Engage
Energy Canada, L.P. in February 1997 and are included in Other Income
- Net on the equity method thereafter.
** Amounts for 1996 included a gain of $272.3 million ($177 million net
of income taxes, or $.84 per share- basic, $.83 per share-diluted),
related to the sale of the Utah coal mining operations. Excluding the
gain, earnings from continuing operations before extraordinary items
for 1996 amounted to $331.0 million ($1.49 per share-basic, $1.47 per
share-diluted).
*** Adjusted for a two-for-one stock split of the Company's common stock
declared on May 7, 1998. In addition, cash dividends of $.225 per
share were paid on the Company's Class A Common Stock in 1999, $.2138
in 1998, and $.18 was paid in 1997, 1996 and 1995.
**** Effective November 1, 1996, the Company discontinued the application
of FAS 71. The accounting change resulted in a charge to earnings of
$85.6 million, net of related income taxes of $50 million, and is
shown as an extraordinary item.
***** Earnings from contining operations for 1998 include a gain of $58.6
million ($38.1 million net of income taxes, or 18 cents per share)
from the sale of certain non-core natural gas gathering and processing
assets.
</FN>
</TABLE>
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.
The Management's Discussion and Analysis of Financial Condition and
Results of Operations is presented on pages F-1 through F-11 hereof.
24
<PAGE>
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
For the information required by this item, see discussion under
Management's Discussion and Analysis of Financial Condition and Results of
Operations, which is presented on pages F-4 and F-5.
Item 8. Financial Statements and Supplementary Data.
The Financial Statements and Supplementary Data required hereunder are
included in this Annual Report as set forth in Item 14(a) hereof.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
None.
25
<PAGE>
PART III
Item 10. Directors and Executive Officers of the Registrant.
The information called for by this Item with respect to the directors is
set forth in the Coastal Proxy Statement for the Annual Meeting of Stockholders
to be filed pursuant to Regulation 14A under the Securities Exchange Act of 1934
on or before April 30, 2000, or in an amendment to this Form 10-K Annual Report,
and is incorporated herein by reference.
The executive officers of the Registrant as of February 1, 2000, were as
follows:
<TABLE>
<CAPTION>
Name (Age), Year First
Elected An Officer Positions and Offices with the Registrant
------------------------------------- -------------------------------------------
<S> <C>
David A. Arledge (55), 1982 Chairman of the Board, President and Chief Executive Officer
Coby C. Hesse (52), 1986 Senior Executive Vice President
James A. King (60), 1992 Executive Vice President
Jeffrey A. Connelly (53), 1988 Senior Vice President
Carl A. Corrallo (56), 1993 Senior Vice President and General Counsel
Rodney D. Erskine (55), 1997 Senior Vice President
Donald H. Gullquist (56), 1994 Senior Vice President
Dan J. Hill (59), 1978 Senior Vice President
Kenneth O. Johnson (79), 1978 Senior Vice President and Director
Austin M. O'Toole (64), 1974 Senior Vice President and Secretary
Keith O. Rattie (45), 1996 Senior Vice President
James L. Van Lanen (55), 1985 Senior Vice President
Thomas M. Wade (47), 1995 Senior Vice President
M. Truman Arnold (71), 1993 Vice President
Daniel F. Collins (58), 1989 Vice President
Thomas E. Jackson (60), 1997 Vice President
Jeffrey B. Levos (39), 1997 Vice President and Controller
John J. Lipinski (49), 1995 Vice President
Stirling D. Pack, Jr. (52), 1999 Vice President
M. Frank Powell (49), 1993 Vice President
Ronald D. Matthews (52), 1994 Treasurer
</TABLE>
The above named persons bear no family relationship to each other. Their
respective terms of office expire coincident with the officer elections at the
Annual Board of Directors' meeting which follows Coastal's Annual Meeting of
Stockholders. Each of the officers named above have been officers of Coastal,
ANR Pipeline and/or Colorado or subsidiaries thereof for five years or more with
the following exceptions:
Mr. Erskine was elected Senior Vice President of Coastal in August 1997.
He has held various positions with Coastal Oil & Gas Corporation, a subsidiary
of Coastal, since 1994. Before joining Coastal, Mr. Erskine was president and
chief executive officer of Nerco Oil & Gas Inc.
Mr. Levos was elected Vice President and Controller of Coastal in March
1997. He has served as Vice President of Coastal States Management Corporation,
a subsidiary of Coastal, since December 1995 and also served as General Auditor
since July 1994. Prior thereto, he was a Certified Public Accountant with the
Houston office of Deloitte & Touche LLP since January 1986.
Mr. Rattie was elected Senior Vice President of Coastal in January 2000.
He has served as a Vice President of Coastal since December 1996. Mr. Rattie has
held various positions with Coastal subsidiaries since 1995, including President
of Coastal Gas Services Company, the Coastal subsidiary responsible for
worldwide unregulated natural gas
26
<PAGE>
activities. Before joining Coastal, Mr. Rattie spent 18 years with the Chevron
Corporation. From 1991 to 1995, Mr. Rattie was General Manager, International
Gas Development with Chevron International Oil Company.
Certain information called for by this item will be set forth in the
Coastal Proxy Statement for the Annual Meeting of Stockholders to be filed
pursuant to Regulation 14A under the Securities Exchange Act of 1934 on or
before April 30, 2000, or in an amendment to this Form 10-K Annual Report, and
is incorporated herein by reference.
Item 11. Executive Compensation.
The information called for by this item will be set forth in the Coastal
Proxy Statement for the Annual Meeting of Stockholders to be filed pursuant to
Regulation 14A under the Securities Exchange Act of 1934, on or before April 30,
2000, or in an amendment to this Form 10-K Annual Report, and is incorporated
herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management.
The information called for by this item will be set forth in the Coastal
Proxy Statement for the Annual Meeting of Stockholders to be filed pursuant to
Regulation 14A under the Securities Exchange Act of 1934 on or before April 30,
2000, or in an amendment to this Form 10-K Annual Report, and is incorporated
herein by reference.
Item 13. Certain Relationships and Related Transactions.
The information called for by this item will be set forth in the Coastal
Proxy Statement for the Annual Meeting of Stockholders to be filed pursuant to
Regulation 14A under the Securities Exchange Act of 1934 on or before April 30,
2000, or in an amendment to this Form 10-K Annual Report, and is incorporated
herein by reference.
27
<PAGE>
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a) The following documents are filed as part of this Annual Report or
incorporated herein by reference:
1. Financial Statements and Supplemental Information.
The following Consolidated Financial Statements of Coastal and
Subsidiaries and Supplemental Information are included in response to
Item 8 hereof on the attached pages as indicated:
Page
----
Independent Auditors' Report.................................. F-12
Statement of Consolidated Operations for the years ended
December 31, 1999, 1998 and 1997.......................... F-13
Consolidated Balance Sheet at December 31, 1999 and 1998...... F-14
Statement of Consolidated Cash Flows for the years ended
December 31, 1999, 1998 and 1997.......................... F-16
Statement of Consolidated Common Stock and Other Stockholders'
Equity for the years ended December 31, 1999, 1998 and
1997...................................................... F-17
Notes to Consolidated Financial Statements.................... F-18
Supplemental Information on Oil and Gas Producing Activities
(Unaudited)............................................... F-43
2. Financial Statement Schedules.
The following schedules of Coastal and Subsidiaries are included
on the attached pages as indicated:
Page
----
Schedule I - Condensed Financial Information of the
Registrant................................... S-1
Schedule II - Valuation and Qualifying Accounts............ S-6
Schedules other than those referred to above are omitted as not
applicable or not required, or the required information is shown in
the Consolidated Financial Statements or Notes thereto.
3. Exhibits.
3.1+ Restated Certificate of Incorporation of Coastal, as restated
on March 22, 1994. (Filed as Module TCC-Artl-Incorp on March
28, 1994).
3.2+ By-Laws of Coastal, as amended on January 16, 1990 (Exhibit
3.4 to Coastal's Annual Report on Form 10-K for the fiscal
year ended December 31, 1989).
4 (With respect to instruments defining the rights of holders
of long-term debt, the Registrant will furnish to the
Commission, on request, any such documents).
10.1+ 1985 Stock Option Plan (Appendix A to Coastal's Proxy
Statement for the 1986 Annual Meeting of Stockholders, dated
March 27, 1986).
10.2+ The Coastal Corporation Performance Unit Plan effective as of
January 1, 1987 (Exhibit 10.5 to Coastal's Annual Report on
Form 10-K for the fiscal year ended December 31, 1987).
-------------------------
Note:
+ Indicates documents incorporated by reference from the prior
filing indicated.
28
<PAGE>
10.3+ The Coastal Corporation Replacement Pension Plan effective as
of November 1, 1987 (Exhibit 10.6 to Coastal's Annual Report
on Form 10-K for the fiscal year ended December 31, 1987).
10.4+ Description of Coastal's Key Employees Bonus Plan (Exhibit
10.7 to Coastal's Annual Report on Form 10-K for the fiscal
year ended December 31, 1987).
10.5+ The Coastal Corporation Dividend Reinvestment and Stock
Purchase Plan, dated July 9, 1996 (Exhibit 10 to Coastal's
Form S-3 filed on July 15, 1996).
10.6+ The Coastal Corporation Amended and Restated Stock Grant
Plan, effective October 9, 1997. (Exhibit 10.7 to Coastal's
Annual Report on Form 10-K for the fiscal year ended December
31, 1997.)
10.7+ The Coastal Corporation Amended and Restated Deferred
Compensation Plan for Directors, effective October 9, 1997.
(Exhibit 10.8 to Coastal's Annual Report on Form 10-K for the
fiscal year ended December 31, 1997.)
10.8+ The Coastal Corporation 1990 Stock Option Plan (Exhibit 10.13
to Coastal's Annual Report on Form 10-K for the fiscal year
ended December 31, 1989).
10.9+ The Coastal Corporation 1997 Directors Stock Plan, effective
June 5, 1997. (Exhibit 10.10 to Coastal's Annual Report on
Form 10-K for the fiscal year ended December 31, 1997.)
10.10+ The Coastal Corporation Deferred Compensation Plan (Exhibit
10.14 to Coastal's Annual Report on Form 10-K for the fiscal
year ended December 31, 1993).
10.11+ The Coastal Corporation 1994 Incentive Stock Plan (Appendix A
to Coastal's Proxy Statement for the 1994 Annual Meeting of
Stockholders dated March 29, 1994).
10.12+ Pension Plan for Employees of The Coastal Corporation as of
January 1, 1993, includes Plan as Restated as of January 1,
1989 and First Amendment dated July 27, 1992, Second
Amendment dated December 9, 1992, Third Amendment dated
October 29, 1993 (Exhibit 10.16 to Coastal's Annual Report on
Form 10-K for the fiscal year ended December 31, 1993).
10.13+ Pension Plan for Employees of The Coastal Corporation as of
January 1, 1993, as further amended by the Fourth Amendment
dated May 20, 1994, Fifth Amendment dated August 17, 1994,
Sixth Amendment dated August 30, 1994, Seventh Amendment
dated October 30, 1995, Eighth Amendment dated December 29,
1995 and Ninth Amendment dated December 29, 1995 (Exhibit
10.14 to Coastal's Annual Report on Form 10-K for the fiscal
year ended December 31, 1995).
10.14+ Pension Plan for Employees of The Coastal Corporation as of
January 1, 1993, as further amended by the Tenth Amendment
dated March 25, 1996 (Exhibit 10.15 to Coastal's Quarterly
Report on Form 10-Q for the period ended March 31, 1996).
10.15+ Pension Plan for Employees of The Coastal Corporation as of
January 1, 1993, as further amended by the Twelfth Amendment
dated August 29, 1996 and the Thirteenth Amendment dated
September 16, 1996 (Exhibit 10.16 to Coastal's Quarterly
Report on Form 10-Q for the period ended September 30, 1996).
10.16+ Pension Plan for Employees of The Coastal Corporation as of
January 1, 1993, as further amended by the Eleventh Amendment
dated December 6, 1996. (Exhibit 10.17 to Coastal's Annual
Report on Form 10-K for the fiscal year ended December 31,
1996.)
-------------------------
Note:
+ Indicates documents incorporated by reference from the prior
filing indicated.
29
<PAGE>
10.17+ Pension Plan for Employees of The Coastal Corporation as of
January 1, 1993, as further amended by the Fourteenth
Amendment dated December 31, 1997. (Exhibit 10.18 to
Coastal's Annual Report on Form 10-K for the fiscal year
ended December 31, 1997.)
10.18+ Agreement for Consulting Services between The Coastal
Corporation and Oscar S. Wyatt, Jr. dated August 1, 1997.
(Exhibit 10.19 to Coastal's Annual Report on Form 10-K for
the fiscal year ended December 31, 1997.)
10.19+ The Coastal Corporation 1998 Incentive Stock Plan, effective
March 19, 1998 (Appendix A to Coastal's Proxy Statement for
the 1998 Annual Meeting of Stockholders dated March 26,
1998).
10.20* Employment Agreement between David A. Arledge and The Coastal
Corporation dated as of April 1, 1999.
10.21* Form of employment agreement for an Employment Agreement
between The Coastal Corporation and each of Coby C. Hesse and
Gene T. Waguespack, dated January 17, 2000.
10.22* Form of employment agreement for an Employment Agreement
between The Coastal Corporation and each of James A. King,
Jeffrey A. Connelly, Carl A. Corrallo, Rodney D. Erskine,
Donald H. Gullquist, Dan J. Hill, Austin M. O'Toole, Keith O.
Rattie, James L. Van Lanen and Thomas M. Wade, dated January
17, 2000.
11* Statement re Computation of Per Share Earnings.
21* Subsidiaries of Coastal.
23* Consent of Deloitte & Touche LLP.
24* Powers of Attorney (included on signature pages herein).
27* Financial Data Schedule.
99+ Indemnity Agreement revised and updated as of April, 1988
(Exhibit 28 to Coastal's Annual Report on Form 10-K for the
fiscal year ended December 31, 1990).
-------------------------
Note:
+ Indicates documents incorporated by reference from the prior
filing indicated.
* Indicates documents filed herewith.
(b) Reports on Form 8-K.
No reports on Form 8-K were filed during the quarter ended December 31,
1999.
30
<PAGE>
POWERS OF ATTORNEY
Each person whose signature appears below hereby appoints David A.
Arledge, Coby C. Hesse and Austin M. O'Toole and each of them, any one of whom
may act without the joinder of the others, as his attorney-in-fact to sign on
his behalf and in the capacity stated below and to file all amendments to this
Annual Report on Form 10-K, which amendment or amendments may make such changes
and additions thereto as such attorney-in-fact may deem necessary or
appropriate.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
THE COASTAL CORPORATION
(Registrant)
By: DAVID A. ARLEDGE
---------------------------------------
David A. Arledge
Chairman of the Board, President and
Chief Executive Officer
February __, 2000
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
By: DAVID A. ARLEDGE
---------------------------------------
David A. Arledge
Chairman of the Board, President and
Chief Executive Officer
(Principal Executive Officer)
February __, 2000
By: COBY C. HESSE
---------------------------------------
Coby C. Hesse
Principal Accounting Officer and
Principal Financial Officer
February __, 2000
By:
---------------------------------------
John M. Bissell
Director
February __, 2000
* * *
31
<PAGE>
By: GEORGE L. BRUNDRETT, JR.
---------------------------------------
George L. Brundrett, Jr.
Director
February __, 2000
By: HAROLD BURROW
---------------------------------------
Harold Burrow
Director
February __, 2000
By: JAMES F. CORDES
---------------------------------------
James F. Cordes
Director
February __, 2000
By: ROY L. GATES
---------------------------------------
Roy L. Gates
Director
February __, 2000
By: ANTHONY W. HALL, JR.
---------------------------------------
Anthony W. Hall, Jr.
Director
February __, 2000
By: KENNETH O. JOHNSON
---------------------------------------
Kenneth O. Johnson
Director
February __, 2000
By: JEROME S. KATZIN
---------------------------------------
Jerome S. Katzin
Director
February __, 2000
By: J. CARLETON MACNEIL, JR.
---------------------------------------
J. Carleton MacNeil, Jr.
Director
February __, 2000
By: THOMAS R. McDADE
---------------------------------------
Thomas R. McDade
Director
February __, 2000
By: O. S. WYATT, JR.
---------------------------------------
O. S. Wyatt, Jr.
Director
February __, 2000
32
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
This report, including Management's Discussion and Analysis of Financial
Condition and Results of Operations, includes certain forward-looking
statements. The forward-looking statements reflect the Company's expectations,
objectives and goals with respect to future events and financial performance,
and are based on assumptions and estimates which the Company believes are
reasonable. However, actual results could differ materially from anticipated
results. Important factors which may affect the actual results include, but are
not limited to, commodity prices, political developments, market and economic
conditions, industry competition, the weather, changes in financial markets and
changing legislation and regulations. The forward-looking statements contained
in this report are intended to qualify for the safe harbor provisions of Section
21E of the Securities Exchange Act of 1934, as amended.
The Notes to Consolidated Financial Statements contain information that is
pertinent to the following analysis.
Liquidity and Capital Resources
The Company uses the following consolidated ratios to measure liquidity
and ability to meet future funding needs and debt service requirements.
<TABLE>
<CAPTION>
1999 1998 1997
-------- -------- --------
<S> <C> <C> <C>
Return on average common stockholders' equity................................ 13.5% 14.6% 13.1%
Cash flow from operating activities to long-term debt........................ 21.8% 28.7% 26.7%
Total debt to total capitalization........................................... 51.9% 52.1% 53.0%
Times interest earned (before tax)........................................... 3.1 3.2 2.7
</TABLE>
The above ratios reflect increased capitalization and debt in 1999 and
1998. The changes in the cash flow from operating activities to long-term debt
ratio resulted from changes in working capital, earnings from operations and
long- term debt.
Cash flows provided from operating activities were $1,043.8 million in
1999, $1,146.3 million in 1998 and $976.9 million in 1997. The 1999 decrease can
be primarily attributed to increases for working capital requirements. The
change in 1998 was due to increases for earnings from continuing operations
before extraordinary items and deferred income taxes.
Capital expenditures amounted to $1,780.6 million, $1,404.0 million and
$996.7 million in 1999, 1998 and 1997, respectively. The capital expenditures
for Exploration and Production were up by 15% in 1999, as the segment added
proved reserves of 1.3 trillion cubic feet of natural gas equivalent, which
amounted to a reserve replacement rate of 499 percent. Natural Gas capital
expenditures increased by 60% in 1999 due to increases for the interstate
pipelines as well as for unregulated operations. Capital expenditures for
Refining, Marketing and Chemicals decreased by 29% in 1999 primarily as a result
of the completion of certain expansion projects at the Aruba refinery. The
capital expenditures for Power increased by $151 million in 1999 due to the
purchase of the Rensselaer facility in New York and the ManChief project in
Colorado. Coal's capital expenditures were up by 88% in 1999 as the Company
continued to expand capacity and develop additional markets for its coal
reserves. The increased capital expenditures for 1998 were primarily due to
Exploration and Production, which increased spending by $360.4 million over
1997, 88% of the Company's total increase, as the continued successful programs
resulted in reserve additions which were more than three times 1998 production.
Capital expenditures for Refining, Marketing and Chemicals increased 37% in
1998, primarily due to expansion projects at the Aruba refinery. Natural Gas
capital expenditures decreased 14% in 1998 as system expansions for the
interstate pipelines were down from 1997. Capital expenditures for the Coal
segment were up 85% in 1998 as the Company continued its transformation from a
processing and marketing company using contract miners into an integrated
company that mines, processes and sells its own coal.
F-1
<PAGE>
The 1999 decrease in proceeds from the sale of property, plant and
equipment of $60.8 million and the increase in 1998 of $14.4 million resulted
primarily from the 1998 sale of certain non-core Natural Gas processing and
gathering assets. Additions to investments increased in 1999 and 1998 as a
result of the Power segment increasing its interest in existing plants,
completing new projects and pursuing opportunities in the United States and
abroad. The Natural Gas segment's additions to investments in 1999 increased by
$76.2 million as a result of investments in new and existing pipeline ventures.
Proceeds from investments decreased in 1999 and 1998 due to reductions from
Natural Gas and Refining, Marketing and Chemical ventures, respectively.
The Company increased total debt by $852.9 million in 1999 and $393.6
million in 1998. The 1999 and 1998 increases were used for capital expenditures
and additions to investments.
In February 1999, the Company completed a public offering of $200 million
of 6.375% senior debentures due 2009. The net proceeds from the sale were used
to repay floating rate indebtedness of a subsidiary under a revolving credit
facility.
In May 1999, the Company issued $200 million of 6.2% senior notes due in
2004 and $200 million of 6.5% senior notes due in 2006. The net proceeds from
the sale of the notes were used to retire $150 million of 8.75% senior notes due
May 15, 1999 and to repay floating rate indebtedness, including indebtedness of
a subsidiary under a revolving credit facility, and for general corporate
purposes.
In August 1999, the Company issued a total of 18,400,000 FELINE PRIDESSM
consisting of 17,000,000 Income PRIDES with a stated value of $25 and 1,400,000
Growth PRIDES with a stated value of $25, and also issued $35 million of 6.625%
Senior Debentures, having a principal amount of $25 and due August 16, 2004 (the
"Senior Debentures"). The Income PRIDES consist of a unit comprised of a Senior
Debenture and a purchase contract under which the holder will purchase from the
Company by no later than August 16, 2002 for $25 (the stated price) a number of
shares of the Company's common stock. The Growth PRIDES consist of a unit
comprised of a purchase contract under which the holder will purchase from the
Company by no later than August 16, 2002 for $25 (the stated price) a number of
shares of the Company's common stock and a 2.5% undivided beneficial interest in
a three-year Treasury security having a principal amount at maturity equal to
$1,000. The interest rate on the Senior Debentures is to be reset, subject to
certain limitations, effective August 16, 2002. Under the terms of the purchase
contracts, the Company will issue shares of the Company's common stock in a
number ranging from a minimum of approximately 9.9 million shares up to a
maximum of approximately 12.1 million shares, depending on the market price,
upon settlement of the purchase contract. If the market price of Coastal's
common stock is less than or equal to $38.0625, the number of shares to be
delivered will be calculated by dividing the stated price by $38.0625. If the
market price of Coastal's common stock is greater than $46.4363, the number of
shares to be delivered will be calculated by dividing the stated price by
$46.4363. If the market price is between $38.0625 and $46.4363, the number of
shares to be delivered will be calculated by dividing the stated price by the
market price. The Company received total gross proceeds of approximately $460
million before applicable expenses. The proceeds from the issuance of the FELINE
PRIDESSM and the Senior Debentures were used to repay indebtedness, including
indebtedness of subsidiaries.
In May 1999, the stockholders approved an increase in the authorized
shares of common stock from 250 million to 500 million shares.
Capital expenditures for 2000, including the Company's equity investments
in partnerships and joint ventures, are currently projected at approximately
$1.9 billion; however, future expenditures are dependent on conditions in the
energy industry. These expenditures are primarily for completion of projects in
process, operational necessities, environmental requirements, expansion projects
and increased efficiency. Other expansion opportunities will continue to be
evaluated.
Financing for budgeted expenditures and mandatory debt retirements in 2000
will be accomplished by the use of internally generated funds, existing credit
lines, proceeds from the selective sale of non-core assets and new financings.
F-2
<PAGE>
Funding for certain proposed projects is anticipated to be provided
through non-recourse project financings in which the projects' assets and
contracts will be pledged as collateral. Equity participation by other entities
will also be considered. To the extent required, cash for equity contributions
to projects will be from general corporate funds.
Unused lines of credit at December 31, 1999 were as follows (Millions of
Dollars):
Short-term...................................... $ 1,031.4
Long-term*...................................... 1,234.7
---------
$ 2,266.1
=========
* $496.3 million of unused long-term credit lines are dedicated to
specific uses.
Credit agreements of certain subsidiaries contain covenants which limit
the making of advances to affiliates and payment of dividends. Where applicable,
restrictions are generally in the form of computed capacities with respect to
advances and the payment of dividends. At December 31, 1999, net assets of
consolidated subsidiaries amounted to approximately $8.4 billion, of which
approximately $766.9 million was restricted. These provisions have not, and are
not expected to, have any meaningful impact on the ability of the Company to
meet its cash obligations.
The Financial Accounting Standard Board ("FASB") has issued Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities" ("FAS 133"), as amended by Statement of Financial
Accounting Standards No. 137 ("FAS 137"), to be effective for all fiscal
quarters of fiscal years beginning after June 15, 2000. FAS 133 requires that an
entity recognize all derivatives as either assets or liabilities in the
statement of financial position and measure those instruments at fair value. The
accounting for changes in the fair value of a derivative will depend on the
intended use of the derivative and the resulting designation. The Company is
currently evaluating the impact of FAS 133.
The Company's operations are subject to extensive and evolving federal,
state and local environmental laws and regulations. Compliance with such laws
and regulations can be costly. Additionally, governmental authorities may
enforce the laws and regulations with a variety of civil and criminal
enforcement measures, including monetary penalties and remediation requirements.
The Company spent approximately $10 million in 1999 on environmental
capital projects and anticipates capital expenditures of approximately $36
million in 2000 in order to comply with such laws and regulations. The majority
of the 2000 expenditures is attributable to projects at the Company's refining,
chemical and terminal facilities. The Company currently anticipates capital
expenditures for environmental compliance of $20 million to $40 million per year
over the next several years.
The Comprehensive Environmental Response, Compensation and Liability Act,
also known as "Superfund," imposes liability for the release of a "hazardous
substance" into the environment. Superfund liability is imposed without regard
to fault and even if the waste disposal was in compliance with the then current
laws and regulations. With the joint and several liability imposed under
Superfund, a potentially responsible party ("PRP") may be required to pay more
than its proportional share of such costs. Certain subsidiaries of the Company
and a company in which Coastal owns a 50% interest have been named as a PRP in
various "Superfund" waste disposal sites. At the nine sites for which there is
sufficient information, total cleanup costs are estimated to be approximately
$609 million, and the Company estimates its pro-rata exposure, to be paid over a
period of years, is approximately $8 million and has made appropriate
provisions. At ten other sites, the EPA is currently unable to provide the
Company with an estimate of total cleanup costs and, accordingly, the Company is
unable to calculate its share of those costs.
Additionally, certain subsidiaries of the Company have been named as PRPs
in four state sites. At one site, the North Carolina Department of Health,
Environmental and Natural Resources has estimated the total cleanup costs to be
approximately $50 million, but the Company believes the subsidiary's activities
at this site were de minimis. At a second state site, the Florida Department of
Environmental Protection has demanded reimbursement of its costs, which total
$100,000, and suitable remediation. The Company believes the subsidiary's
activities at the Florida site were de minimis. At a third site, the owner of
the California site has estimated the total cleanup costs to be approximately
$40 million, but the Company believes the subsidiary's activities at this site
were de minimis. At the fourth site, the Texas
F-3
<PAGE>
Natural Resource Conservation Commission has estimated the total cleanup costs
to be approximately $2 million, but the Company believes the subsidiary's
activities at this site were de minimis.
Future information and developments, including legislative and enforcement
developments, will require the Company to continually reassess the expected
impact of these environmental matters. However, the Company has evaluated its
total environmental exposure based on currently available data, including its
potential joint and several liability, and believes that compliance with all
applicable laws and regulations will not have a material adverse impact on the
Company's consolidated financial position or results of operations.
Market Risk Management
The Company uses fixed and variable rate debt to partially finance
budgeted expenditures and mandatory debt retirements. These agreements expose
the Company to market risk related to changes in interest rates. Derivative
financial instruments, specifically interest rate swaps, are used to reduce and
manage this risk. The Company has entered into a number of interest rate swap
agreements designated as a partial hedge of the Company's portfolio of variable
rate debt. The Company does not hold or issue financial instruments for trading
purposes.
The following table presents hypothetical changes in fair values in the
Company's debt obligations and other market sensitive financial instruments at
December 31, 1999 and 1998. The modeling technique used measures the change in
fair values arising from selected changes in interest rates. Market changes
reflect immediate hypothetical changes in interest rates at December 31. Fair
values are calculated as the net present value of the expected cash flows of the
financial instrument.
<TABLE>
<CAPTION>
Millions of Dollars No Change 10% Increase 10% Decrease
--------- ------------------------ --------------------------
Impact of changes in market Fair Fair Increase Fair Increase
rates of interest on: Value Value (Decrease) Value (Decrease)
- --------------------------------------- ----------- ----------- ---------- ----------- ----------
<S> <C> <C> <C> <C> <C> <C>
Assets
Notes receivable and marketable debt
securities
1999......................... $ 305.6 $ 298.9 $ (6.7) $ 313.1 $ 7.5
1998......................... 312.2 305.2 (7.0) 319.8 7.6
Liabilities
Long-term debt subject to fixed interest
rates
1999......................... $ 3,550.2 $ 3,410.6 $ (139.6) $ 3,702.4 $ 152.2
1998......................... 2,982.7 2,875.9 (106.8) 3,097.3 114.6
Securities of Subsidiaries
Mandatory redemption preferred
securities of a consolidated trust
1999......................... $ 276.0 $ 260.1 $ (15.9) $ 293.9 $ 17.9
1998......................... 295.6 279.2 (16.4) 313.4 17.8
</TABLE>
The Company is not subject to fair value risk resulting from changes in
market rates of interest on its portfolio of variable rate obligations,
including notes payable, long-term debt, other commitments and variable to fixed
swaps with an aggregate fair value of approximately $2,012.6 million at December
31, 1999. However, variable rate obligations do expose the Company to possible
increases in interest expense and decreases in earnings if interest rates were
to rise. If interest rates were to immediately increase by 10% from the December
31, 1999 levels and continue through 2000 assuming no changes in debt levels,
interest expense, including the effects of interest rate swaps, would increase
by approximately $11.7 million with a corresponding decrease in earnings before
taxes, as compared to an $11.4 million increase at December 31, 1998.
F-4
<PAGE>
Subsidiaries of the Company have issued preferred stocks with an aggregate
fair value of $150 million at December 31, 1999 and $100 million at December 31,
1998. These preferred stocks pay cumulative preferred dividends at variable
rates tied to market rates of interest. These stocks expose the Company to
potential decreases in earnings should interest rates increase. An immediate 10%
increase in market rates of interest, continuing through 2000, assuming no
change in outstanding shares, would decrease earnings before taxes by
approximately $0.9 million, compared to a $0.5 million decrease at December 31,
1998. Another subsidiary of the Company issued preferred stock in 1999 with a
fair value of $16.3 million at December 31, 1999 that pays cumulative preferred
dividends at 6%. A 10% change in market rates of interest would not have a
material impact on earnings before taxes related to this stock.
The limited partners of a consolidated joint venture established in 1999
are entitled to a priority return based on market rates of interest. This
limited partner interest has a fair value of $285.9 million at December 31, 1999
and exposes the Company to potential decreases in earnings should interest rates
increase. An immediate 10% increase in market rates of interest, continuing
through 2000, assuming no changes in qualifying limited partner capital, would
decrease earnings before taxes by approximately $1.7 million.
The Company also holds certain equity securities that expose the Company
to price risk associated with equity security markets. These securities are
carried at their fair value of $21.2 million at December 31, 1999. An immediate
decrease in the market prices of these securities of 10% would result in a fair
value of approximately $19.1 million, or a decrease in earnings before taxes of
approximately $2.1 million. The potential loss at December 31, 1998 was
approximately $2.3 million.
The Company also enters into swaps, futures and other contracts to hedge
exposure to price risks associated with crude oil, refined product and natural
gas inventories, commitments and certain anticipated transactions. The table
below presents the hypothetical changes in fair values arising from immediate
selected potential changes in the quoted market prices of derivative commodity
instruments outstanding at December 31, 1999 and 1998. Gain or loss on these
derivative commodity instruments would be offset by a corresponding gain or loss
on the hedged commodity positions, which are not included in the table.
Derivative commodity instruments held or issued for trading purposes are not
material at December 31, 1999.
<TABLE>
<CAPTION>
Millions of Dollars No Change 10% Increase 10% Decrease
--------- ------------------------ --------------------------
Impact of changes in commodity Fair Fair Increase Fair Increase
prices on: Value Value (Decrease) Value (Decrease)
- --------------------------------------- ----------- ----------- ---------- ----------- ----------
<S> <C> <C> <C> <C> <C>
Derivative commodity instruments
1999............................. $ 22.9 $ 7.7 $ (15.2) $ 38.1 $ 15.2
1998............................. (20.9) (25.7) (4.8) (16.1) 4.8
</TABLE>
In addition, the repayment terms of certain long-term variable rate debt
with a fair value of $264.2 million at December 31, 1999, is linked to the
quoted market price of crude oil in order to hedge inventory and certain
anticipated activity against the risk of market changes in the price of crude
oil. An immediate, hypothetical increase of 10% in the price of crude oil at
December 31, 1999 would result in an increase of $27.5 million in the fair value
of this debt, which would be offset by a corresponding increase in the fair
value of the hedged activities. The hypothetical gain in fair value at December
31, 1998 was $12.9 million. The increase in the hypothetical change is due to
the increase in oil prices in 1999.
The Company's utilization of derivative financial and commodity
instruments in managing market risk exposures described above is consistent with
the prior year.
Year 2000. The Company did not experience any significant disruptions in
its operations during the transition into the Year 2000. In the third quarter of
1999, the Company announced that it had completed necessary assessments,
modifications or replacement and testing of systems critical for the delivery of
products and services and that it believed it had met its Year 2000 readiness
objectives. The Company also prepared a contingency plan to mitigate potential
adverse effects which might have arisen from noncompliant systems or third
parties who had not adequately addressed
F-5
<PAGE>
the Year 2000 issue. Because of its preparations, the Company did not expect any
significant disruptions in its own operations. The amounts incurred and expensed
for developing and carrying out the overall Year 2000 plan totaled approximately
$18 million. While the Company did not experience any significant Year 2000
disruptions during the transition into the Year 2000, it will continue to
monitor its operations and systems and address any date-related problems that
may arise as the year progresses.
Results of Operations
The Company operates principally in the following lines of business:
natural gas; refining, marketing and chemicals; exploration and production;
power; and coal.
Natural Gas. Natural Gas operations involve the production, purchase,
gathering, storage, transportation and sale of natural gas, principally to
utilities, industrial customers and other pipelines, and include the operations
of natural gas liquids extraction plants. The operations involve both regulated
and unregulated companies. The interstate natural gas pipeline and certain
storage subsidiaries are subject to the regulations and accounting procedures of
the FERC.
The Company's interstate pipelines operate under FERC Order 636. The
intent of Order 636 is to ensure that interstate pipeline transportation
services are equal in quality for all gas supplies, whether the buyer purchases
gas from the pipeline or from any other gas supplier. The FERC requires the use
of the straight fixed variable ("SFV") rate setting methodology. In general, SFV
provides that all fixed costs of providing service to firm customers (including
an authorized return on rate base and associated taxes) are to be received
through fixed monthly reservation charges, which are not a function of volumes
transported, and provides that the pipeline's variable operating costs are
received through the commodity billing component. In addition, Order 636 has
resulted in the incurrence of transition costs. However, Order 636 provides
mechanisms for the recovery of such costs within a reasonable time period.
In September 1996, Coastal and Westcoast Energy Inc. ("Westcoast") jointly
announced plans to form one of North America's largest marketers of natural gas
and electricity through the combination of the operations of the two companies'
related marketing and service subsidiaries. Agreements were concluded in
February 1997, which created Engage Energy US, L.P. and Engage Energy Canada,
L.P. ("Engage") in which Coastal and Westcoast indirectly own 50% each.
Subsequent to the combination, Coastal's share of Engage's net earnings is
included in Other Income-Net.
<TABLE>
<CAPTION>
Millions of Dollars
-------------------------------------------
1999 1998 1997
----------- ----------- ----------
<S> <C> <C> <C>
Operating revenues.............................................. $ 1,246.9 $ 1,358.4 $ 2,166.2
Depreciation, depletion and amortization........................ 129.2 118.3 136.5
Earnings before interest and income taxes....................... 573.8 594.3 583.0
Total throughput volume (Bcf)................................... 2,109 2,132 2,190
</TABLE>
1999 Versus 1998. Operating revenues decreased by $112 million in 1999
primarily as a result of reduced transportation, storage and gathering revenues;
lower volumes of gas sales; a 1998 gain of $59 million from the sale of certain
non-core natural gas gathering and processing assets; and proceeds of $27
million in 1998 from the termination of gas transportation agreements. Revenues
of $39 million in 1998 from a rate case settlement were largely responsible for
the transportation, storage and gathering revenue decrease.
Purchases decreased by $49 million, primarily due to reduced natural gas
volumes. Gross profit decreased by $63 million in 1999 when compared to 1998.
Earnings before interest and income taxes ("EBIT") decreased by $21
million in 1999 as a result of the $59 million gain from the sale of assets
noted above, $39 million from a 1998 rate case settlement and proceeds of $27
million received from the termination of gas transportation agreements in 1998
partially offset by increased earnings from equity investments of $15 million, a
1998 provision of $18 million for environmental and other matters not recurring,
an $8 million gross profit increase from the operation of extraction plants, $32
million increased gross profit from gas sales, reduced operating expenses of $11
million, and other increases of $20 million. The increased earnings from equity
F-6
<PAGE>
method investments is primarily due to a one-time charge of $15 million in 1998
related to the default on delivery obligations by a supplier of electricity to
Engage. The other increases result primarily from recoveries of environmental
costs from prior years and increased rental income.
Demand for natural gas is expected to increase in the United States,
particularly in the Midwest and East. Coastal's strategy is to find and develop
new reserves and position our assets to move gas to these core growth markets.
1998 Versus 1997. The decrease in operating revenues of $808 million was
primarily a result of the Company's unregulated gas marketing operations which
became a part of Engage in 1997. The revenues from these operations, which were
included in the Company's revenues through February 1997, resulted in a decrease
of $833.5 million for the 1998 period. Revenues for 1997 also included a $42
million gain from an equalization payment recognized in connection with the
Engage combination. The 1998 revenues included a $59 million gain from the sale
of certain non- core natural gas processing and gathering assets. Transportation
and storage revenues decreased in 1998.
Purchases decreased by $793 million, primarily due to the combination of
the Company's unregulated natural gas marketing operations noted above. Gross
profit decreased by $15 million in 1998.
EBIT increased by $11 million as a result of the $59 million gain from the
sale of assets noted above; proceeds of $27 million received from the
termination of gas transportation agreements; $39 million from a rate case
settlement; reduced depreciation, depletion and amortization of $18 million; and
decreased operating and general expenses of $20 million partially offset by the
$42 million 1997 gain discussed above; decreased earnings from equity
investments of $12 million; reduced transportation, storage and gathering
revenues of $43 million; a decrease of $8 million from the combination of gas
marketing operations; reduced revenues of $34 million from the operation of gas
plants and sale of extracted products; and other decreases of $13 million. The
reduced transportation, storage and gathering revenues resulted from warmer than
normal weather, decreased rates and continued intensified competition across the
United States natural gas industry. Depreciation, depletion and amortization
decreased due to the revision of depreciation rates for certain assets as
discussed in Note 1 of Notes to Consolidated Financial Statements. The decreased
earnings from equity investments included a one-time charge of $15 million in
1998 related to the default on delivery obligations by a supplier of electricity
to Engage. Operating expenses decreased primarily due to reductions for gas
plant operations. The other decreases were primarily due to reduced gross profit
from gas sales.
Refining, Marketing and Chemicals. Refining, marketing and chemicals
operations involve the purchase, transportation and sale of refined products,
crude oil, condensate and natural gas liquids; the operation of refineries and
chemical plants; the sale at retail of gasoline, petroleum products and
convenience items; petroleum product terminaling and marketing of crude oil and
refined petroleum products worldwide.
<TABLE>
<CAPTION>
Millions of Dollars
-------------------------------------------
1999 1998 1997
----------- ----------- ----------
<S> <C> <C> <C>
Operating revenues.............................................. $ 6,008.1 $ 5,202.7 $ 6,877.1
Depreciation, depletion and amortization........................ 74.3 78.3 74.6
Earnings before interest and income taxes....................... 228.5 243.9 95.6
Refined product sales (millions of barrels)..................... 287 300 279
</TABLE>
1999 Versus 1998. Operating revenues increased by $805 million due to
higher prices and other increases partially offset by lower sales volumes. Sales
volumes of refined products, including products purchased from others, were down
4% from 1998.
Purchases increased by $823 million, also due to higher prices partially
offset by lower volumes, resulting in a gross profit decrease of $18 million.
Refining margins in 1999 were at a 15-year low, a result of three consecutive
warm winters, the downturn in Asian demand and the artificially tight crude
market that resulted when producers curtailed supply.
F-7
<PAGE>
The gross profit decrease of $18 million results from reduced margins of
$33 million and lower sales volumes of $27 million partially offset by increased
gross profit of $18 million from the sale, trading and exchanging of third-party
products and other increases of $24 million, primarily from recoveries of
environmental costs from prior years.
EBIT decreased by $15 million in 1999 as the decreased gross profit of $18
million and increased operating and general expenses of $20 million were
partially offset by improved earnings from equity investments of $20 million and
other increases of $3 million. Operating and general expenses increased
primarily as a result of increased throughput at the Company's refineries.
1998 Versus 1997. The decrease in operating revenues of $1,674 million was
due to reduced prices partially offset by increased volumes. Although throughput
at the companies refineries was down in 1998 due to scheduled turnarounds, sales
volumes of refined products, including products purchased from others, was up
8%.
Purchases decreased by $1,809 million, also due to reduced prices
partially offset by increased volumes, resulting in a gross profit increase of
$135 million. The reduced purchases can also be attributed to the Company's
increasing ability to use less expensive heavy and sour crudes.
The gross profit increase resulted from increased margins of $105 million;
higher sales volumes of $24 million; and an increase of $8 million from the
sale, trading and exchanging of third-party products partially offset by other
decreases of $2 million.
The EBIT increase of $148 million resulted from the increased gross profit
of $135 million and reduced operating expenses of $25 million partially offset
by increased depreciation, depletion and amortization of $4 million and reduced
earnings from equity investments of $8 million. The reduced operating expenses
resulted from reductions for the retail operations, primarily as a result of the
sale of certain stores in 1998, and the closure of certain terminal operations
in the northeastern United States in 1997.
Exploration and Production. Exploration and production operations involve
the exploration, development and production of natural gas, crude oil,
condensate and natural gas liquids.
<TABLE>
<CAPTION>
Millions of Dollars
-------------------------------------------
1999 1998 1997
----------- ----------- ----------
<S> <C> <C> <C>
Operating revenues.............................................. $ 584.0 $ 463.0 $ 490.2
Depreciation, depletion and amortization........................ 231.9 209.2 185.5
Earnings before interest and income taxes....................... 185.9 109.8 167.6
Natural gas production (MMcf per day)........................... 632 509 436
Oil, condensate and natural gas liquids production (bpd)........ 12,261 15,281 13,580
Average sales price (dollars):
Gas (per Mcf)............................................. $ 2.19 $ 1.95 $ 2.40
Oil, condensate and natural gas liquids (per barrel)...... 16.49 11.77 18.75
</TABLE>
1999 Versus 1998. Operating revenues increased by $121 million as
increased volumes and prices for natural gas and increased prices for crude oil,
condensate and natural gas liquids were partially offset by lower crude oil,
condensate and natural gas liquids volumes. Revenue increases for natural gas of
$143 million; crude oil, condensate and natural gas liquids of $8 million and
other of $1 million were partially offset by a decrease of $31 million from
hedging activities. Average daily net production of natural gas increased by 24%
over 1998 and net production of crude oil, condensate and natural gas liquids
decreased by 20% from the prior year. The natural gas volume increase results
from Coastals' ongoing successful programs in the Gulf of Mexico, Texas Coastal
Plain and the Uinta and Piceance Basins in the Rocky Mountain area.
The EBIT increase of $76 million results from increased production volumes
of $74 million; higher product prices of $77 million and other increases of $1
million partially offset by increased operating and general expenses of $22
F-8
<PAGE>
million; higher depreciation, depletion and amortization of $23 million; and the
$31 million decrease from hedging activities. The increase in operating and
general expenses is primarily a result of increased production volumes, and the
higher depreciation, depletion and amortization results from increased
production volumes partially offset by a lower rate.
For the fifth year in a row, Coastal added reserves in 1999 that were more
than triple production.
1998 Versus 1997. The decrease in operating revenues of $27 million
resulted from lower prices for all products partially offset by increased
volumes. Natural gas revenue decreases of $20 million and crude oil, condensate
and natural gas liquids revenue decreases of $27 million were partially offset
by increases of $20 million, primarily the result of hedging activities. Average
daily net production of natural gas increased by 17% over 1997 and net
production of crude oil, condensate and natural gas liquids increased by 13%
over the prior year. These volume increases resulted from Coastal's ongoing
successful programs in the Gulf of Mexico, the Texas Coastal Plain and Utah's
Uinta Basin.
The EBIT decrease of $58 million resulted from lower prices of $123
million; increased depreciation, depletion and amortization of $24 million;
operating and general expense increases of $8 million and other decreases of $3
million partially offset by higher volumes of $75 million and a $25 million
increase from hedging activities. The depreciation, depletion and amortization
increase resulted from increased production. Operating expenses were higher as a
result of increased expenses for producing wells.
Power. Power operations include the ownership of, participation in and
operation of power projects in the United States and internationally.
<TABLE>
<CAPTION>
Millions of Dollars
-------------------------------------------
1999 1998 1997
----------- ----------- ----------
<S> <C> <C> <C>
Operating revenues.............................................. $ 127.6 $ 121.1 $ 103.8
Depreciation, depletion and amortization........................ 8.5 3.2 3.1
Earnings before interest and income taxes....................... 89.0 67.8 43.4
</TABLE>
1999 Versus 1998. Operating revenues increased by $6 million in 1999 as a
result of revenues from the Rensselaer power plant ($21 million) which was
purchased in 1999 partially offset by a net benefit of $17 million in 1998 from
the restructuring of power purchase agreements for the Company's Fulton power
plant. The EBIT increase of $21 million results from the improved revenues of $6
million and increased earnings from equity investments of $31 million partially
offset by increases for operating and general expenses of $8 million;
depreciation, depletion and amortization of $5 million; and other decreases of
$3 million. The increases for operating and general expenses and depreciation,
depletion and amortization are primarily due to the Rensselaer operations.
Coastal's net generating capacity in operation on December 31, 1999, was
1,422 megawatts, up 69% from December 31, 1998. Coastal's power business
continues to pursue growth, with particular emphasis on the domestic market.
1998 Versus 1997. The increase in operating revenues of $17 million was
primarily due to a net benefit of $17 million from the restructuring of power
purchase agreements for the Company's Fulton power plant ("Plant"). The net
benefit reflected a $23 million reduction in the Plant's carrying value (to
estimated fair value following the restructuring) and deferral of certain
proceeds to cover estimated future costs. The EBIT increase of $24 million
reflected this $17 million and increased income from equity investments of $7
million. The increased equity income in 1998 can be attributed to Coastal's
successful expansion of its power operations in North America, Latin America and
Asia.
F-9
<PAGE>
Coal. Coal operations include mining, processing and marketing of coal
from Company-owned reserves and from other sources, and the brokering of coal
for others.
<TABLE>
<CAPTION>
Millions of Dollars
-------------------------------------------
1999 1998 1997
----------- ----------- ----------
<S> <C> <C> <C>
Operating revenues.............................................. $ 257.6 $ 241.7 $ 226.8
Depreciation, depletion and amortization........................ 16.8 14.6 14.1
Earnings before interest and income taxes....................... 15.8 17.4 25.3
Captive and brokered sales (millions of tons)................... 9.5 9.0 8.0
</TABLE>
1999 Versus 1998. The increase in coal revenues results primarily from
increased volumes partially offset by lower prices and a 1998 gain of $3 million
from the sale of assets. The segment experienced a 10% increase in captive
volumes sold and a 3% decrease in the average sale price per ton as compared to
1998.
EBIT decreased by $2 million in 1999 as increases for operating and
general expenses of $16 million and depreciation, depletion and amortization of
$2 million more than offset the increased revenues of $16 million. The increased
operating and general expenses, which include coal costs, are primarily due to
the increased volumes.
Coastal's coal business made significant progress in 1999 toward its goal
of expanding capacity and developing additional markets for its reserve base. It
is rapidly transforming from a niche producer to a high-volume marketer of
low-sulfur steam coal.
1998 Versus 1997. The increase in coal revenues of $15 million resulted
primarily from increased volumes and a gain of $3 million from the sale of
assets partially offset by lower prices. The segment experienced a 14% increase
in captive volumes sold and a 2% decrease in the average sale price per ton as
compared to 1997.
The EBIT decrease of $8 million in 1998 resulted from a nonrecurring
favorable resolution of a contingency in 1997 for $9 million, increased
operating and general expenses of $13 million and other decreases of $1 million
partially offset by the increased revenues of $15 million. The increased
operating and general expenses, which include coal costs, were primarily due to
the increased volumes sold.
Corporate and Other. Other operations involve real estate and corporate
income and expense not allocated to the operating segments.
<TABLE>
<CAPTION>
Millions of Dollars
-------------------------------------------
1999 1998 1997
----------- ----------- ----------
<S> <C> <C> <C>
Operating revenues.............................................. $ 15.1 $ 23.0 $ 29.4
Depreciation, depletion and amortization........................ 3.6 7.0 4.1
Loss before interest and income taxes........................... (96.9) (88.7) (70.4)
</TABLE>
1999 Versus 1998. The decrease in operating revenues of $8 million results
from the transfer of certain real estate properties to the Natural Gas segment.
The increased loss before interest and income taxes of $8 million results from
dividends on the Company-obligated mandatory redemption preferred securities of
a consolidated trust and increased expenses from financing activities partially
offset by increased income from the return on pension assets.
1998 Versus 1997. Operating revenues decreased by $6 million, primarily as
the result of the sale of certain real estate properties in 1997. The increased
loss before interest and income taxes of $18 million was attributable to
dividends on the Company-obligated mandatory redemption preferred securities of
a consolidated trust of $16 million and other of $2 million.
F-10
<PAGE>
Interest and Debt Expense
1999 Versus 1998. Interest and debt expense increased by $28 million in
1999 as the result of higher average debt partially offset by reduced average
interest rates and increased capitalized interest.
1998 Versus 1997. The interest and debt expense decrease of $13 million
resulted from reduced average interest rates, reduced interest associated with
regulatory matters and increased capitalized interest partially offset by
increases due to higher average debt.
Taxes on Income
Income taxes fluctuated as a result of changing levels of income before
taxes and changes in the effective federal income tax rate. The effective
federal income tax rates were primarily affected by the exclusions for foreign
investments and certain domestic joint ventures.
Discontinued Operations
The discontinued operations resulted from the Company's pursuing the
disposition of its 50% ownership of a joint venture trucking operation as
described in Note 12 of the Notes to Consolidated Financial Statements.
Extraordinary Item
The extraordinary item, net of income taxes, resulted from the early
retirement of debt in 1997. See Note 13 of the Notes to Consolidated Financial
Statements.
F-11
<PAGE>
INDEPENDENT AUDITORS' REPORT
Board of Directors and Stockholders
The Coastal Corporation
Houston, Texas
We have audited the accompanying consolidated balance sheets of The
Coastal Corporation and subsidiaries as of December 31, 1999 and 1998, and the
related consolidated statements of operations, common stock and other
stockholders' equity and cash flows for each of the three years in the period
ended December 31, 1999. Our audits also included the financial statement
schedules listed in the Index at Item 14(a)2. These financial statements and
financial statement schedules are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements and financial statement schedules based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards 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. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the consolidated financial position of The Coastal
Corporation and subsidiaries as of December 31, 1999 and 1998, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 1999, in conformity with generally accepted accounting
principles. Also, in our opinion, such financial statement schedules, when
considered in relation to the basic consolidated financial statements taken as a
whole, present fairly in all material respects the information set forth
therein.
DELOITTE & TOUCHE LLP
Houston, Texas
February 8, 2000
F-12
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED OPERATIONS
(Millions of Dollars Except Per Share)
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
OPERATING REVENUES.............................................. $ 8,197.2 $ 7,368.2 $ 9,730.1
----------- ----------- -----------
OPERATING COSTS AND EXPENSES
Purchases.................................................... 5,148.7 4,376.8 6,863.5
Operating and general expenses............................... 1,687.2 1,674.9 1,700.4
Depreciation, depletion and amortization..................... 479.6 443.2 433.5
----------- ----------- -----------
7,315.5 6,494.9 8,997.4
----------- ----------- -----------
OTHER INCOME - NET.............................................. 114.4 71.2 111.8
----------- ----------- -----------
EARNINGS BEFORE INTEREST AND INCOME TAXES....................... 996.1 944.5 844.5
----------- ----------- -----------
OTHER EXPENSES
Interest and debt expense.................................... 323.3 294.9 307.5
Taxes on income.............................................. 173.9 166.7 138.3
----------- ----------- -----------
EARNINGS FROM CONTINUING OPERATIONS
BEFORE EXTRAORDINARY ITEM.................................... 498.9 482.9 398.7
DISCONTINUED OPERATIONS - NET OF INCOME TAXES
Loss from operations......................................... - (3.5) (6.6)
Estimated loss on disposal................................... - (35.0) -
----------- ----------- -----------
EARNINGS BEFORE EXTRAORDINARY ITEM.............................. 498.9 444.4 392.1
EXTRAORDINARY ITEM - NET OF INCOME TAXES
Loss on early extinguishment of debt......................... - - (90.6)
----------- ----------- -----------
NET EARNINGS.................................................... 498.9 444.4 301.5
DIVIDENDS ON PREFERRED STOCK.................................... .3 6.0 17.4
----------- ----------- -----------
NET EARNINGS AVAILABLE TO COMMON
STOCKHOLDERS................................................. $ 498.6 $ 438.4 $ 284.1
=========== =========== ===========
BASIC EARNINGS PER SHARE
From continuing operations before extraordinary item......... $ 2.34 $ 2.24 $ 1.80
Discontinued operations...................................... - (.18) (.03)
Extraordinary item........................................... - - (.43)
----------- ----------- -----------
NET BASIC EARNINGS PER SHARE................................. $ 2.34 $ 2.06 $ 1.34
=========== =========== ===========
DILUTED EARNINGS PER SHARE
From continuing operations before extraordinary item......... $ 2.30 $ 2.21 $ 1.77
Discontinued operations...................................... - (.18) (.03)
Extraordinary item........................................... - - (.42)
----------- ----------- -----------
NET DILUTED EARNINGS PER SHARE............................... $ 2.30 $ 2.03 $ 1.32
=========== =========== ===========
</TABLE>
See Notes to Consolidated Financial Statements.
F-13
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Millions of Dollars)
<TABLE>
<CAPTION>
December 31,
---------------------------
1999 1998
----------- ----------
<S> <C> <C>
ASSETS
- ------
CURRENT ASSETS
Cash and cash equivalents..................................................... $ 44.4 $ 106.9
Receivables, less allowance for doubtful accounts $17.4 million (1999)
and $15.9 million (1998)................................................... 1,932.5 1,142.8
Inventories................................................................... 732.7 499.5
Prepaid expenses and other.................................................... 213.9 220.6
----------- ----------
Total current assets....................................................... 2,923.5 1,969.8
----------- ----------
PROPERTY, PLANT AND EQUIPMENT - AT COST
Natural gas systems........................................................... 6,328.7 6,069.2
Refining, crude oil and chemical facilities................................... 2,555.0 2,424.2
Gas and oil properties - at full-cost......................................... 3,832.0 2,870.8
Other......................................................................... 581.5 366.6
----------- ----------
13,297.2 11,730.8
Accumulated depreciation, depletion and amortization.......................... 3,959.8 3,706.9
----------- ----------
9,337.4 8,023.9
----------- ----------
OTHER ASSETS
Goodwill...................................................................... 451.8 470.8
Investments - equity method .................................................. 1,434.9 970.8
Other......................................................................... 975.4 868.8
----------- ----------
2,862.1 2,310.4
----------- ----------
$ 15,123.0 $ 12,304.1
=========== ==========
</TABLE>
See Notes to Consolidated Financial Statements.
F-14
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Millions of Dollars)
<TABLE>
<CAPTION>
December 31,
---------------------------
1999 1998
----------- ----------
<S> <C> <C>
LIABILITIES AND STOCKHOLDERS' EQUITY
- ------------------------------------
CURRENT LIABILITIES
Notes payable ................................................................ $ 105.9 $ 87.0
Accounts payable.............................................................. 2,350.1 1,488.0
Accrued expenses.............................................................. 420.0 305.0
Current maturities on long-term debt.......................................... 161.6 126.5
----------- ----------
Total current liabilities.................................................. 3,037.6 2,006.5
----------- ----------
DEBT
Long-term debt, excluding current maturities.................................. 4,798.2 3,999.3
----------- ----------
DEFERRED CREDITS AND OTHER
Deferred income taxes......................................................... 1,814.2 1,717.7
Other deferred credits ....................................................... 785.2 704.8
----------- ----------
2,599.4 2,422.5
----------- ----------
SECURITIES OF SUBSIDIARIES
Company-obligated mandatory redemption preferred securities of a
consolidated trust......................................................... 300.0 300.0
Preferred stock issued by subsidiaries........................................ 165.0 100.0
Consolidated joint venture.................................................... 285.9 -
----------- ----------
750.9 400.0
----------- ----------
COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY
Cumulative preferred stock (with aggregate liquidation preference
of $7.3 million) .......................................................... - -
Class A common stock - Issued (1999 - 345,019 shares;
1998 - 354,058 shares)..................................................... .1 .1
Common stock - Issued (1999 - 217,705,249 shares;
1998 - 216,764,580 shares)................................................. 72.5 72.2
Additional paid-in capital.................................................... 1,031.7 1,016.2
Retained earnings............................................................. 2,965.1 2,519.8
----------- ----------
4,069.4 3,608.3
Less common stock in treasury - at cost (1999 - 4,395,950 shares;
1998 - 4,395,654 shares).................................................. 132.5 132.5
----------- ----------
3,936.9 3,475.8
----------- ----------
$ 15,123.0 $ 12,304.1
=========== ==========
</TABLE>
See Notes to Consolidated Financial Statements.
F-15
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CASH FLOWS
(Millions of Dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------------------------
1999 1998 1997
----------- ----------- ----------
<S> <C> <C> <C>
NETCASH FLOW FROM OPERATING ACTIVITIES Earnings from continuing operations
before extraordinary
item...................................................... $ 498.9 $ 482.9 $ 398.7
Add (subtract) items not requiring (providing) cash:
Depreciation, depletion and amortization ................. 483.3 449.4 436.6
Deferred income taxes..................................... 112.1 151.7 73.9
Undistributed earnings from equity investments............ (39.3) (41.2) (43.0)
Working capital and other changes, excluding changes relating to cash and
non-operating activities:
Accounts receivable....................................... (809.2) 395.2 248.5
Inventories............................................... (119.5) 185.1 418.2
Prepaid expenses and other................................ 18.3 31.0 12.3
Accounts payable.......................................... 661.2 (573.4) (350.1)
Accrued expenses.......................................... 111.0 30.9 (56.6)
Other..................................................... 127.0 34.7 (161.6)
----------- ----------- ----------
1,043.8 1,146.3 976.9
----------- ----------- ----------
CASH FLOW FROM INVESTING ACTIVITIES
Purchases of property, plant and equipment................... (1,780.6) (1,404.0) (996.7)
Proceeds from sale of property, plant and equipment.......... 37.7 98.5 84.1
Additions to investments..................................... (379.4) (255.4) (193.8)
Proceeds from investments.................................... 9.8 59.9 71.5
Net from discontinued operations............................. (3.0) 9.3 (16.0)
----------- ----------- ----------
(2,115.5) (1,491.7) (1,050.9)
----------- ----------- ----------
CASH FLOW FROM FINANCING ACTIVITIES
Increase in short-term notes................................. 93.9 123.0 259.0
Redemption of preferred stock................................ - (200.0) -
Proceeds from issuing common stock........................... 14.7 5.5 7.3
Proceeds from long-term debt issues.......................... 1,090.8 432.2 943.4
Proceeds from issuing Company-obligated mandatory
redemption preferred securities of a consolidated trust... - 300.0 -
Proceeds from sale of interest in joint venture.............. 285.0 - -
Proceeds from issuing stock of subsidiaries.................. 65.0 - -
Payments to retire long-term debt............................ (486.6) (172.4) (1,161.8)
Dividends paid............................................... (53.6) (56.5) (59.7)
----------- ----------- ----------
1,009.2 431.8 (11.8)
----------- ----------- -----------
NET INCREASE (DECREASE) IN CASH
AND CASH EQUIVALENTS ........................................ (62.5) 86.4 (85.8)
Cash and cash equivalents at beginning of year............... 106.9 20.5 106.3
----------- ----------- ----------
Cash and cash equivalents at end of year..................... $ 44.4 $ 106.9 $ 20.5
=========== =========== ==========
</TABLE>
See Notes to Consolidated Financial Statements.
F-16
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED COMMON STOCK AND
OTHER STOCKHOLDERS' EQUITY
(Thousands of Shares and Millions of Dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------------------------------------------
1999 1998 1997
------------------- -------------------- --------------------
Shares Amount Shares Amount Shares Amount
-------- -------- -------- -------- -------- ---------
<S> <C> <C> <C> <C> <C> <C>
PREFERRED STOCK, PAR VALUE 33-1/3(cent)
PER SHARE, AUTHORIZED 50,000,000
SHARES CUMULATIVE CONVERTIBLE PREFERRED:
$1.19, Series A: Beginning balance. 56 $ - 58 $ - 60 $ -
Converted to common................ (3) - (2) - (2) -
-------- --------- ------- -------- ------- --------
Ending balance................... 53 - 56 - 58 -
======== --------- ======= -------- ======= --------
$1.83, Series B: Beginning balance. 61 - 68 - 74 -
Converted to common................ (3) - (7) - (6) -
-------- --------- ------- -------- ------- --------
Ending balance................... 58 - 61 - 68 -
======== --------- ======= -------- ======= --------
$5.00, Series C: Beginning balance. 28 - 30 - 32 -
Converted to common................ (1) - (2) - (2) -
-------- --------- ------- -------- ------- --------
Ending balance................... 27 - 28 - 30 -
======== --------- ======= -------- ======= --------
CUMULATIVE PREFERRED:
$2.125, Series H, liquidation amount
of $25 per share:
Beginning balance.................. - - 8,000 2.6 8,000 2.6
Redeemed........................... - - (8,000) (2.6) - -
-------- --------- ------- ------- ------- --------
Ending balance..................... - - - - 8,000 2.6
======== --------- ======= -------- ======= --------
CLASS A COMMON STOCK, PAR VALUE
331/3(cent)PER SHARE, AUTHORIZED
2,700,000 SHARES
Beginning balance.................. 354 .1 366 .1 382 .1
Converted to common................ (12) - (13) - (17) -
Conversion of preferred stock and
exercise of stock options.......... 3 - 1 - 1 -
-------- --------- ------- -------- ------- --------
Ending balance................... 345 .1 354 .1 366 .1
======== --------- ======= -------- ======= --------
COMMON STOCK, PAR VALUE 331/3(cent)
PER SHARE, AUTHORIZED 500,000,000
SHARES
Beginning balance.................. 216,765 72.2 110,117 36.7 109,756 36.6
Conversion of preferred stock...... 65 - 63 - 47 -
Conversion of Class A common stock. 12 - 13 - 17 -
Two-for-one stock split............ - - 106,274 35.4 - -
Exercise of stock options.......... 863 .3 298 .1 297 .1
-------- --------- ------- -------- ------- --------
Ending balance................... 217,705 72.5 216,765 72.2 110,117 36.7
======== --------- ======= -------- ======= --------
ADDITIONAL PAID-IN CAPITAL
Beginning balance.................. 1,016.2 1,243.6 1,239.6
Exercise of stock options.......... 9.0 5.4 4.0
Two-for-one stock split............ - (35.4) -
Redemption of Series H preferred
stock............................ - (197.4) -
Issuance of FELINE PRIDES(SM)...... 6.5 - -
--------- -------- --------
Ending balance................... 1,031.7 1,016.2 1,243.6
--------- -------- --------
RETAINED EARNINGS
Beginning balance ................. 2,519.8 2,131.9 1,890.1
Net earnings for period............ 498.9 444.4 301.5
Cash dividends on preferred stock.. (.3) (6.0) (17.4)
Cash dividends on Class A common
stock, 22.5(cents)(1999),
21.38(cents)(1998) and 18(cents)
(1997) per share................. (.1) (.1) (.1)
Cash dividends on common stock,
25(cents)(1999), 23.75(cents)
(1998) and 20(cents) (1997)
per share........................ (53.2) (50.4) (42.2)
-------- ------- -------
Ending balance................... 2,965.1 2,519.8 2,131.9
--------- -------- --------
LESS TREASURY STOCK - AT COST........... 4,396 132.5 4,396 132.5 4,396 132.5
======== --------- ======= -------- ======= --------
TOTAL................................... $ 3,936.9 $3,475.8 $3,282.4
========= ======== ========
</TABLE>
See Notes to Consolidated Financial Statements.
F-17
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Summary of Significant Accounting Policies
Principles of Consolidation. The consolidated financial statements include
accounts of the Company and its wholly owned subsidiaries, after eliminating all
significant intercompany transactions. The equity method of accounting is used
for investments in which the Company has a 20% to 50% voting interest and
exercises significant influence. The equity method is also used for investments
in limited partnerships in which the Company has an interest of more than 5%.
Other investments in which the Company has less than a 20% voting interest are
accounted for by the cost method.
Statement of Cash Flows. For purposes of this statement, cash equivalents
include time deposits, certificates of deposit and all highly liquid instruments
with original maturities of three months or less. Cash flows of a hedging
instrument that is accounted for as a hedge of an identifiable transaction are
classified in the same category as the cash flows from the item being hedged.
The Company made cash payments for interest and financing fees (net of amounts
capitalized) of $306.6 million, $291.6 million and $275.7 million in 1999, 1998
and 1997, respectively. Cash payments for income taxes amounted to $9.7 million,
$42.4 million and $63.6 million for 1999, 1998 and 1997, respectively.
Use of Estimates. The preparation of financial statements in conformity
with generally accepted accounting principles requires the Company to make
estimates and assumptions that affect the reported amounts of assets,
liabilities, revenues and expenses. Actual results could differ from the
estimates and assumptions used.
Inventories. Inventories of refined products and crude oil are accounted
for by the first-in, first-out cost method or market, if lower. Inventories of
natural gas are accounted for at average cost. Inventories of coal are accounted
for at average cost, or market, if lower. Inventories of materials and supplies
are accounted for at average cost.
Hedges. The Company frequently enters into swaps, futures and other
contracts to hedge the price risks associated with inventories, commitments and
certain anticipated transactions. The Company defers the impact of changes in
the market value of these contracts until such time as the hedged transaction is
completed. At that time, the impact of the changes in the fair value of these
contracts is recognized in income. The Company also enters into interest rate
and foreign currency swaps to manage interest rates and foreign currency
exchange risk. Income and expense related to interest rate swaps is accrued as
interest rates change and is recognized in income over the life of the
agreement. Such gains and losses are essentially offset by gains or losses on
the related debt.
To qualify as a hedge, the item to be hedged must expose the Company to
price, interest rate or foreign currency exchange rate risk and the hedging
instrument must reduce that exposure. Any contracts held or issued that did not
meet the requirements of a hedge would be recorded at fair value in the balance
sheet and any changes in that fair value recognized in income. If a contract
designated as a hedge of price risk or foreign currency exchange risk is
terminated, the associated gain or loss is deferred and recognized in income in
the same manner as the hedged item. Also, a contract designated as a hedge of an
anticipated transaction that is no longer likely to occur would be recorded at
fair value and the associated changes in fair value recognized in income. The
gain or loss associated with a terminated interest rate swap that has been
designated as a hedge of interest rate risk will continue to be recognized in
interest and debt expense over the life of the agreement.
Property, Plant and Equipment. Property additions include acquisition
costs, administrative costs and, where appropriate, capitalized interest
allocable to construction. Capitalized interest amounted to $41.3 million, $26.9
million and $15.5 million in 1999, 1998 and 1997, respectively. All costs
incurred in the acquisition, exploration and development of gas and oil
properties, including unproductive wells, are capitalized under the full-cost
method of accounting. Such costs include the costs of all unproved properties
and internal costs directly related to acquisition and exploration activities.
All other general and administrative costs, as well as production costs, are
expensed as incurred.
Depreciation, depletion and amortization ("DD&A") of gas and oil
properties are provided on the unit-of- production basis whereby the unit rate
for DD&A is determined by dividing the total unrecovered carrying value of gas
F-18
<PAGE>
and oil properties plus estimated future development costs by the estimated
proved reserves included therein, as estimated by Company engineers and reviewed
by independent engineers. The average amortization rate per equivalent unit of a
thousand cubic feet of gas production for oil and gas operations was $.87 for
1999, $.89 for 1998 and $.91 for 1997. Unamortized costs of proved properties
are subject to a ceiling which limits such costs to the estimated future net
cash flows from proved gas and oil properties, net of related income tax
effects, discounted at 10 percent. If the unamortized costs are greater than
this ceiling, any excess will be charged to DD&A expense. No such charge was
required in the periods presented. Provisions for depletion of coal properties,
including exploration and development costs, are based upon estimates of
recoverable reserves using the unit-of-production method. Provision for
depreciation of other property is primarily on a straight-line basis over the
estimated useful life of the properties. The annual rates of depreciation are as
follows:
Refining, crude oil and chemical facilities...... 3.0% - 20.0%
Gas systems...................................... 1.2% - 10.0%
Coal facilities.................................. 5.0% - 33.3%
Power facilities ................................ 2.9% - 33.3%
Transportation equipment......................... 4.5% - 33.3%
Office and miscellaneous equipment............... 3.0% - 33.3%
Buildings and improvements....................... 1.3% - 20.0%
Costs of minor property units (or components thereof) retired or abandoned
are charged or credited, net of salvage, to accumulated depreciation, depletion
and amortization. Gain or loss on sales of major property units is credited or
charged to income.
The Company reexamined the useful lives of certain assets of its
interstate natural gas pipelines and certain storage subsidiaries. During 1997,
the depreciation rates associated with these assets were revised, which had the
effect of increasing "Earnings from continuing operations before extraordinary
item" and "Net earnings" by $19.0 million ($.09 per share) in 1998 and $13.4
million ($.06 per share) in 1997.
Goodwill. Goodwill, which primarily relates to the acquisitions of
American Natural Resources Company ("ANR") and Colorado Interstate Gas Company
("CIG"), amounted to $451.8 million at December 31, 1999, and is being amortized
on a straight-line basis over a 40-year period. Amortization expense charged to
operations was approximately $19.0 million for 1999, 1998 and 1997,
respectively. As warranted by facts and circumstances, the Company periodically
assesses the recoverability of the cost of goodwill from future operating
income.
Income Taxes. The Company follows the liability method of accounting for
deferred income taxes as required by the provisions of Statement of Financial
Accounting Standards No. 109, "Accounting for Income Taxes."
Revenue Recognition. The Company's subsidiaries recognize revenues for the
sale of their respective products in the period of delivery. Revenues for
services are recognized in the period the services are provided.
Currency Translation. The U.S. dollar is the functional currency for
substantially all the Company's foreign operations. For those operations, all
gains and losses from currency translations are included in income currently.
Earnings Per Share. Basic earnings per common share amounts are calculated
using the average number of common and Class A common shares outstanding during
each period. Diluted earnings per share assumes conversion of dilutive
convertible preferred stocks and exercise of all stock options having exercise
prices less than the average market price of the common stock using the treasury
stock method.
Basic and diluted earnings per share amounts and average shares entering
into the computation for 1998 and 1997 reflect the two-for-one stock split of
the Company's common stock declared on May 7, 1998.
Emerging Issues Task Force Issue No. 98-10. The Company adopted Financial
Accounting Standards Board ("FASB") Emerging Issues Task Force Issue No. 98-10,
"Accounting for Contracts in Energy Trading and Risk
F-19
<PAGE>
Management Activities," in 1999. The application of Issue 98-10 did not have a
material effect on the Company's consolidated financial statements.
Statement of Position 98-5 ("SOP 98-5"). The Company adopted the
Accounting Standards Executive Committee of the American Institute of Certified
Public Accountants' SOP 98-5, "Reporting on the Costs of Start-Up Activities,"
in 1999. The application of SOP 98-5 did not have a material effect on the
Company's consolidated financial statements.
Statement of Financial Accounting Standards No. 133, "Accounting for
Derivative Instruments and Hedging Activities" ("FAS 133"). The FASB has issued
FAS 133, as amended by Statement of Financial Accounting Standards No. 137, to
be effective for all fiscal quarters of fiscal years beginning after June 15,
2000. FAS 133 requires that an entity recognize all derivatives as either assets
or liabilities in the statement of financial position and measure those
instruments at fair value. The accounting for changes in the fair value of a
derivative will depend on the intended use of the derivative and the resulting
designation. The Company is currently evaluating the impact of FAS 133.
Euro Conversion. In January 1999, certain countries of the European Union
adopted the Euro as their legal common currency. This conversion to the Euro did
not have a material effect on the Company's consolidated results of operations,
financial position or cash flows as the Company does not have significant
European operations.
Reclassification of Prior Period Statements. Certain minor
reclassifications have been made to conform with current reporting practices.
The effect of the reclassifications was not material to the Company's
consolidated results of operations, financial position or cash flows.
Note 2. Inventories
Inventories at December 31 were (Millions of Dollars):
<TABLE>
<CAPTION>
1999 1998
----------- ----------
<S> <C> <C>
Refined products, crude oil and chemicals.................................. $ 576.2 $ 306.9
Natural gas in underground storage......................................... - 32.0
Coal, materials and supplies............................................... 156.5 160.6
----------- ----------
$ 732.7 $ 499.5
=========== ==========
</TABLE>
Elements included in inventory cost are material, labor and manufacturing
expenses.
Note 3. Investments
The Company has interests in corporations and partnerships which are
accounted for on an equity basis. These investments, included in Other Assets,
are Great Lakes Gas Transmission Limited Partnership (50% interest), which
operates an interstate pipeline system; Engage Energy US, L.P. and Engage Energy
Canada, L.P. ("Engage") (50% interest), which market natural gas and
electricity; Iroquois Gas Pipeline System, L.P. (16% interest), which operates a
natural gas pipeline; Empire State Pipeline (50% interest), which operates a
natural gas pipeline; Javelina Company (40% interest), which operates a gas
processing plant in Corpus Christi, Texas; Eagle Point Cogeneration Partnership
(50% interest), which operates a cogeneration facility in New Jersey; Alliance
Pipeline Limited Partnership (14.4% interest), which is constructing a 1,900
mile pipeline; Midland Cogeneration Venture (43.5% interest), which operates a
cogeneration plant in Michigan; and several pipeline, power and other ventures.
The Company's investment in these entities, including advances, amounted to
$1,434.9 million and $970.8 million at December 31, 1999 and 1998, respectively.
The Company's equity in income of the investments, included in Other Income-Net,
was $190.4 million, $124.3 million and $137.5 million in 1999, 1998 and 1997,
respectively, while dividends and partnership distributions received amounted to
$151.1 million, $83.1 million and $94.5 million in 1999, 1998 and 1997,
respectively.
F-20
<PAGE>
Summarized financial information of these entities is as follows (Millions
of Dollars):
<TABLE>
<CAPTION>
December 31,
---------------------------
1999 1998
----------- ----------
<S> <C> <C>
Current assets............................................................. $ 2,095.3 $ 1,388.2
Noncurrent assets.......................................................... 7,338.7 5,948.8
----------- ----------
$ 9,434.0 $ 7,337.0
=========== ==========
Current liabilities........................................................ $ 1,673.1 $ 1,093.1
Noncurrent liabilities..................................................... 4,088.8 3,348.2
Deferred credits........................................................... 456.1 225.0
Equity..................................................................... 3,216.0 2,670.7
----------- ----------
$ 9,434.0 $ 7,337.0
=========== ==========
</TABLE>
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
Revenues ................................................ $ 7,271.4 $ 7,631.4 $ 5,302.1
Operating income.......................................... 661.1 563.2 627.5
Net income................................................ 494.8 306.5 353.4
</TABLE>
F-21
<PAGE>
Note 4. Debt
Long-Term Debt - Balances at December 31 were (Millions of Dollars):
<TABLE>
<CAPTION>
1999 1998
----------- ----------
<S> <C> <C>
The Coastal Corporation:
Notes payable (revolving credit agreements)................................ $ 50.0 $ 125.0
Senior notes:
10.375%, due 2000....................................................... 121.3 121.3
10%, due 2001........................................................... 84.0 84.0
8.75%, due 1999......................................................... - 150.0
8.125%, due 2002........................................................ 249.8 249.7
6.2%, due 2004.......................................................... 199.8 -
6.5%, due 2006.......................................................... 199.6 -
Senior debentures:
10.25%, due 2004........................................................ 37.7 37.7
10.75%, due 2010........................................................ 56.5 56.4
9.75%, due 2003......................................................... 102.1 102.1
9.625%, due 2012........................................................ 149.4 149.3
7.75%, due 2035......................................................... 149.9 149.9
7.42%, due 2037......................................................... 200.0 200.0
6.7%, due 2027.......................................................... 200.0 200.0
6.5%, due 2008.......................................................... 199.8 199.8
6.95%, due 2028......................................................... 199.4 199.4
6.375%, due 2009........................................................ 199.5 -
6.625% with FELINE PRIDES(SM), due 2004................................. 454.0 -
----------- ----------
2,852.8 2,024.6
----------- ----------
Subsidiary companies:
Notes payable (term credit facilities)..................................... 354.7 184.3
Notes payable (revolving credit agreements)................................ 379.0 609.0
Notes payable (project financings), due 2006-2011.......................... 53.8 59.6
Debentures, 6.85% to 10%, due 2005-2037.................................... 777.5 777.5
Other, due 2003-2028....................................................... 67.0 70.8
----------- ----------
1,632.0 1,701.2
----------- ----------
Amount reclassified from short-term debt................................... 475.0 400.0
----------- ----------
Total long-term debt....................................................... 4,959.8 4,125.8
Less current maturities.................................................... 161.6 126.5
----------- ----------
$ 4,798.2 $ 3,999.3
=========== ==========
</TABLE>
At December 31, 1999, amounts available under long-term credit agreements
with banks totaled $2,018.4 million, including $85.0 million available to The
Coastal Corporation. Loans under these agreements bear interest at money
market-related rates (weighted average 6.46% at December 31, 1999). Annual
commitment fees range up to .30% payable on the unused portion of the applicable
facility. At December 31, 1999, $783.7 million was outstanding and $496.3
million of the unused amount was dedicated to specific uses.
The subsidiary project financing notes bear interest at money
market-related rates.
In February 1999, the Company completed a public offering of $200 million
of 6.375% senior debentures due 2009. The net proceeds from the sale were used
to repay floating rate indebtedness of a subsidiary under a revolving credit
facility.
F-22
<PAGE>
In May 1999, the Company issued $200 million of 6.2% senior notes due in
2004 and $200 million of 6.5% senior notes due in 2006. The net proceeds from
the sale of the notes were used to retire $150 million of 8.75% senior notes due
May 15, 1999 and to repay floating rate indebtedness, including indebtedness of
a subsidiary under a revolving credit facility, and for general corporate
purposes.
In August 1999, the Company issued a total of 18,400,000 FELINE PRIDESSM
consisting of 17,000,000 Income PRIDES with a stated value of $25 and 1,400,000
Growth PRIDES with a stated value of $25, and also issued $35 million of 6.625%
Senior Debentures, having a principal amount of $25 and due August 16, 2004 (the
"Senior Debentures"). The Income PRIDES consist of a unit comprised of a Senior
Debenture and a purchase contract under which the holder will purchase from the
Company by no later than August 16, 2002 for $25 (the stated price) a number of
shares of the Company's common stock. The Growth PRIDES consist of a unit
comprised of a purchase contract under which the holder will purchase from the
Company by no later than August 16, 2002 for $25 (the stated price) a number of
shares of the Company's common stock and a 2.5% undivided beneficial interest in
a three-year Treasury security having a principal amount at maturity equal to
$1,000. The interest rate on the Senior Debentures is to be reset, subject to
certain limitations, effective August 16, 2002. Under the terms of the purchase
contracts, the Company will issue shares of the Company's common stock in a
number ranging from a minimum of approximately 9.9 million shares up to a
maximum of approximately 12.1 million shares, depending on the market price,
upon settlement of the purchase contracts. If the market price of Coastal's
common stock is less than or equal to $38.0625, the number of shares to be
delivered will be calculated by dividing the stated price by $38.0625. If the
market price of Coastal's common stock is greater than $46.4363, the number of
shares to be delivered will be calculated by dividing the stated price by
$46.4363. If the market price is between $38.0625 and $46.4363, the number of
shares to be delivered will be calculated by dividing the stated price by the
market price. The Company received total gross proceeds of approximately $460
million before applicable expenses. The proceeds from the issuance of the FELINE
PRIDESSM and the Senior Debentures were used to repay indebtedness, including
indebtedness of subsidiaries.
Various agreements contain restrictive covenants which, among other
things, limit dividends by certain subsidiaries and additional indebtedness of
certain subsidiaries. At December 31, 1999, net assets of consolidated
subsidiaries amounted to approximately $8.4 billion, of which $766.9 million was
restricted by such provisions.
Maturities. The aggregate amounts of long-term debt maturities for the
five years following 1999 are (Millions of Dollars):
2000 $161.6 2003 $123.4
2001 $596.9 2004 $705.6
2002 $469.6
Notes Payable. At December 31, 1999, Coastal and its subsidiaries had
$580.9 million of outstanding indebtedness under the Company's commercial paper
program and indebtedness to banks under short-term lines of credit, compared to
$487.0 million at December 31, 1998. As of December 31, 1999, the Company's
financial statements reflected $475.0 million of short-term borrowings which had
been reclassified as long-term, based on the availability of committed credit
lines with maturities in excess of one year and the Company's intent to maintain
such amounts as long-term borrowings. There was a similar reclassification of
$400.0 million as of December 31, 1998. The weighted average interest rates were
6.63% and 6.07% at December 31, 1999 and 1998, respectively. As of December 31,
1999, $1,031.4 million was available to be drawn under short-term credit lines.
Restrictions on Payment of Dividends. Under the terms of the most
restrictive of the Company's financing agreements, approximately $781.4 million
of retained earnings was available at December 31, 1999, for payment of
dividends on the Company's common and preferred stocks.
Guarantees. Coastal and certain subsidiaries have guaranteed specific
obligations of several unconsolidated affiliates. Affiliates are generally not
required to collateralize their contingent liabilities to the Company. At
December 31, 1999, the Company had guaranteed a construction financing of a
partially owned partnership. The Company's proportionate share of the
outstanding principal balance under this guarantee was $92.5 million at December
31, 1999. This loan is expected to be refinanced on a non-recourse basis. The
Company and a partner have issued a number of
F-23
<PAGE>
guarantees related to the operations of Engage. Pursuant to an equalization
agreement with the partner, each party has agreed to reimburse the other in the
event there are disproportionate payments under their respective guarantees. As
of December 31, 1999, the Company's share of such guarantees was $668.6 million;
the actual liabilities related to these guarantees was $144.8 million. Other
guarantees and indemnities related to obligations of unconsolidated affiliates
amounted to approximately $104.4 million as of December 31, 1999. The Company is
of the opinion that its unconsolidated affiliates will be able to perform under
their respective financings and other obligations and that no payments will be
required and no losses will be incurred under such guarantees and indemnities.
Note 5. Leases and Commitments
The Company leases property, plant and equipment under various operating
leases, certain of which contain renewal and purchase options and residual value
guarantees. Such residual value guarantees amount to approximately $517.3
million. Rental expense amounted to approximately $120.3 million, $86.0 million
and $95.3 million in 1999, 1998 and 1997, respectively, excluding leases
covering natural resources. Aggregate minimum lease payments under existing
noncapitalized long-term leases are estimated to be $124.4 million, $114.9
million, $100.1 million, $99.5 million, and $98.6 million for the years
2000-2004, respectively, and $677.5 million thereafter.
Note 6. Securities of Subsidiaries
Company-Obligated Mandatory Redemption Preferred Securities of a
Consolidated Trust. On May 13, 1998, Coastal completed a public offering of
12,000,000 Coastal-obligated mandatory redemption preferred securities through
an affiliate, Coastal Finance I, a business trust (the "Trust"), for $300
million in cash. The Trust holds debt securities of Coastal purchased with the
proceeds of the preferred securities offering. Cumulative quarterly
distributions are being paid on the preferred securities at an annual rate of
8.375% of the liquidation amount of $25 per preferred security. The preferred
securities are mandatorily redeemable on the maturity date, May 13, 2038, and
may be redeemed at the Company's option on or after May 13, 2003, or earlier if
certain events occur. The redemption price to be paid is $25 per preferred
security, plus accrued and unpaid distributions to the date of redemption.
Preferred Stock of Subsidiaries. Coastal Securities Company Limited
("Coastal Securities"), a wholly owned subsidiary, issued 4,000,000 shares of
preferred stock in 1996 for $100 million in cash. Quarterly cash dividends are
being paid on the preferred stock at a rate based on the London Interbank
Offered Rate ("LIBOR"). The preferred shareholders are also entitled to
participating dividends based on certain refining margins. Coastal Securities
may redeem the preferred stock on or after December 31, 1999 for cash. Also, on
or after December 31, 1999 but prior to December 31, 2000, Coastal Securities
may elect to redeem the preferred stock by issuing unsecured convertible
debentures.
In 1999, Coastal Oil and Gas Resources, Inc. ("COGR"), a wholly owned
subsidiary, issued 50,000 shares of preferred stock for $50 million in cash. The
preferred shareholders are entitled to quarterly cash dividends at a rate based
on LIBOR. The dividend rate is subject to renegotiation in 2004 and on each
fifth anniversary thereafter. In the event COGR and the preferred shareholders
are unable to agree to a new rate, COGR must redeem the shares at $1,000 per
share plus any accrued and unpaid dividends, or cause the preferred stock to be
registered with the Securities and Exchange Commission and remarketed. COGR also
has the option to redeem all shares on any dividend rate reset date for $1,000
per share plus any accrued and unpaid preferred dividends.
In 1999, Coastal Limited Ventures, Inc. ("CLVI"), a wholly owned
subsidiary, issued 150,000 shares of preferred stock for $15 million in cash.
The preferred shareholders are entitled to quarterly cash dividends at an annual
rate of 6%. The dividend rate is subject to renegotiation in 2004 and on each
fifth anniversary thereafter. In the event CLVI and the preferred shareholders
are unable to agree to a new rate, the preferred shareholders may call for
redemption of all of the preferred shares. The redemption price is $100 per
share plus any accrued and unpaid preferred dividends thereon. CLVI also has the
option to redeem all shares on any rate reset date for $100 per share plus any
accrued and unpaid preferred dividends.
Consolidated Joint Venture. In December 1999, CLVI contributed certain
assets to a limited partnership in exchange for a controlling general
partnership interest. Limited interests in the partnership were issued to
unaffiliated
F-24
<PAGE>
investors for $285 million in cash. The limited partners are entitled to a
cumulative priority return based on LIBOR. The return is subject to
renegotiation in 2004 and on each fifth anniversary thereafter. The partnership
has a maximum life of 20 years, but may be terminated sooner subject to certain
conditions, including failure to agree to a new rate. CLVI may terminate the
partnership at any time by repayment of the limited partners' outstanding
capital plus any unpaid priority returns.
Note 7. Financial Instruments and Risk Management
The Company's operations involve managing market risks related to changes
in interest rates, foreign exchange rates and commodity prices. Derivative
financial instruments, specifically swaps and other contracts, are used to
reduce and manage those risks. The Company does not currently hold or issue
financial instruments for trading purposes.
Interest Rate Swaps. The Company has entered into a number of interest
rate swap agreements designated as a partial hedge of the Company's portfolio of
variable rate debt. The purpose of these swaps is to fix interest rates on
variable rate debt and reduce certain exposures to interest rate fluctuations.
At December 31, 1999, the Company had interest rate swaps with a notional amount
of $18.2 million, and a portfolio of variable rate debt outstanding in the
amount of $1,469.2 million. Under these agreements, Coastal will pay the
counterparties interest at a weighted average fixed rate of 6.78%, and the
counterparties will pay Coastal interest at a variable rate equal to LIBOR or
other market rates. The weighted average rate applicable to these agreements was
5.29% at December 31, 1999. The notional amounts do not represent amounts
exchanged by the parties, and thus are not a measure of exposure of the Company.
The amounts exchanged are normally based on the notional amounts and other terms
of the swaps. The weighted average variable rates are subject to change over
time as market rates fluctuate. Terms expire at various dates through the year
2011.
Neither the Company nor the counterparties, which are prominent bank
institutions, are required to collateralize their respective obligations under
these swaps. Coastal is exposed to loss if one or more of the counterparties
default. At December 31, 1999, Coastal had no exposure to credit loss on
interest rate swaps. The Company does not believe that any reasonably likely
change in interest rates would have a material adverse effect on the financial
position, the results of operations or cash flows of the Company. All interest
rate and currency swaps are reviewed with, and when necessary, are approved by
the Company's Board of Directors.
Other Derivatives. The Company and its subsidiaries also frequently enter
into swaps and other contracts to hedge the price risks associated with
inventories, commitments and certain anticipated transactions. The swaps and
other contracts are with established energy companies and major financial
institutions. The Company believes its credit risk is minimal on these
transactions, as the counterparties are required to meet stringent credit
standards. There is continuous day-to-day involvement by senior management in
the hedging decisions, operating under resolutions adopted by each subsidiary's
board of directors.
F-25
<PAGE>
Fair Value of Financial Instruments. The estimated fair value amounts of
the Company's financial instruments have been determined by the Company, using
appropriate market information and valuation methodologies. Considerable
judgment is required to develop the estimates of fair value, thus, the estimates
provided herein are not necessarily indicative of the amounts that the Company
could realize in a current market exchange.
<TABLE>
<CAPTION>
(Millions of Dollars)
------------------------------------------------------------
Dec. 31, 1999 Dec. 31, 1998
---------------------------- -----------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
---------- ----------- ----------- ------------
<S> <C> <C> <C> <C>
Nonderivatives:
Financial assets:
Cash and cash equivalents..................... $ 44.4 $ 44.4 $ 106.9 $ 106.9
Notes receivable.............................. 259.0 270.6 248.1 271.3
Investments................................... 68.0 68.0 64.0 64.0
Financial liabilities:
Short-term debt............................... 105.9 105.9 87.0 87.0
Long-term debt ............................... 4,959.8 4,907.0 4,125.8 4,423.0
Company-obligated mandatory redemption
preferred securities of a consolidated trust.. 300.0 276.0 300.0 295.6
Preferred stock - issued by subsidiaries........ 165.0 166.3 100.0 100.0
Limited partnership interests in consolidated
joint venture................................. 285.9 285.9 - -
Derivatives relating to:
Commodity swaps gain (loss)..................... - (4.8) - 6.4
Interest rate swaps gain (loss) ................ - .4 - (1.7)
</TABLE>
The estimated values of the Company's notes receivable, long-term debt,
Company-obligated mandatory redemption preferred securities of a consolidated
trust, preferred stock - issued by subsidiaries and limited partnership
interests in consolidated joint venture are based on interest rates at December
31, 1999 and 1998, respectively, for new issues with similar remaining
maturities. The fair value of investments are based on market prices at December
31, 1999 and 1998, respectively. The fair value of the derivatives related to
commodity swaps are derived from quoted market prices at December 31, 1999 and
1998, respectively. The fair market value of the Company's interest rate swaps
is based on the estimated termination values at December 31, 1999 and 1998,
respectively.
Note 8. Common and Preferred Stock
On April 15, 1998, the Company redeemed all 8,000,000 outstanding shares
of its $2.125 Cumulative Preferred Stock, Series H. Redemption price for the
Series H stock was $25 per share plus accrued dividends of $.182986 to April 15,
1998.
Executives, directors and other key employees have been granted options to
purchase common shares under stock option plans adopted in 1990, 1994, 1996,
1997 and 1998. Under each plan, the option price equals the fair market value of
the common shares on the date of grant. Options vest cumulatively at rates
ranging from 15% to 33 1/3% of the option shares on each anniversary date of the
date of grant beginning with the first or second anniversary. The options, which
expire either five years or ten years from the grant date, do not carry any
stock appreciation rights.
F-26
<PAGE>
The following table presents a summary of stock options transactions for
the three years ended December 31, 1999:
<TABLE>
<CAPTION>
Class A Average
Common Common Option Price
Shares Shares Per Share
------------ ----------- --------------
<S> <C> <C> <C>
December 31, 1996........................................... 4,469,050 2,280 $ 15.49
Granted.................................................. 1,567,112 - 23.60
Exercised................................................ (589,930) - 13.72
Revoked or expired....................................... (235,202) - 16.26
------------ ----------- --------------
December 31, 1997........................................... 5,211,030 2,280 18.12
Granted.................................................. 2,080,349 - 32.72
Exercised................................................ (466,812) - 16.15
Revoked or expired....................................... (222,230) - 23.84
----------- ----------- --------------
December 31, 1998........................................... 6,602,337 2,280 22.64
Granted.................................................. 1,809,068 - 32.93
Exercised................................................ (863,408) (2,280) 17.23
Revoked or expired....................................... (434,288) - 26.52
----------- ----------- --------------
December 31, 1999........................................... 7,113,709 - $ 25.68
=========== =========== ==============
</TABLE>
In accordance with the provisions of Statement of Financial Accounting
Standards No. 123, "Accounting for Stock-Based Compensation" ("FAS 123"), the
Company applies APB Opinion 25 in accounting for its stock option plans and,
accordingly, does not recognize compensation cost for options granted to
executives and other key employees. If the Company had elected to recognize
compensation cost based on the fair value of the options granted at grant date
as prescribed by FAS 123, earnings from continuing operations before
extraordinary item, net earnings and earnings per share would have been reduced
to the pro forma amounts shown in the table below (in Millions Except Per Share
Amounts):
<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------------------------
1999 1998 1997
----------- ----------- ----------
<S> <C> <C> <C>
Earnings from continuing operations before
extraordinary item..................................... $ 486.8 $ 473.8 $ 394.4
Net earnings.............................................. 486.8 435.3 297.2
Basic earnings per share
From continuing operations before
extraordinary item................................... $ 2.28 $ 2.20 $ 1.78
Discontinued operations................................ - (.18) (.03)
Extraordinary item..................................... - - (.43)
----------- ----------- ----------
Net basic earnings per share........................... $ 2.28 $ 2.02 $ 1.32
=========== =========== ==========
Diluted earnings per share
From continuing operations before
extraordinary item................................... $ 2.24 $ 2.17 $ 1.75
Discontinued operations................................ - (.18) (.03)
Extraordinary item..................................... - - (.42)
----------- ----------- ----------
Net diluted earnings per share......................... $ 2.24 $ 1.99 $ 1.30
=========== =========== ==========
</TABLE>
The effects of applying FAS 123 in this pro forma disclosure are not
indicative of future amounts.
F-27
<PAGE>
The fair value of each option grant is estimated on the date of grant
using the Black-Scholes option-pricing model with the following assumptions used
for grants in 1999, 1998 and 1997:
<TABLE>
<CAPTION>
1999 1998 1997
----------- ----------- ----------
<S> <C> <C> <C>
Risk free interest rate................................... 5.17% 5.57% 6.90%
Expected life (years)..................................... 8 8 8
Expected dividend yield................................... .81% .611% .85%
Expected volatility....................................... .3583 .2241 .2205
Weighted average fair value of options granted (per share) $ 15.22 $ 12.77 $ 9.75
</TABLE>
Stock options available for future grants amounted to 5,478,587;
6,856,789; and 493,642 at December 31, 1999, 1998 and 1997, respectively.
Exercisable stock options amounted to 1,983,595; 1,706,453; and 1,353,198, at
December 31, 1999, 1998 and 1997, respectively.
The following table summarizes information about stock options outstanding
and exercisable at December 31, 1999:
<TABLE>
<CAPTION>
Outstanding Exercisable
------------------------------------- -------------------------
Average Average
Exercise Average Exercise Exercise
Price Range Shares Life (*) Price Shares Price
----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
$10.46 - $18.28........................ 2,338,018 4.9 $ 15.93 1,337,138 $ 15.20
23.53 - 29.82........................ 1,236,058 7.1 23.63 384,336 23.69
30.74 - 43.34........................ 3,539,633 8.6 32.84 262,121 32.88
----------- -----------
7,113,709 1,983,595
=========== ===========
<FN>
* Average life remaining in years.
</FN>
</TABLE>
Note 9. Segment and Geographic Reporting
The Company operates principally in the following lines of business:
natural gas; refining, marketing and chemicals; exploration and production;
power; and coal. Separate management of each segment is required because each
line of business is subject to different production, marketing and technology
strategies.
Natural gas operations involve the production, purchase, gathering,
storage, transportation, marketing and sale of natural gas, principally to
utilities, industrial customers and other pipelines, and include the operation
of natural gas liquids extraction plants. Sales are primarily made to pipeline
and distribution companies in most major areas of the United States.
Refining, marketing and chemicals operations involve the purchase,
transportation and sale of refined products, crude oil, condensate and natural
gas liquids; the operation of refineries and chemical plants; the sale at retail
of gasoline, petroleum products and convenience items; petroleum product
terminaling and marketing of crude oil and refined petroleum products. Products
from this segment are sold to customers worldwide.
Exploration and production operations involve the exploration, development
and production of natural gas, crude oil, condensate and natural gas liquids.
Sales are made to affiliated companies, industrial users, interstate pipelines
and distribution companies in the Rocky Mountain, central and southwest areas of
the United States and offshore Gulf of Mexico.
F-28
<PAGE>
Power operations involve the ownership of, participation in and operation
of power projects in the United States and internationally. Power is sold to
customers in the Northeast and Midwest United States and internationally in Asia
and Latin America.
Coal operations include the mining, processing and marketing of coal from
Company-owned reserves and from other sources, and the brokering of coal for
others. Sales are made to utilities and industrial customers in the United
States and to export markets in Canada.
Corporate and other operations include real estate activities and
corporate income and expense not allocated to the operating segments.
The Company's operating revenues from external customers; intersegment
revenues; earnings (loss) before interest and income taxes; depreciation
depletion and amortization; equity income (loss) from investments; and capital
expenditures for the years ended December 31, 1999, 1998 and 1997 are shown as
follows (Millions of Dollars):
<TABLE>
<CAPTION>
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
Operating Revenues From External Customers
Natural gas............................................... $ 1,243.5 $ 1,356.8 $ 2,125.5
Refining, marketing and chemicals......................... 6,005.9 5,200.4 6,870.9
Exploration and production................................ 556.3 436.6 383.4
Power..................................................... 127.6 121.1 103.8
Coal...................................................... 257.6 241.7 226.8
Corporate and other ...................................... 6.3 11.6 19.7
----------- ----------- -----------
Consolidated totals.................................... $ 8,197.2 $ 7,368.2 $ 9,730.1
=========== =========== ===========
Intersegment Revenues
Natural gas............................................... $ 3.4 $ 1.6 $ 40.7
Refining, marketing and chemicals......................... 2.2 2.3 6.2
Exploration and production................................ 27.7 26.4 106.8
Power..................................................... - - -
Coal...................................................... - - -
Corporate and other ...................................... 8.8 11.4 9.7
----------- ----------- -----------
Consolidated totals.................................... $ 42.1 $ 41.7 $ 163.4
=========== =========== ===========
Earnings (Loss) Before Interest and Income Taxes
Natural gas............................................... $ 573.8 $ 594.3 $ 583.0
Refining, marketing and chemicals......................... 228.5 243.9 95.6
Exploration and production................................ 185.9 109.8 167.6
Power..................................................... 89.0 67.8 43.4
Coal...................................................... 15.8 17.4 25.3
Corporate and other....................................... (96.9) (88.7) (70.4)
----------- ----------- -----------
Consolidated totals.................................... $ 996.1 $ 944.5 $ 844.5
=========== =========== ===========
Depreciation, Depletion and Amortization (Excluding
Amortization of Goodwill)
Natural gas............................................... $ 129.2 $ 118.3 $ 136.5
Refining, marketing and chemicals......................... 74.3 78.3 74.6
Exploration and production................................ 231.9 209.2 185.5
Power..................................................... 8.5 3.2 3.1
Coal...................................................... 16.8 14.6 14.1
Corporate and other....................................... 3.6 7.0 4.1
----------- ----------- -----------
Consolidated totals.................................... $ 464.3 $ 430.6 $ 417.9
=========== =========== ===========
</TABLE>
F-29
<PAGE>
<TABLE>
<CAPTION>
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
Equity Income (Loss) from Investments
Natural gas............................................... $ 95.7 $ 80.4 $ 92.6
Refining, marketing and chemicals......................... 20.7 1.0 8.7
Exploration and production................................ - - -
Power..................................................... 74.4 43.0 36.2
Coal...................................................... - - -
Corporate and other....................................... (.4) (0.1) -
----------- ----------- -----------
Consolidated totals.................................... $ 190.4 $ 124.3 $ 137.5
=========== =========== ===========
Capital Expenditures
Natural gas............................................... $ 307.3 $ 192.2 $ 224.7
Refining, marketing and chemicals......................... 162.8 229.1 167.6
Exploration and production................................ 1,079.6 934.8 574.4
Power..................................................... 153.1 2.0 2.2
Coal...................................................... 65.4 34.7 18.8
Corporate and other....................................... 12.4 11.2 9.0
----------- ----------- -----------
Consolidated totals.................................... $ 1,780.6 $ 1,404.0 $ 996.7
=========== =========== ===========
</TABLE>
The Company's assets and amount of investment in equity method investees
by segment as of December 31, 1999, 1998 and 1997 are as follows (Millions of
Dollars):
<TABLE>
<CAPTION>
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
Assets
Natural gas............................................... $ 5,801.3 $ 5,379.5 $ 5,262.0
Refining, marketing and chemicals......................... 4,464.2 3,351.2 3,795.4
Exploration and production................................ 3,029.5 2,161.6 1,484.0
Power..................................................... 765.3 449.8 258.1
Coal...................................................... 307.1 269.6 252.7
Corporate and other....................................... 755.6 692.4 587.5
----------- ----------- -----------
Consolidated totals.................................... $ 15,123.0 $ 12,304.1 $ 11,639.7
=========== =========== ===========
Equity Method Investments
Natural gas............................................... $ 851.3 $ 608.9 $ 521.7
Refining, marketing and chemicals......................... 98.8 68.2 64.6
Exploration and production................................ - - -
Power..................................................... 486.4 295.0 167.5
Coal...................................................... .5 .5 .5
Corporate and other....................................... (2.1) (1.8) (1.7)
----------- ----------- -----------
Consolidated totals.................................... $ 1,434.9 $ 970.8 $ 752.6
=========== =========== ===========
</TABLE>
Intersegment sales are accounted for on the basis of contract, current
market or internally established transfer prices.
In September 1996, Coastal and Westcoast Energy Inc. ("Westcoast") jointly
announced plans to form one of North America's largest marketers of natural gas
and electricity through the combination of the operations of the two companies'
related marketing and service subsidiaries. Agreements were concluded in
February 1997, which created Engage in which Coastal and Westcoast indirectly
own 50% each. Natural gas operating revenues for the first two months of 1997
include the revenues of Coastal's natural gas marketing operations ($833.5
million). Subsequent to the combination, Engage's revenues are not included in
Coastal's operating revenues; however, Coastal's share of Engage's net earnings
is included in Other Income-Net. As part of the combination, Coastal received an
equalization payment of $42 million which is included in the Natural Gas
earnings before interest and income taxes in 1997.
F-30
<PAGE>
In June 1998, the power purchase agreement associated with the Company's
Fulton Power Plant ("Plant") was restructured. In connection with the
restructuring, a net gain of $17.2 million was recorded in the Power segment.
The net gain reflects a $23 million reduction in the Plant's carrying value (to
estimated fair value following the restructuring) and deferral of certain
proceeds to cover estimated future costs.
In October 1998, the Company sold certain non-core natural gas processing
and gathering assets. Revenues and earnings before interest and income taxes for
the Natural Gas segment include a gain of $58.6 million from the sale.
Refining, marketing and chemicals revenues include gross profit arising
from the selling, trading and exchanging of third-party products. Approximate
amounts from these transactions included in revenues and the impact on earnings,
exclusive of interest costs, were (Millions of Dollars):
<TABLE>
<CAPTION>
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
Revenues.................................................. $ 52.5 $ 34.8 $ 26.3
Impact on earnings........................................ 34.1 22.6 17.1
</TABLE>
The number and magnitude of such transactions may vary significantly from
year to year, particularly in view of conditions in world petroleum markets.
The Company's operating revenues for the years ended December 31, 1999,
1998 and 1997 and property, plant and equipment as of December 31, 1999, 1998
and 1997, by geographic area, are shown as follows (Millions of Dollars):
<TABLE>
<CAPTION>
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
Operating Revenues
United States............................................. $ 6,865.4 $ 6,381.7 $ 8,059.6
Foreign, Aruba............................................ 1,045.1 743.4 1,251.4
Foreign, Other............................................ 286.7 243.1 419.1
----------- ----------- -----------
Consolidated totals.................................... $ 8,197.2 $ 7,368.2 $ 9,730.1
=========== =========== ===========
Property, Plant and Equipment
United States............................................. $ 8,608.7 $ 7,344.9 $ 6,551.0
Foreign, Aruba............................................ 589.2 564.0 478.8
Foreign, Other............................................ 139.5 115.0 91.8
----------- ----------- -----------
Consolidated totals.................................... $ 9,337.4 $ 8,023.9 $ 7,121.6
=========== =========== ===========
</TABLE>
Revenues from sales to any single customer during 1999, 1998 or 1997 did
not amount to 10% or more of the Company's consolidated revenues. Revenues by
geographic area are attributed to countries based on the location of Company
subsidiaries making the sales.
F-31
<PAGE>
Note 10. Benefit Plans
The Company has non-contributory pension plans covering substantially all
U.S. employees. These plans provide benefits based on final average monthly
compensation and years of service. The Company's funding policy is to contribute
the amount necessary for the plan to maintain its qualified status under the
Employment Retirement Income Security Act of 1974, as amended. The following
tables provide a reconciliation of the changes in the pension plans' benefit
obligations and fair value of assets over each of the years ended December 31,
1999 and 1998 and a statement of the funded status as of December 31, 1999 and
1998 (Millions of Dollars):
<TABLE>
<CAPTION>
Year Ended
December 31,
----------------------------
1999 1998
----------- -----------
<S> <C> <C>
Change in Benefit Obligation
Benefit obligation at beginning of year.................................... $ 757.9 $ 729.3
Service cost............................................................... 21.4 19.6
Interest cost.............................................................. 51.5 49.0
Plan amendment ............................................................ - 3.8
Actuarial (gain) loss...................................................... (11.4) (1.5)
Benefit payments........................................................... (42.9) (42.3)
----------- -----------
Benefit obligation at end of year.......................................... $ 776.5 $ 757.9
=========== ===========
Change in Plan Assets
Fair value of plan assets at beginning of year............................. $ 1,481.8 $ 1,298.7
Actual return on plan assets............................................... 222.4 224.9
Employer contributions..................................................... .7 .5
Benefit payments........................................................... (42.9) (42.3)
----------- -----------
Fair value of plan assets at end of year................................... $ 1,662.0 $ 1,481.8
=========== ===========
</TABLE>
<TABLE>
<CAPTION>
December 31,
----------------------------
1999 1998
----------- -----------
<S> <C> <C>
Funded Status
Funded status at year end.................................................. $ 885.5 $ 723.9
Unrecognized transition obligation (asset)................................. (20.3) (28.5)
Unrecognized prior service cost............................................ 5.0 5.9
Unrecognized net (gain) loss............................................... (368.4) (293.1)
----------- -----------
Prepaid pension cost....................................................... $ 501.8 $ 408.2
=========== ===========
</TABLE>
Plan assets include common stock and Class A common stock of the Company
amounting to a total of 7.2 million shares at December 31, 1999 and 1998,
respectively.
F-32
<PAGE>
The following table provides the components of the net periodic pension
benefit for 1999, 1998 and 1997 (Millions of Dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
Service cost.............................................. $ 21.4 $ 19.6 $ 17.2
Interest cost............................................. 51.5 49.0 47.5
Expected return on assets................................. (145.1) (126.4) (105.7)
Amortization of transition obligation (asset)............. (8.2) (8.6) (8.6)
Amortization of prior service cost........................ .8 .8 .4
Amortization of net (gain) loss........................... (13.4) (7.6) (3.1)
----------- ----------- -----------
Net periodic pension benefit ............................. $ (93.0) $ (73.2) $ (52.3)
=========== =========== ===========
</TABLE>
The discount rate used in determining the actuarial present value of the
projected benefit obligation was 8% in 1999 and 7% in 1998 and 1997. The
expected increase in future compensation levels was 4% in 1999, 1998 and 1997
and the expected long-term rate of return on assets was 10% in 1999, 1998 and
1997.
The Company also participates in several multi-employer pension plans for
the benefit of its employees who are union members. Company contributions to
these plans were not material for 1999, 1998 or 1997.
The Company also makes contributions to a thrift plan, which is a
trusteed, voluntary and contributory plan for eligible employees of the Company.
The Company's contributions, which are based on matching employee contributions,
amounted to $20.2 million, $19.4 million and $18.9 million in 1999, 1998 and
1997, respectively.
The Company provides certain health care and life insurance benefits for
retired employees. Substantially all U.S. employees are provided these benefits.
The estimated costs of retiree benefit payments are accrued during the years the
employee provides services.
F-33
<PAGE>
The following tables provide a reconciliation of the changes in the
postretirement benefit obligation and the fair value of plan assets over each of
the years ended December 31, 1999 and 1998, and a statement of the funded status
as of December 31, 1999 and 1998 (Millions of Dollars):
<TABLE>
<CAPTION>
Year Ended
December 31,
----------------------------
1999 1998
----------- -----------
<S> <C> <C>
Change in Benefit Obligation
Benefit obligation at beginning of year.................................... $ 108.1 $ 108.0
Service cost............................................................... 2.7 2.3
Interest cost.............................................................. 6.8 6.9
Participant contributions.................................................. 2.4 2.8
Actuarial gain (loss)...................................................... (2.7) (.8)
Benefit payments........................................................... (9.6) (10.2)
Curtailment (gain) loss.................................................... - (.9)
----------- -----------
Benefit obligation at end of year.......................................... $ 107.7 $ 108.1
=========== ===========
Change in Plan Assets
Fair value of plan assets at beginning of year............................. $ 24.4 $ 24.1
Actual return on plan assets............................................... 1.4 .1
Employer contributions..................................................... 10.4 5.5
Administrative expenses.................................................... (2.3) (.1)
Benefit payments........................................................... (4.5) (5.2)
----------- -----------
Fair value of plan assets at end of year................................... $ 29.4 $ 24.4
=========== ===========
</TABLE>
<TABLE>
<CAPTION>
December 31,
----------------------------
1999 1998
----------- -----------
<S> <C> <C>
Funded Status
Funded status at year end.................................................. $ (78.3) $ (83.7)
Unrecognized transition obligation ........................................ 77.2 83.2
Unrecognized prior service cost............................................ 3.0 3.5
Unrecognized net (gain) loss............................................... (38.6) (34.1)
----------- -----------
Accrued postretirement benefit obligation.................................. $ (36.7) $ (31.1)
=========== ===========
</TABLE>
The following table provides the components of net periodic postretirement
benefit cost for 1999, 1998 and 1997 (Millions of Dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
Service cost.............................................. $ 2.7 $ 2.3 $ 2.3
Interest cost............................................. 6.8 6.9 7.0
Expected return on assets................................. (.7) (.7) (.8)
Amortization of transition obligation .................... 5.9 6.0 6.0
Amortization of prior service cost........................ .4 .4 .4
Amortization of net (gain) loss........................... (2.4) (2.6) (2.6)
Deferred regulatory amounts............................... - - 3.5
----------- ----------- -----------
Net periodic postretirement benefit cost.................. $ 12.7 $ 12.3 $ 15.8
=========== =========== ===========
</TABLE>
The assumed health care cost trend rate used in measuring the accumulated
postretirement benefit obligation was 8.40% in 1999, declining gradually to 6.0%
by the year 2004. The assumed health care cost trend rate used in measuring
F-34
<PAGE>
the accumulated postretirement benefit obligation was 9.0% in 1998 and 9.7% in
1997. A one percentage point increase in the assumed health care cost trend rate
for each year would increase the accumulated postretirement benefit obligation
as of December 31, 1999 by approximately 4.63% and the net postretirement health
care cost by approximately 3.75%. A one percentage point decrease in the assumed
health care cost trend rate for each year would decrease the accumulated
postretirement benefit obligation as of December 31, 1999 by approximately 4.61%
and the net postretirement health care cost by approximately 4.58%.The assumed
discount rate used in determining the accumulated postretirement benefit
obligation was 8.0% in 1999, 7.0% in 1998 and 7.25% in 1997 and the expected
long-term rate of return on assets was 4.3% in 1999, 1998 and 1997.
Note 11. Taxes on Income
Pretax earnings from continuing operations before extraordinary item are
composed of the following (Millions of Dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
United States............................................. $ 554.3 $ 502.8 $ 458.2
Foreign .................................................. 118.5 146.8 78.8
----------- ----------- -----------
$ 672.8 $ 649.6 $ 537.0
=========== =========== ===========
</TABLE>
Provisions for income taxes from continuing operations before
extraordinary item are composed of the following (Millions of Dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
Current income taxes:
Federal................................................... $ 45.0 $ 5.0 $ 50.7
Foreign................................................... 7.8 5.5 5.3
State..................................................... 9.0 4.5 8.4
----------- ----------- -----------
61.8 15.0 64.4
----------- ----------- -----------
Deferred income taxes:
Federal................................................... 111.7 140.9 69.5
Foreign................................................... 3.4 3.4 3.3
State..................................................... (3.0) 7.4 1.1
----------- ----------- -----------
112.1 151.7 73.9
----------- ----------- -----------
Taxes on Income................................................. $ 173.9 $ 166.7 $ 138.3
=========== =========== ===========
</TABLE>
The Company and the Internal Revenue Service ("IRS") Appeals Office have
concluded a final settlement of adjustments originally proposed to federal
income tax returns filed for the years 1985 through 1987 and have concluded a
tentative settlement of the additional adjustments proposed by the IRS to those
returns. The Company and the IRS Appeals Office have also concluded a tentative
settlement of the adjustments proposed to the Company's federal income tax
returns filed for the years 1988 through 1990. The Company has received notice
of proposed adjustments to the Company's federal income tax returns filed for
the years 1991 through 1994, and the Company is currently contesting certain of
these adjustments before the IRS Appeals Office. Examination of the Company's
federal income tax returns filed for the years 1995, 1996 and 1997 began in
1999. It is the opinion of management that adequate provisions for federal
income taxes have been reflected in the consolidated financial statements.
F-35
<PAGE>
Provisions for income taxes were different than the amount computed by
applying the statutory U.S. federal income tax rate to earnings before tax. The
reasons for these differences are (Millions of Dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
Tax expense by applying the U.S. federal income tax
rate of 35%............................................ $ 235.5 $ 227.4 $ 187.9
Increases (reductions) in taxes resulting from:
Tight sands gas credit................................. (6.0) (7.9) (6.5)
State income tax cost ................................. 3.9 7.7 6.2
Goodwill............................................... 6.4 6.4 6.4
Exclusion for foreign investments and certain
domestic joint ventures.............................. (51.5) (50.3) (50.6)
Depletion and depreciation............................. (16.4) (1.2) (1.4)
Other.................................................. 2.0 (15.4) (3.7)
----------- ----------- -----------
Taxes on income................................................. $ 173.9 $ 166.7 $ 138.3
=========== =========== ===========
</TABLE>
Deferred tax liabilities (assets) which are recognized for the estimated
future tax effects attributable to temporary differences and carryforwards are
(Millions of Dollars):
<TABLE>
<CAPTION>
December 31,
----------------------------
1999 1998
----------- -----------
<S> <C> <C>
Excess of book basis over tax basis of property, plant and equipment ...... $ 1,646.2 $ 1,637.4
Pensions and benefit costs................................................. 129.4 109.8
Other...................................................................... 130.0 67.2
----------- -----------
Deferred tax liabilities................................................... 1,905.6 1,814.4
----------- -----------
Purchase gas and other recoverable costs................................... (4.9) (14.0)
Alternative minimum tax credit carryforward................................ (189.7) (195.4)
----------- -----------
Deferred tax assets........................................................ (194.6) (209.4)
----------- -----------
Deferred income taxes...................................................... $ 1,711.0 $ 1,605.0
=========== ===========
</TABLE>
U.S. income taxes have been provided for earnings of foreign subsidiaries
that are expected to be distributed to the U.S. parent company. Foreign
subsidiaries' cumulative undistributed earnings of $389.3 million are considered
to be indefinitely reinvested outside the U.S. and, accordingly, no U.S. income
taxes have been provided on those earnings. The determination of the
hypothetical amount of unrecognized deferred U.S. taxes on undistributed
earnings of foreign subsidiaries is not practicable.
Note 12. Discontinued Operations
The Company is pursuing the disposition of its 50% ownership of ANR
Advance Transportation Company, Inc. ("ANR Advance"), a trucking operation. ANR
Advance is being liquidated in cooperation with other owners. Accordingly, the
trucking operations are being reported as a discontinued operation.
The net assets (liabilities) being disposed of have been classified in the
accompanying consolidated balance sheet in Other Assets at December 31, 1999 and
1998. The net assets (liabilities) of the discontinued operations amounted to
$2.5 million and $(.5) million at December 31, 1999 and 1998, respectively.
Operating results of the discontinued operations are shown separately in
the accompanying statement of consolidated operations. The loss from operations
shown on the statement of consolidated operations is net of income tax benefits
of $1.9 million and $3.5 million in 1998 and 1997, respectively. The estimated
loss on disposal of the discontinued operations of $35.0 million is net of
income tax benefits of $18.8 million.
F-36
<PAGE>
Note 13. Extraordinary Item
Early Extinguishment of Debt. In February 1997, the Company purchased and
retired $798.0 million of notes and debentures with interest rates ranging from
9-3/4% to 10-3/4%. None of the issues were eligible for redemption and the
purchase included payment of a premium. The Company incurred an after-tax
extraordinary charge of $90.6 million ($.43 per share-basic or $.42 per
share-diluted), net of income taxes of $48.7 million, in connection with the
repurchase of these debt securities.
Note 14. Earnings Per Share
Earnings per share are calculated following Statement of Financial
Accounting Standards No. 128. The following data shows the amounts used in
computing basic earnings per share and the effects on income and the weighted
average number of shares of dilutive securities.
<TABLE>
<CAPTION>
For the Year Ended December 31, 1999
-----------------------------------------------
Income Shares
(Numerator) (Denominator) Per-Share
(Millions) (Thousands) Amount
-------------- ----------- -----------
<S> <C>
Earnings from continuing operations
before extraordinary item............................ $ 498.9
Less preferred stock dividends.......................... .3
--------------
Basic earnings per share
Income available to common stockholders.............. 498.6 213,283 $ 2.34
===========
Effect of dilutive securities
Options.............................................. - 2,465
Convertible preferred stock.......................... .3 1,244
-------------- -----------
Diluted earnings per share
Income available to common stockholders
plus assumed conversions......................... $ 498.9 216,992 $ 2.30
============== =========== ===========
</TABLE>
<TABLE>
<CAPTION>
For the Year Ended December 31, 1998
-----------------------------------------------
Income Shares
(Numerator) (Denominator) Per-Share
(Millions) (Thousands) Amount
-------------- ----------- -----------
<S> <C>
Earnings from continuing operations before
extraordinary items.................................. $ 482.9
Less preferred stock dividends.......................... 6.0
--------------
Basic earnings per share
Income available to common stockholders.............. 476.9 212,543 $ 2.24
===========
Effect of dilutive securities
Options.............................................. - 2,248
Convertible preferred stock.......................... .3 1,317
-------------- -----------
Diluted earnings per share
Income available to common stockholders
plus assumed conversions......................... $ 477.2 216,108 $ 2.21
============== =========== ===========
</TABLE>
F-37
<PAGE>
<TABLE>
<CAPTION>
For the Year Ended December 31, 1997
-----------------------------------------------
Income Shares
(Numerator) (Denominator) Per-Share
(Millions) (Thousands) Amount
-------------- ----------- -----------
<S> <C>
Earnings from continuing operations before
extraordinary items.................................. $ 398.7
Less preferred stock dividends.......................... 17.4
--------------
Basic earnings per share
Income available to common stockholders.............. 381.3 211,892 $ 1.80
===========
Effect of dilutive securities
Options.............................................. - 1,798
Convertible preferred stock.......................... .4 1,412
-------------- -----------
Diluted earnings per share
Income available to common stockholders plus
assumed conversions.............................. $ 381.7 215,102 $ 1.77
============== =========== ===========
</TABLE>
Note 15. Litigation, Environmental and Regulatory Matters
Litigation. In December 1992, certain of Colorado's natural gas lessors in
the West Panhandle Field filed a complaint in the U.S. District Court, Northern
District of Texas, claiming underpayment of royalties, breach of fiduciary duty,
fraud and negligent misrepresentation. Management believes that CIG has numerous
defenses to the lessors' claims, including (i) that the royalties were properly
paid, (ii) that the majority of the claims were released by written agreement
and (iii) that the majority of the claims are barred by the statute of
limitations. In March of 1995, the trial court granted a partial summary
judgment in favor of CIG, holding that the four-year statute of limitations had
not been tolled and the releases are valid and dismissing all tort claims and
claims for breach of any duty of disclosure. The remaining claim for
underpayment of royalties was tried to a jury which, in May 1995, made findings
favorable to CIG. On June 7, 1995, the trial court entered a judgment that the
lessors recover no monetary damages from CIG and permanently estopping the
lessors from asserting any claim based on an interpretation of the contract
different than that asserted by CIG in the litigation. The lessors' motion for a
new trial was denied on July 18, 1997, and both parties filed appeals. On June
7, 1996, the same plaintiffs sued CIG in state court in Amarillo, Texas, for
underpayment of royalties. CIG removed the second lawsuit to federal court which
granted a stay of the second suit pending the outcome of the first lawsuit. Oral
arguments were heard before the Fifth Circuit Court of Appeals on December 4,
1998, and the parties are awaiting the Court's decision.
In October 1996, the Company, along with several subsidiaries, was named
as a defendant in a suit filed by several former and current African American
employees in the U.S. District Court, Southern District of Texas ("Texas suit").
The Texas suit alleges racially discriminatory employment policies and
practices. Coastal vigorously denies these allegations and has filed responsive
pleadings. Plaintiffs' counsel are seeking to have the Texas suit certified as a
class action of all former and current African American employees and initially
claimed compensatory and punitive damages of $400 million. In February 1999, in
response to Coastal's motion to deny class certification, plaintiffs' counsel
obtained permission from the Court to delete all claims for compensatory and
punitive damages and to seek equitable relief only.
In January 1998, the plaintiffs in the Texas suit amended their suit to
exclude ANR Pipeline employees from the potential class. A new suit was then
filed in state court in Wayne County, Michigan, seeking to have the Michigan
suit certified as a class action of African American employees of ANR Pipeline
and seeking unspecified damages as well as attorneys and expert fees. ANR
Pipeline has filed responsive pleadings denying these allegations. In August
1999, the court denied plaintiffs' motion to have the Michigan suit certified as
a class action. Plaintiffs filed with the Michigan Court of Appeals an
application for leave to appeal the denial of the class certification. On
November 5, 1999, the Michigan Court of Appeals denied the application for leave
to appeal.
Two legal proceedings, one in federal court and the other in state court,
have been instituted against a number of gas pipeline companies and their
affiliates, including Coastal and several of its subsidiaries. The plaintiffs in
each suit
F-38
<PAGE>
seek damages for the alleged undermeasurement of the heating value and the
volume of natural gas. In the federal proceeding, Jack Grynberg filed 77
separate False Claim Act suits in September 1997 against natural gas
transmission companies and producers, gatherers, and processors of natural gas,
seeking unspecified damages which could include treble damages for the maximum
period permitted by law (potentially as much as ten years) and penalties of up
to $10,000 per false claim. In addition to the measurement claims, these suits
also allege that the defendants undervalued the gas in paying royalties. The
Coastal defendants were sued in the U.S. District Courts of Colorado and the
Eastern District of Michigan. In April 1999, the U.S. Department of Justice
notified the Company that the United States will not intervene in these cases at
this time. The MultiDistrict Litigation Panel has consolidated the Grynberg
suits with several other Grynberg cases for pre-trial proceedings in Wyoming.
The defendants have filed a motion to dismiss which will be argued in March of
2000.
In the state proceedings, the Quinque Operating Company, on behalf of
itself and subclasses of gas producers, royalty owners, overriding royalty
owners, and state taxing authorities, in May 1999 instituted a legal proceeding
in State Court in Stevens County, Kansas against over 200 gas companies,
including several Coastal subsidiaries. The Quinque suit seeks unspecified
actual, punitive and treble damages for the alleged undermeasurement of all
natural gas measured in the United States from non-federal and non-Indian lands
since 1974. The plaintiffs are seeking certification of a national class of all
similarly situated gas producers, royalty owners, overriding royalty owners, and
state taxing authorities. The suit has been removed to the U.S. District Court
for the District of Kansas. The plaintiffs have filed a motion to remand the
case back to the state court, and several defendants have filed a motion under
the MultiDistrict Litigation rules to have the suit transferred to Wyoming and
consolidated with the Grynberg proceedings for pre-trial proceedings.
Numerous other lawsuits and other proceedings which have arisen in the
ordinary course of business are pending or threatened against the Company or its
subsidiaries.
Although no assurances can be given and no determination can be made at
this time as to the outcome of any particular lawsuit or proceeding, the Company
believes there are meritorious defenses to substantially all such claims and
that any liability which may finally be determined should not have a material
adverse effect on the Company's consolidated financial position or results of
operations.
Environmental Matters. The Company's operations are subject to extensive
and evolving federal, state and local environmental laws and regulations.
Compliance with such laws and regulations can be costly. Additionally,
governmental authorities may enforce the laws and regulations with a variety of
civil and criminal enforcement measures, including monetary penalties and
remediation requirements.
The Company spent approximately $10 million in 1999 on environmental
capital projects and anticipates capital expenditures of approximately $36
million in 2000 in order to comply with such laws and regulations. The majority
of the 2000 expenditures is attributable to projects at the Company's refining,
chemical and terminal facilities. The Company currently anticipates capital
expenditures for environmental compliance of $20 million to $40 million per year
over the next several years.
The Comprehensive Environmental Response, Compensation and Liability Act,
also known as "Superfund," imposes liability for the release of a "hazardous
substance" into the environment. Superfund liability is imposed without regard
to fault and even if the waste disposal was in compliance with the then current
laws and regulations. With the joint and several liability imposed under
Superfund, a potentially responsible party ("PRP") may be required to pay more
than its proportional share of such costs. Certain subsidiaries of the Company
and a company in which Coastal owns a 50% interest have been named as a PRP in
various "Superfund" waste disposal sites. At the nine sites for which there is
sufficient information, total cleanup costs are estimated to be approximately
$609 million, and the Company estimates its pro-rata exposure, to be paid over a
period of years, is approximately $8 million and has made appropriate
provisions. At ten other sites, the EPA is currently unable to provide the
Company with an estimate of total cleanup costs and, accordingly, the Company is
unable to calculate its share of those costs.
Additionally, certain subsidiaries of the Company have been named as PRPs
in four state sites. At one site, the North Carolina Department of Health,
Environmental and Natural Resources has estimated the total cleanup costs to
F-39
<PAGE>
be approximately $50 million, but the Company believes the subsidiary's
activities at this site were de minimis. At a second state site, the Florida
Department of Environmental Protection has demanded reimbursement of its costs,
which total $100,000, and suitable remediation. The Company believes the
subsidiary's activities at the Florida site were de minimis. At a third site,
the owner of the California site has estimated the total cleanup costs to be
approximately $40 million, but the Company believes the subsidiary's activities
at this site were de minimis. At the fourth site, the Texas Natural Resource
Conservation Commission has estimated the total cleanup costs to be
approximately $2 million, but the Company believes the subsidiary's activities
at this site were de minimis.
Future information and developments, including legislative and enforcement
developments, will require the Company to continually reassess the expected
impact of these environmental matters. However, the Company has evaluated its
total environmental exposure based on currently available data, including its
potential joint and several liability, and believes that compliance with all
applicable laws and regulations will not have a material adverse impact on the
Company's consolidated financial position or results of operations.
Regulatory Matters. On July 29, 1998, the FERC issued a "Notice of
Proposed Rulemaking," in which the FERC has proposed a number of significant
changes to the industry, including, among other things, removal of price caps in
the short-term market (less than one year), capacity auctions, changed reporting
obligations, the ability to negotiate terms and conditions of all services,
elimination of the requirement of a matching term cap on the renewal of existing
contracts, and a review of its policies for approving capacity construction. On
the same day, the FERC also issued a "Notice of Inquiry" soliciting industry
input on various matters affecting the pricing of long-term service and
certificate pricing in light of changing market conditions. On February 9, 2000,
the FERC issued a final rule implementing certain of the changes that were
discussed in these two proposals. Among other things, the final rule: (a)
removes the price ceilings for short-term secondary market capacity releases for
a trial period through September 30, 2002; (b) permits pipelines to propose
seasonally and term-differentiated rates; (c) revises requirements relating to
pipeline scheduling procedures, capacity segmentation and penalties; (d) narrows
the right-of-first-refusal granted to long-term shippers to retain their
capacity; and (e) expands pipeline reporting requirements. Coastal's interstate
pipeline subsidiaries will seek clarification of certain aspects of the final
rule.
On September 15, 1999, the FERC issued a Policy Statement addressing the
certification and pricing of new pipeline construction projects. Under the
Policy Statement, applicants must first satisfy a threshold pricing requirement
of demonstrating that their projects can be constructed without subsidies from
existing customers. Second, the applicants must show that any adverse impacts of
the project on identified interests (existing customers of the applicant, other
existing pipelines and their captive customers, landowners and the surrounding
communities) are outweighed by its benefits. On October 19, 1999, Coastal's
interstate pipeline subsidiaries sought clarification and/or rehearing of the
Policy Statement insofar as it does not apply directly to those projects filed
for approval under the FERC's "optional certificate" regulations. Other parties
also sought rehearing of this and other aspects of the Policy Statement. On
February 9, 2000, the FERC issued an order which, among other things, held that
the Policy Statement balancing criteria would apply to new optional certificate
applications while it receives comments on its companion notice proposing to
eliminate its optional certificate regulations.
On May 30, 1997, WIC filed with the FERC to increase its rates by
approximately $5.7 million annually. On June 27, 1997, the FERC accepted the
filing effective as of December 1, 1997, subject to refund. The FERC staff and
certain participants in the proceeding raised a number of issues relating to
WIC's rates, revenue requirements and the treatment of an "exit fee" which WIC
had received in conjunction with the termination of a transportation service
agreement. WIC and most of the parties subsequently reached a settlement
resolving all issues in the case. That settlement was ultimately approved by the
FERC on June 21, 1999 (the "June 21, 1999 settlement"). Two parties opposed the
settlement and the FERC initially severed them from the settlement and ordered a
separate hearing on their issues. However, on October 13, 1999, the FERC
determined that the settlement should also apply to those parties as well,
inasmuch as WIC had filed a new rate case (discussed below) which would become
effective before any decision could be reached and implemented. The FERC denied
rehearing of the October 13, 1999 Order on December 21, 1999. The two parties
who had objected to the settlement have the right to seek judicial review of
this order.
On July 1, 1999, WIC filed with the FERC a new rate case to increase its
rates by approximately $8 million annually (based on the rates determined under
the June 21, 1999 settlement). On July 29, 1999, the FERC issued its
F-40
<PAGE>
order accepting the rate filing and suspending it for five months to become
effective on January 1, 2000. The order also set the case for hearing, which is
currently scheduled to commence in the second half of 2000. WIC has filed to
place its new rates into effect on January 1, 2000, and is collecting those
rates subject to refund.
Certain other regulatory issues remain unresolved among CIG, ANR Pipeline,
ANR Storage Company and WIC, their customers, their suppliers and the FERC. The
Company has made provisions which represent management's assessment of the
ultimate resolution of these issues. As a result, the Company anticipates that
these regulatory matters will not have a material adverse effect on its
consolidated financial position or results of operations. While the Company
estimates the provisions to be adequate to cover potential adverse rulings on
these and other issues, it cannot estimate when each of these issues will be
resolved.
Note 16. Quarterly Results of Operations (Unaudited)
Results of operations by quarter for the years ended December 31, 1999 and
1998 were (Millions of Dollars Except per Share):
<TABLE>
<CAPTION>
Quarter Ended
----------------------------------------------------------------------
March 31, 1999 June 30, 1999 Sept. 30, 1999 Dec. 31, 1999
-------------- ------------- -------------- -------------
<S> <C> <C> <C> <C>
Operating revenues......................... $ 1,709.6 $ 1,892.1 $ 2,060.1 $ 2,535.4
Less purchases............................. 945.9 1,184.3 1,295.5 1,723.0
---------- ----------- ---------- ----------
763.7 707.8 764.6 812.4
Other income and expenses.................. 629.2 614.5 662.5 643.4
---------- ----------- ---------- ----------
Net earnings .............................. $ 134.5 $ 93.3 $ 102.1 $ 169.0
========== =========== ========== ==========
Basic earnings per share................... $ .63 $ .44 $ .48 $ .79
========== =========== ========== ==========
Diluted earnings per share................. $ .62 $ .43 $ .47 $ .78
========== =========== ========== ==========
</TABLE>
<TABLE>
<CAPTION>
Quarter Ended
----------------------------------------------------------------------
March 31, 1998 June 30, 1998 Sept. 30, 1998 Dec. 31, 1998*
-------------- ------------- -------------- --------------
<S> <C> <C> <C> <C>
Operating revenues......................... $ 1,956.5 $ 1,924.4 $ 1,661.6 $ 1,825.7
Less purchases............................. 1,186.4 1,176.8 966.9 1,046.7
---------- ----------- ---------- ----------
770.1 747.6 694.7 779.0
Other income and expenses.................. 645.3 656.1 602.9 604.2
---------- ----------- ---------- ----------
Earnings from continuing operations........ 124.8 91.5 91.8 174.8
Discontinued operations.................... (1.9) 3.1 (2.3) (37.4)
---------- ----------- ---------- ----------
Net earnings............................... $ 122.9 $ 94.6 $ 89.5 $ 137.4
========== =========== ========== ==========
Basic earnings per share:
From continuing operations.............. $ .57 $ .42 $ .43 $ .82
Discontinued operations................. (.01) .02 (.01) (.18)
---------- ----------- ---------- ----------
Net basic earnings per share............ $ .56 $ .44 $ .42 $ .64
========== =========== ========== ==========
Diluted earnings per share:
From continuing operations.............. $ .56 $ .42 $ .42 $ .81
Discontinued operations................. (.01) .01 (.01) (.17)
---------- ----------- ---------- ----------
Net diluted earnings per share ......... $ .55 $ .43 $ .41 $ .64
========== =========== ========== ==========
<FN>
*Includes a $58.6 million gain ($38.1 million net of income taxes, or $.18 per
share) from the sale of certain non-core natural gas processing and gathering
assets.
</FN>
</TABLE>
F-41
<PAGE>
Note 17. Merger
Coastal and El Paso Energy Corporation ("El Paso Energy") announced on
January 18, 2000 the execution of definitive agreements for the merger of
Coastal and El Paso Energy. Each share of Coastal common stock and Class A
common stock will be converted on a tax-free basis (except for cash paid in lieu
of fractional shares) into 1.23 shares of El Paso Energy common stock. The
outstanding convertible preferred stock of Coastal will be exchanged tax free
(except for cash paid in lieu of fractional shares) for El Paso Energy common
stock on the same basis as if the preferred stock had been converted into
Coastal common stock immediately prior to the merger. It is expected that the
merger will be completed during the fourth quarter of 2000 and be accounted for
as a pooling of interests. The merger is subject to various conditions,
particularly federal regulatory approval.
F-42
<PAGE>
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
Reserves; capitalized costs; costs incurred in oil and gas acquisition,
exploration and development activities; results of operations; and the
standardized measure of discounted future net cash flows are presented for the
exploration and production segment. Natural gas systems reserves and the related
standardized measure of discounted future net cash flows are separately
presented for natural gas systems operations. All of the Company's proved
properties are located in North America (United States and Canada). The reserve
tables that follow report on United States operations and do not include
approximately 78,000 MMcf equivalents of Canadian proved reserves discovered
during the fourth quarter of 1999.
Estimated Quantities of Proved Reserves (Domestic)
<TABLE>
<CAPTION>
Natural Gas Exploration
Systems and Production
----------- --------------------------
Developed Developed Undeveloped Total
----------- --------- ----------- ---------
<S> <C> <C> <C> <C>
Natural Gas (MMcf):
------------------
1999.................................................. 197,649 1,625,713 1,643,350 3,466,712
1998.................................................. 211,761 1,287,207 1,028,167 2,527,135
1997.................................................. 248,248 953,235 551,031 1,752,514
Oil, Condensate and Natural Gas Liquids (000 barrels):
-----------------------------------------------------
1999.................................................. 249 33,690 23,188 57,127
1998.................................................. 237 31,894 20,153 52,284
1997.................................................. 349 27,016 12,778 40,143
</TABLE>
Changes in proved reserves since the end of 1996 are shown in the following
table.
<TABLE>
<CAPTION>
Oil, Condensate and
Natural Gas Natural Gas Liquids
(MMcf) (000 barrels)
---------------------------- ----------------------------
Natural Exploration Natural Exploration
Gas and Gas and
Total Proved Reserves Systems Production Systems Production
- --------------------- ----------- ------------- ----------- -------------
<S> <C> <C> <C> <C>
Total, end of 1996.............................. 267,927 1,188,605 391 44,071
-------- ---------- ------- ---------
Production during 1997.......................... (38,135) (159,127) (57) (4,957)
Extensions and discoveries...................... 8,870 305,319 - 5,775
Acquisitions.................................... - 252,219 - 2,340
Sales of reserves in-place...................... - (56,894) - (6,739)
Revisions of previous quantity estimates and
other..................................... 9,586 (25,856) 15 (696)
-------- ---------- ------- ---------
Total, end of 1997.............................. 248,248 1,504,266 349 39,794
-------- --------- ------- ---------
Production during 1998.......................... (39,058) (185,732) (44) (5,578)
Extensions and discoveries...................... 404 518,529 - 9,185
Acquisitions.................................... - 575,934 - 11,915
Sales of reserves in-place...................... - (25,556) - (1,072)
Revisions of previous quantity estimates and
other..................................... 2,167 (72,067) (68) (2,197)
-------- ---------- ------- ---------
Total, end of 1998.............................. 211,761 2,315,374 237 52,047
-------- ---------- ------- ---------
Production during 1999.......................... (35,634) (230,542) (24) (4,475)
Extensions and discoveries...................... - 745,565 - 5,354
Acquisitions.................................... - 539,274 - 11,377
Sales of reserves in-place...................... - (39,908) - (805)
Revisions of previous quantity estimates and
other..................................... 21,522 (60,700) 36 (6,620)
-------- ---------- ------- ---------
Total, end of 1999.............................. 197,649 3,269,063 249 56,878
======== ========== ======= =========
</TABLE>
F-43
<PAGE>
Total proved reserves for natural gas systems exclude storage gas and
liquids volumes. The natural gas systems storage gas volumes are 221,509,
225,853 and 213,571 MMcf and storage liquids volumes are approximately 301,000,
232,000 and 209,000 barrels at December 31, 1999, 1998 and 1997, respectively.
Total proved reserves for natural gas equivalents include approximately 152,000,
162,000 and 32,000 MMcf associated with volumetric production payments sold to
unaffiliated entities by the Company for the years 1999, 1998 and 1997,
respectively.
All of the Company's proved reserves are located in North America (United
States and Canada). Other international activities are connected with the
evaluation of various concessions. The statistical tables on capitalized costs
report on worldwide operations while the reserve and cash flow tables are for
properties located in the United States. Other international investments are
periodically reviewed for impairment.
Capitalized Costs Relating to Exploration and Production Activities (Worldwide)
(Millions of Dollars)
<TABLE>
<CAPTION>
December 31,
--------------------
1999 1998
-------- --------
<S> <C> <C>
Proved and Unproved Properties:
- ------------------------------
Proved properties....................................................................... $ 3,234 $ 2,508
Unproved properties..................................................................... 536 312
-------- --------
3,770 2,820
Accumulated depreciation, depletion and amortization.................................... (904) (765)
-------- --------
$ 2,866 $ 2,055
======== ========
</TABLE>
The Company follows the full-cost method of accounting for oil and gas
properties.
Costs Excluded from Amortization (Domestic)
(Millions of Dollars)
The following table summarizes the costs related to unevaluated properties
and major development projects which are excluded from amounts subject to
amortization at December 31, 1999. The Company regularly evaluates these costs
to determine whether impairment has occurred. The majority of these costs are
expected to be evaluated and included in the amortization base within three
years.
<TABLE>
<CAPTION>
Years Costs Incurred
--------------------------------------------------------------
Prior to
Total 1999 1998 1997 1997
--------- --------- -------- -------- ---------
<S> <C> <C> <C> <C> <C>
Property acquisition............................. $ 277 $ 137 $ 121 $ 15 $ 4
Exploration...................................... 123 89 28 4 2
Development...................................... 64 36 21 6 1
Capitalized interest............................. 22 20 2 - -
--------- --------- -------- -------- ---------
$ 486 $ 282 $ 172 $ 25 $ 7
========= ========= ======== ======== =========
</TABLE>
F-44
<PAGE>
Costs Incurred in Oil and Gas Acquisition, Exploration and Development
Activities (Worldwide) (Millions of Dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------
1999 1998 1997
-------- -------- ---------
<S> <C> <C> <C>
Property acquisition costs:
Proved................................................................. $ 154 $ 129 $ 48
Unproved............................................................... 152 133 49
Exploration costs............................................................ 168 123 83
Development costs............................................................ 593 540 388
</TABLE>
Results of Operations for Exploration and Production Activities (Domestic)
(Millions of Dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------
1999 1998 1997
-------- -------- --------
<S> <C> <C> <C>
Revenues:
Sales..................................................................... $ 451 $ 333 $ 227
Transfers................................................................. 113 111 240
-------- -------- --------
Total.................................................................. 564 444 467
-------- -------- --------
Production costs............................................................. (104) (89) (92)
Operating expenses........................................................... (50) (44) (34)
Depreciation, depletion and amortization..................................... (223) (195) (171)
-------- -------- --------
187 116 170
Income tax expense........................................................... (59) (33) (52)
-------- -------- --------
Results of operations for producing activities (excluding corporate
overhead and interest costs).............................................. $ 128 $ 83 $ 118
======== ======== ========
</TABLE>
The average domestic amortization rate per equivalent Mcf was $0.87 in
1999, $0.89 in 1998 and $0.91 in 1997. Depreciation, depletion and amortization
excludes provisions for the impairment of international projects of $10.0
million in 1999, $9.1 million in 1998 and $10.7 million in 1997.
Standardized Measure of Discounted Future Net Cash Flows Relating to
Proved Oil and Gas Reserve Quantities (Domestic). Future cash inflows for the
years ended December 31, 1999 and 1998 from the sale of proved reserves and
estimated production and development costs as calculated by the Company's
engineers and reviewed by Huddleston, the Company's independent engineer, are
discounted by 10% after they are reduced by the Company's estimate for future
income taxes. The amount for 1997 was calculated by Huddleston. The calculations
are based on year-end prices and costs, statutory tax rates and nonconventional
fuel source tax credits that relate to existing proved oil and gas reserves in
which the Company has mineral interests.
F-45
<PAGE>
The standardized measure is not intended to represent the market value of
reserves and, in view of the uncertainties involved in the reserve estimation
process, including the instability of energy markets as evidenced by changes in
both natural gas and crude oil prices, may be subject to material future
revisions (Millions of Dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------------------------------------------------------
1999 1998 1997
------------------------- ------------------------- ----------------------------
Natural Gas Exploration Natural Gas Exploration Natural Gas Exploration
Systems and Production Systems and Production Systems and Production
----------- -------------- ----------- -------------- ----------- ---------------
<S> <C> <C> <C> <C> <C> <C>
Future cash inflows.......... $ 229 $ 8,250 $ 256 $ 4,939 $ 291 $ 4,190
Future production and
development costs......... (74) (2,674) (79) (1,909) (87) (1,479)
Future income tax expenses... (49) (1,265) (57) (584) (67) (635)
----------- ----------- ----------- ----------- ----------- -----------
Future net cash flows........ 106 4,311 120 2,446 137 2,076
10% annual discount for
estimated timing of cash
flows..................... (41) (1,556) (51) (865) (57) (651)
----------- ----------- ----------- ----------- ----------- -----------
Standardized measure of
discounted future net
cash flows................ $ 65 $ 2,755 $ 69 $ 1,581 $ 80 $ 1,425
=========== =========== =========== =========== =========== ===========
</TABLE>
Future net cash flows include approximately $190 million for 1999, $156
million for 1998 and $38 million for 1997 related to volumes dedicated to
volumetric production payments sold to unaffiliated entities by the Company.
Principal sources of change in the standardized measure of discounted
future net cash flows during each year are (Millions of Dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------------------------------------------------------
1999 1998 1997
------------------------- ------------------------- ----------------------------
Natural Gas Exploration Natural Gas Exploration Natural Gas Exploration
Systems and Production Systems and Production Systems and Production
----------- -------------- ----------- -------------- ----------- ---------------
<S> <C> <C> <C> <C> <C> <C>
Sales and transfers, net of
production costs.......... $ (36) $ (474) $ (34) $ (338) $ (34) $ (373)
Net changes in prices and
production costs.......... (5) 734 3 (334) (53) (906)
Extensions and discoveries... - 606 - 430 10 322
Acquisitions................. - 643 - 317 - 289
Sales of reserves in-place... - (33) - (21) - (117)
Development costs incurred during
the period that reduced estimated
future development costs.. - 102 - 115 - 11
Revisions of previous quantity
estimates, timing and other 28 (234) 6 (322) (34) (392)
Accretion of discount........ 6 136 8 141 17 233
Net change in income taxes... 3 (306) 6 168 34 398
----------- ----------- ----------- ----------- ----------- -----------
Net change................... $ (4) $ 1,174 $ (11) $ 156 $ (60) $ (535)
=========== =========== =========== =========== =========== ===========
</TABLE>
None of the amounts include any value for natural gas systems storage gas
and liquids volumes, which was approximately 41 Bcf for CIG, 117 Bcf for ANR
Pipeline, 63 Bcf for Mid Michigan Gas Storage Company and 301,000 barrels of
liquids for CIG at the end of 1999.
F-46
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT
THE COASTAL CORPORATION
BALANCE SHEET
(Millions of Dollars)
<TABLE>
<CAPTION>
December 31,
------------------------
1999 1998
--------- ---------
<S> <C> <C>
ASSETS
- ------
CURRENT ASSETS:
Cash and cash equivalents......................................................... $ .5 $ 79.6
Receivables....................................................................... 9.6 6.1
Receivables from subsidiaries..................................................... 2,050.8 1,516.6
Prepaid expenses and other........................................................ 4.9 4.6
--------- ---------
Total Current Assets........................................................... 2,065.8 1,606.9
--------- ---------
PROPERTY, PLANT AND EQUIPMENT - at cost, net......................................... .6 .5
--------- ---------
INVESTMENTS IN SUBSIDIARIES AND OTHER ASSETS:
Investment in subsidiaries at cost plus equity in undistributed earnings since
acquisition.................................................................... 4,853.2 4,361.7
Due from subsidiaries............................................................. 283.2 128.1
Deferred income taxes............................................................. 145.4 120.5
Other assets...................................................................... 517.8 392.3
--------- ---------
5,799.6 5,002.6
$ 7,866.0 $ 6,610.0
========= =========
</TABLE>
See Notes to Condensed Financial Statements.
S-1
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT
THE COASTAL CORPORATION
BALANCE SHEET
(Millions of Dollars)
<TABLE>
<CAPTION>
December 31,
------------------------
1999 1998
--------- ---------
<S> <C> <C>
LIABILITIES AND STOCKHOLDERS' EQUITY
- ------------------------------------
CURRENT LIABILITIES:
Notes payable..................................................................... $ 105.9 $ 87.0
Accounts payable and accrued expenses............................................. 118.5 70.0
Payable to subsidiaries........................................................... 9.6 242.4
Current maturities on long-term debt.............................................. 151.3 50.0
--------- ---------
Total Current Liabilities...................................................... 385.3 449.4
--------- ---------
DUE TO SUBSIDIARIES.................................................................. 366.4 309.8
--------- ---------
DEBT:
Long-term debt.................................................................... 3,176.5 2,374.6
--------- ---------
DEFERRED CREDITS AND OTHER........................................................... .9 .4
--------- ---------
COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY.......................................... 3,936.9 3,475.8
--------- ---------
$ 7,866.0 $ 6,610.0
========= =========
</TABLE>
See Notes to Condensed Financial Statements.
S-2
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT
THE COASTAL CORPORATION
STATEMENT OF OPERATIONS
(Millions of Dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------
1999 1998 1997
--------- --------- ---------
<S> <C> <C> <C>
OPERATING REVENUES..................................................... $ - $ - $ -
OPERATING COSTS AND EXPENSES........................................... - - -
--------- --------- ---------
OPERATING PROFIT....................................................... - - -
--------- --------- ---------
OTHER INCOME:
Equity in net earnings of subsidiaries.............................. 517.7 455.6 424.8
Interest income from subsidiaries - net............................. 85.0 54.4 63.0
Other income - net.................................................. 127.1 70.4 62.0
--------- --------- ---------
729.8 580.4 549.8
--------- --------- ---------
OTHER EXPENSES (BENEFITS):
General and administrative.......................................... 11.6 10.0 11.7
Interest and debt expense........................................... 233.0 179.9 166.9
Taxes on income..................................................... (13.7) (66.4) (20.9)
--------- --------- ---------
230.9 123.5 157.7
--------- --------- ---------
EARNINGS FROM CONTINUING OPERATIONS
BEFORE EXTRAORDINARY ITEM........................................... 498.9 456.9 392.1
DISCONTINUED OPERATIONS, NET OF INCOME TAXES:
Estimated loss on disposal.......................................... - (12.5) -
--------- --------- ---------
EARNINGS BEFORE EXTRAORDINARY ITEM..................................... 498.9 444.4 392.1
--------- --------- ---------
EXTRAORDINARY ITEM, NET OF INCOME TAXES:
Loss on early extinguishment of debt................................ - - (90.6)
--------- --------- ---------
NET EARNINGS........................................................... $ 498.9 $ 444.4 $ 301.5
========= ========= =========
</TABLE>
See Notes to Condensed Financial Statements.
S-3
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT
THE COASTAL CORPORATION
STATEMENT OF CASH FLOWS
(Millions of Dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------
1999 1998 1997
--------- --------- ---------
<S> <C> <C> <C>
Net Cash Flow From Operating Activities:
Earnings from continuing operations before extraordinary item....... $ 498.9 $ 456.9 $ 392.1
Items not requiring (providing) cash:
Depreciation, depletion and amortization......................... .1 .1 .1
Deferred income taxes............................................ (26.0) (35.2) (25.1)
Undistributed subsidiary earnings................................ (478.5) (248.5) (363.7)
Working capital and other changes, excluding changes relating to cash and
non-operating activities:
Receivables................................................... (3.5) 2.8 1.8
Prepaid expenses and other.................................... .8 (1.2) (.5)
Accounts payable and accrued expenses......................... 43.1 (54.4) 82.6
Other......................................................... (86.4) (75.6) (39.9)
--------- --------- ---------
(51.5) 44.9 47.4
--------- --------- ---------
Cash Flow from Investing Activities:
Purchases of property, plant and equipment.......................... - (.2) (.1)
Net change in accounts with subsidiaries............................ (865.5) (113.6) 143.2
Investments in subsidiaries......................................... (13.2) (120.3) (2.5)
Discontinued operations............................................. (22.7) - -
--------- --------- ---------
(901.4) (234.1) 140.6
--------- --------- ---------
Cash Flow from Financing Activities:
Increase in short-term notes........................................ 93.9 123.0 259.0
Proceeds from issuing common stock.................................. 14.7 5.5 7.3
Proceeds from long-term debt issues................................. 1,044.6 406.9 523.4
Redemption of preferred stock....................................... - (200.0) -
Payments to retire long-term debt................................... (225.8) (10.6) (933.1)
Dividends paid...................................................... (53.6) (56.5) (59.7)
--------- --------- ----------
873.8 268.3 (203.1)
--------- --------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents................... (79.1) 79.1 (15.1)
Cash and Cash Equivalents at Beginning of Year......................... 79.6 .5 15.6
--------- --------- ---------
Cash and Cash Equivalents at End of Year............................... $ .5 $ 79.6 $ .5
========= ========= =========
</TABLE>
See Notes to Condensed Financial Statements.
S-4
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT
THE COASTAL CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS
Note 1. Summary of Significant Accounting Policies
Principles of Consolidation - The financial statements of the Company
reflect the investment in wholly owned subsidiaries using the equity method.
Statement of Cash Flows - For purposes of this statement, cash equivalents
include time deposits, certificates of deposit and all highly liquid instruments
with original maturities of three months or less. The Company made cash payments
for interest and financing fees of $225.0 million, $173.6 million and $178.5
million in 1999, 1998 and 1997, respectively. Cash payments (refunds - primarily
from subsidiaries) for income taxes amounted to $(15.2) million, $8.5 million
and $(97.9) million for 1999, 1998 and 1997, respectively.
Federal Income Taxes - The Company follows the liability method of
accounting for income taxes as required by the provisions of Statement of
Financial Accounting Standards No. 109, "Accounting for Income Taxes."
The Company files a consolidated federal income tax return with its wholly
owned subsidiaries. Members of the consolidated group with taxable incomes are
charged with the amount of income taxes as if they filed separate federal income
tax returns, and members providing deductions and credits which result in income
tax savings are allocated credits for such savings.
Note 2. Consolidated Financial Statements
Reference is made to the Consolidated Financial Statements and related
Notes of Coastal and Subsidiaries for additional information.
Note 3. Debt and Guarantees
Information on the debt of the Company is disclosed in Note 4 of the Notes
to Consolidated Financial Statements included herein. The Company has guaranteed
certain long-term debt of its subsidiaries and certain other obligations arising
in the ordinary course of business. Approximately $407.0 million of guaranteed
long-term debt of subsidiaries was outstanding at December 31, 1999, including
current maturities. The Company and certain of its subsidiaries have entered
into interest rate swaps with major banking institutions. The Company is exposed
to loss if one or more counterparties default. In addition, the Company or
certain of its subsidiaries are guarantors on certain bank loans of
corporations, joint ventures and partnerships in which the Company or certain
subsidiaries have equity interests. Information on the guarantees and swaps is
disclosed in Notes 4 and 7, respectively, of the Notes to Consolidated Financial
Statements.
The aggregate amounts of long-term debt maturities of Coastal for the five
years following 1999 are (Millions of Dollars):
2000............. $151.3 2003............ $102.3
2001............. 104.1 2004............ 697.7
2002............. 250.0
Note 4. Dividends Received
Cash dividends received from consolidated subsidiaries were as follows:
1999 - $39.2 million, 1998 - $207.1 million and 1997 - $61.1 million.
S-5
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(Millions of Dollars)
<TABLE>
<CAPTION>
Additions
Balance at Charged to Balance
Beginning Costs and at End
Description of Year Expenses Other of Year
- -----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Year Ended December 31, 1999
Allowance for doubtful accounts.................... $15.9 $ 4.3 $(2.8)(A) $ 17.4
===== ===== ===== =======
Year Ended December 31, 1998
Allowance for doubtful accounts.................... $16.6 $ 4.0 $(4.7)(A) $ 15.9
===== ===== ===== =======
Year Ended December 31, 1997
Allowance for doubtful accounts.................... $23.4 $ 4.0 $(10.8)(A) $ 16.6
===== ===== ====== =======
<FN>
- --------
(A) Accounts charged off net of recoveries.
</FN>
</TABLE>
S-6
<PAGE>
EXHIBIT INDEX
Exhibit
Number Document
- ------- -----------------------------------------------------------------
3.1+ Restated Certificate of Incorporation of Coastal, as restated on
March 22, 1994. (Filed as Module TCC-Artl-Incorp on March 28,
1994).
3.2+ By-Laws of Coastal, as amended on January 16, 1990 (Exhibit 3.4 to
Coastal's Annual Report on Form 10-K for the fiscal year ended
December 31, 1989).
4 (With respect to instruments defining the rights of holders of
long-term debt, the Registrant will furnish to the Commission, on
request, any such documents).
10.1+ 1985 Stock Option Plan (Appendix A to Coastal's Proxy Statement
for the 1986 Annual Meeting of Stockholders, dated March 27,
1986).
10.2+ The Coastal Corporation Performance Unit Plan effective as of
January 1, 1987 (Exhibit 10.5 to Coastal's Annual Report on Form
10-K for the fiscal year ended December 31, 1987).
10.3+ The Coastal Corporation Replacement Pension Plan effective as of
November 1, 1987 (Exhibit 10.6 to Coastal's Annual Report on Form
10-K for the fiscal year ended December 31, 1987).
10.4+ Description of Coastal's Key Employees Bonus Plan (Exhibit 10.7 to
Coastal's Annual Report on Form 10-K for the fiscal year ended
December 31, 1987).
10.5+ The Coastal Corporation Dividend Reinvestment and Stock Purchase
Plan, dated July 9, 1996 (Exhibit 10 to Coastal's Form S-3 filed
on July 15, 1996).
10.6+ The Coastal Corporation Amended and Restated Stock Grant Plan,
effective October 9, 1997. (Exhibit 10.7 to Coastal's Annual
Report on Form 10-K for the fiscal year ended December 31, 1997.)
10.7+ The Coastal Corporation Amended and Restated Deferred Compensation
Plan for Directors, effective October 9, 1997. (Exhibit 10.8 to
Coastal's Annual Report on Form 10-K for the fiscal year ended
December 31, 1997.)
10.8+ The Coastal Corporation 1990 Stock Option Plan (Exhibit 10.13 to
Coastal's Annual Report on Form 10-K for the fiscal year ended
December 31, 1989).
10.9+ The Coastal Corporation 1997 Directors Stock Plan, effective June
5, 1997. (Exhibit 10.10 to Coastal's Annual Report on Form 10-K
for the fiscal year ended December 31, 1997.)
10.10+ The Coastal Corporation Deferred Compensation Plan (Exhibit 10.14
to Coastal's Annual Report on Form 10-K for the fiscal year ended
December 31, 1993).
10.11+ The Coastal Corporation 1994 Incentive Stock Plan (Appendix A to
Coastal's Proxy Statement for the 1994 Annual Meeting of
Stockholders dated March 29, 1994).
10.12+ Pension Plan for Employees of The Coastal Corporation as of
January 1, 1993, includes Plan as Restated as of January 1, 1989
and First Amendment dated July 27, 1992, Second Amendment dated
December 9, 1992, Third Amendment dated October 29, 1993 (Exhibit
10.16 to Coastal's Annual Report on Form 10-K for the fiscal year
ended December 31, 1993).
- -------------------------
Note:
+ Indicates documents incorporated by reference from the prior filing
indicated.
<PAGE>
EXHIBIT INDEX
Exhibit
Number Document
- ------- -----------------------------------------------------------------
10.13+ Pension Plan for Employees of The Coastal Corporation as of
January 1, 1993, as further amended by the Fourth Amendment dated
May 20, 1994, Fifth Amendment dated August 17, 1994, Sixth
Amendment dated August 30, 1994, Seventh Amendment dated October
30, 1995, Eighth Amendment dated December 29, 1995 and Ninth
Amendment dated December 29, 1995 (Exhibit 10.14 to Coastal's
Annual Report on Form 10-K for the fiscal year ended December 31,
1995).
10.14+ Pension Plan for Employees of The Coastal Corporation as of
January 1, 1993, as further amended by the Tenth Amendment dated
March 25, 1996 (Exhibit 10.15 to Coastal's Quarterly Report on
Form 10-Q for the period ended March 31, 1996).
10.15+ Pension Plan for Employees of The Coastal Corporation as of
January 1, 1993, as further amended by the Twelfth Amendment dated
August 29, 1996 and the Thirteenth Amendment dated September 16,
1996 (Exhibit 10.16 to Coastal's Quarterly Report on Form 10-Q for
the period ended September 30, 1996).
10.16+ Pension Plan for Employees of The Coastal Corporation as of
January 1, 1993, as further amended by the Eleventh Amendment
dated December 6, 1996. (Exhibit 10.17 to Coastal's Annual Report
on Form 10-K for the fiscal year ended December 31, 1997.)
10.17+ Pension Plan for Employee of The Coastal Corporation as of January
1, 1993, as further amended by the Fourteenth Amendment dated
December 31, 1997. (Exhibit 10.18 to Coastal's Annual Report on
Form 10-K for the fiscal year ended December 31, 1997.)
10.18+ Agreement for Consulting Services between The Coastal Corporation
and Oscar S. Wyatt, Jr. dated August 1, 1997. (Exhibit 10.19 to
Coastal's Annual Report on Form 10-K for the fiscal year ended
December 31, 1997.)
10.19+ The Coastal Corporation 1998 Incentive Stock Plan, effective March
19, 1998 (Appendix A to Coastal's Proxy Statement for the 1998
Annual Meeting of Stockholders dated March 26, 1998).
10.20* Employment Agreement between David A. Arledge and The Coastal
Corporation dated as of April 1, 1999.
10.21* Form of employment agreement for an Employment Agreement between
The Coastal Corporation and each of Coby C. Hesse and Gene T.
Waguespack, dated January 17, 2000.
10.22* Form of employment agreement for an Employment Agreement between
The Coastal Corporation and each of James A. King, Jeffrey A.
Connelly, Carl A. Corrallo, Rodney D. Erskine, Donald H.
Gullquist, Dan J. Hill, Austin M. O'Toole, Keith O. Rattie, James
L. Van Lanen and Thomas M. Wade, dated January 17, 2000.
11* Statement re Computation of Per Share Earnings.
21* Subsidiaries of Coastal.
23* Consent of Deloitte & Touche LLP.
24* Powers of Attorney (included on signature pages herein).
27* Financial Data Schedule.
99+ Indemnity Agreement revised and updated as of April, 1988 (Exhibit
28 to Coastal's Annual Report on Form 10-K for the fiscal year
ended December 31, 1990).
- -------------------------
Note:
+ Indicates documents incorporated by reference from the prior filing
indicated.
* Indicates documents filed herewith.
<PAGE>
Exhibit 10.20
EMPLOYMENT AGREEMENT
between
DAVID A. ARLEDGE
and
THE COASTAL CORPORATION
<PAGE>
EMPLOYMENT AGREEMENT
EMPLOYMENT AGREEMENT dated as of April 1, 1999 (the "Agreement") between The
Coastal Corporation, a Delaware corporation ("Company"), and David A. Arledge
("Executive").
WHEREAS, the Company desires to employ Executive as its Chairman and Chief
Executive Officer upon the terms and subject to the conditions set forth herein;
NOW, THEREFORE, in consideration of the premises and the mutual agreements
contained herein, the Company and Executive hereby agree as follows:
ARTICLE 1
DEFINITIONS
The terms set forth below have the following meanings (such meanings to be
applicable to both the singular and plural forms, except where otherwise
expressly indicated):
1.1 "Accrued Annual Bonus" means the amount of any Annual Bonus earned but not
yet paid with respect to the Year ended prior to the Date of Termination.
1.2 "Accrued Base Salary" means the amount of Executive's Base Salary which is
accrued but not yet paid as of the Date of Termination.
1.3 "Affiliate" means any Person directly or indirectly controlling, controlled
by, or under direct or indirect common control with, the Company. For the
purposes of this definition, the term "control" when used with respect to
any Person means the power to direct or cause the direction of management
or policies of such Person, directly or indirectly, whether through the
ownership of voting securities, by contract or otherwise.
1.4 "Agreement" - see the recitals to this Agreement.
1.5 "Agreement Date" means the date that is specified in the recitals to this
Agreement.
1.6 "Anniversary Date" means any annual anniversary of the Agreement Date.
1.7 "Annual Bonus" - see Section 4.2(a).
1.8 "Annualized Total Compensation" means, as of any date, the sum of
Executive's (i) Base Salary as of such date and (ii)Target Annual Bonus (in
no event shall such
- 2 -
<PAGE>
Target Annual Bonus be less than the most recently awarded Annual Bonus)
applicable to the Year that includes such date.
1.9 "Base Salary" - see Section 4.1.
1.10 "Beneficiary" - see Section 10.3.
1.11 "Board" means the Board of Directors of the Company.
1.12 "Cause" means any of the following:
(a) Executive's conviction of a felony or of a misdemeanor involving
fraud, dishonesty or moral turpitude, or
(b) Executive's willful or intentional material breach of this Agreement
that results in financial detriment that is material to the Company
and its Affiliates taken as a whole.
For purposes of clause (b) of the preceding sentence, Cause shall not include
any one or more of the following:
(i) bad judgment,
(ii) negligence,
(iii) any act or omission that Executive believed in good faith to
have been in or not opposed to the interest of the Company
(without intent of Executive to gain therefrom, directly or
indirectly, a profit to which he was not legally entitled), or
(iv) any act or omission of which any member of the Board who is not
a party to such act or omission has had actual knowledge for at
least 12 months.
1.13 "Change of Control" mean any of the following events:
(a) any person or group (as such terms are used in Rule 13d-5 under the
Exchange Act and defined in Sections 3(a)(9) and 13(d)(3) of the
Exchange Act), other than a Subsidiary or any employee benefit plan
(or any related trust) of the Company or a Subsidiary, becomes the
beneficial owner of 15% or more of the Common Stock or of securities
of the Company that are entitled to vote generally in the election of
directors of the Company ("Voting Securities") representing 15% or
more of the combined voting power of all Voting Securities of the
Company.
- 3 -
<PAGE>
(b) individuals who, as of the Agreement Date, constitute the Board (the
"Incumbent Directors") cease for any reason to constitute a majority
of the members of the Board; provided that any individual who becomes
a director after the Agreement Date whose election or nomination for
election by the Company's shareholders was approved by a majority of
the members of the Incumbent Board (other than an election or
nomination of an individual whose initial assumption of office is in
connection with an actual or threatened "election contest" relating
to the election of the directors of the Company (as such terms are
used in Rule 14a-11 under the Exchange Act), "tender offer" (as such
term is used in Section 14(d) of the Exchange Act) or a proposed
Merger (as defined below)) shall be deemed to be members of the
Incumbent Board; or
(c) approval by the stockholders of the Company of either of the
following:
(i) a merger, reorganization, consolidation or similar transaction
(any of the foregoing, a "Merger") as a result of which the
Persons who were the respective beneficial owners of the
outstanding Common Stock and Voting Securities of the Company
immediately before such Merger are not expected to
beneficially own, immediately after such Merger, directly or
indirectly, more than 60% of, respectively, the common stock
and the combined voting power of the Voting Securities of the
corporation resulting from such Merger in substantially the
same proportions as immediately before such Merger, or
(ii) a plan of liquidation of the Company or a plan or agreement
for the sale or other disposition of all or substantially all
of the assets of the Company.
Notwithstanding the foregoing, there shall not be a Change in Control if, in
advance of such event, Executive agrees in writing that such event shall not
constitute a Change in Control.
1.14 "Code" means the Internal Revenue Code of 1986, as amended from time to
time.
1.15 "Committee" means the Compensation and Executive Development Committee of
the Board.
1.16 "Common Stock" means the common stock and Class A common stock of the
Company.
1.17 "Company" - see the recitals to this Agreement.
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1.18 "Date of Termination" means the effective date of a Termination of
Employment for any reason, including death or Disability, whether by either
of the Company or by Executive.
1.19 "Disability" means a mental or physical condition which, in the opinion of
the Board, renders Executive unable or incompetent to carry out the
material job responsibilities which such Executive held or the material
duties to which Executive was assigned at the time the disability was
incurred, which has existed for at least three months, and which in the
opinion of a physician mutually agreed upon by the Company and Executive
(provided that neither party shall unreasonably withhold his agreement) is
expected to be permanent or to last for an indefinite duration or a
duration in excess of six months.
1.20 "Employment Period" - see Section 3.1.
1.21 "Exchange Act" means the Securities Exchange Act of 1934.
1.22 "Executive" - see the recitals to this Agreement.
1.23 "Fair Market Value" means, as of any date, (a) the average of the high and
low prices of the Common Stock on such date reported on principal national
securities exchange on which the Common Stock is then listed (or, if no
sale of the Common Stock was reported for such date, on the next preceding
date on which such a sale of such security was reported), (b) if the Common
Stock is not listed on any national securities exchange, the average of the
high bid and low asked quotations for the Common Stock on such date in the
over-the-counter market (or, if no quotation of the Common Stock was
reported for such date, on the next preceding date on which such a
quotation of such security was reported), or (c) if there is no public
market for the Common Stock, the fair market value of the Common Stock
determined by the Committee in the good faith exercise of its discretion.
1.24 "Good Reason" means the occurrence of any one or more of the following
events unless Executive specifically agrees in writing that such event
shall not be Good Reason:
(a) any material breach of this Agreement by the Company, including:
(i) the failure of the Company to comply with the provisions of
Articles II, III, IV, V, VI or VII of this Agreement;
(ii) any material adverse change in the status, responsibilities
or perquisites of Executive;
(iii) any failure to nominate or elect Executive as Chairman and
Chief Executive Officer of the Company and as member of the
Board;
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(iv) causing or requiring Executive to report to anyone other than
the Board; or
(v) assignment of duties materially inconsistent with his position
and duties described in this Agreement,
(b) the failure of the Company to assign this Agreement to a successor to
the Company or failure of a successor to the Company to explicitly
assume and agree to be bound by this Agreement,
(c) requiring Executive to be principally based at any office or location
more than 25 miles from the current offices of the Company in Houston,
Texas,
(d) the delivery to Executive of a Notice of Consideration pursuant to
Section 8.1(b) if, within a period of 90 days thereafter, the Board
fails for any reason to terminate Executive for Cause in compliance
with all of the substantive and procedural requirements of Section
8.1, or
(e) a Termination of Employment by Executive for any reason or no reason
during the 30-day period commencing 12 months after a Change of
Control.
Any reasonable determination by Executive that any of the foregoing events has
occurred and constitutes Good Reason shall be conclusive and binding for all
purposes.
1.25 "including" means including without limitation.
1.26 "Notice of Consideration" - see Section 8.1(b).
1.27 "Option" means an option to purchase shares of Common Stock.
1.28 "Person" means any individual, sole proprietorship, partnership, joint
venture, trust, unincorporated organization, association, corporation,
institution, public benefit corporation, entity or government
instrumentality, division, agency, body or department.
1.29 "Prorata Annual Bonus" means (a) the product of the amount of the Target
Annual Bonus to which Executive would have been entitled if he had been
employed by the Company on the last day of the Year that includes the Date
of Termination and if Executive had achieved his Target Annual Goals for
such Year, multiplied by (b) a fraction of which the numerator is the
numbers of days which have elapsed in such Year through the Date of
Termination and the denominator is 365.
1.30 "Replacement Pension Plan" - see Section 7.1.
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1.31 "Severance Payment" means the payment of a multiple of Executive's
Annualized Total Compensation pursuant to Section 8.3(b) or Section 8.4, as
applicable.
1.32 "Severance Period" means the interval of time between the Date of
Termination and the expiration of the Employment Period, without giving
effect to any Termination of Employment; provided that, for purposes of
Section 8.3, the Severance Period shall in no event be less than 2.99 years
if a Termination of Employment occurs after a Change of Control.
1.33 "Subsidiary" means, with respect to any Person, (a) any corporation of
which more than 50% of the outstanding capital stock having ordinary voting
power to elect a majority of the board of directors of such corporation
(irrespective of whether, at the time, stock of any other class or classes
of such corporation shall have or might have voting power by reason of the
happening of any contingency) is at the time, directly or indirectly, owned
by such Person, and (b) any partnership in which such Person has a direct
or indirect interest (whether in the form of voting or participation in
profits or capital contribution) of more than 50%.
1.34 "Target Annual Bonus" - see Section 4.2.
1.35 "Target Annual Goal" - see Section 4.2.
1.36 "Taxes" means the incremental United States federal, state and local
income, excise and other taxes payable by Executive with respect to any
applicable item of income.
1.37 "Tax Gross-Up Payment" means an amount payable to Executive such that,
after payment of Taxes on such amount, there remains a balance sufficient
to pay the Taxes being reimbursed.
1.38 "Termination For Good Reason" means a Termination of Employment by
Executive for a Good Reason.
1.39 "Termination of Employment" means a termination by the Company or by
Executive of Executive's employment by the Company.
1.40 "Termination Without Cause" means a Termination of Employment by the
Company for any reason other than Cause or Executive's death or Disability.
1.41 "Withholding Taxes" means any United States federal, state, local or
foreign withholding taxes and other deductions required to be paid in
accordance with applicable law by reason of compensation received pursuant
to this Agreement.
1.42 "Year" means a calendar year period ending on December 31.
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ARTICLE 2
DUTIES
2.1 Duties. The Company shall employ Executive during the Employment Period as
its Chairman and Chief Executive Officer. It is contemplated that, in
connection with each applicable annual meeting of shareholders (or action
by written consent in lieu thereof) of the Company during the Employment
Period, the Board will nominate Executive for election as a member of the
Board, and the shareholders of the Company will reelect Executive as a
member of the Board. During the Employment Period, Executive shall perform
the duties properly assigned to him hereunder, shall devote substantially
all of his business time, attention and effort to the affairs of the
Company and shall use his reasonable best efforts to promote the interests
of the Company. During the Employment Period, and excluding any periods of
disability, vacation, or sick leave to which Executive is entitled,
Executive agrees to devote his full attention and time to the business and
affairs of the Company.
2.2 Other Activities. Executive may serve on corporate, civic or charitable
boards or committees, deliver lectures, fulfill speaking engagements, teach
at educational institutions, or manage personal investments; provided that
such activities do not individually or in the aggregate significantly
interfere with the performance of his duties under this Agreement.
ARTICLE 3
EMPLOYMENT PERIOD
3.1 Employment Period. Subject to Section 3.2 and the termination provisions
hereinafter provided, the term of Executive's employment under this
Agreement (the "Employment Period") shall begin on the Agreement Date and
end on the Anniversary Date which is three years after such date. The
employment of Executive by the Company shall not be terminated other than
in accordance with Article VIII.
3.2 Extensions of Employment Period. The Employment Period shall terminate on
the later of the (a) Anniversary Date specified in Section 3.1 or (b) the
date which is three years after the date on which the Company delivers to
the Executive, or the Executive delivers to the Company, a written notice
that the Employment Period will not be extended.
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ARTICLE 4
COMPENSATION
4.1 Salary. The Company shall pay Executive in accordance with its normal
payroll practices (but not less frequently than monthly) an annual salary
at a rate of $725,000 per year ("Base Salary"). During the Employment
Period, the Base Salary shall be reviewed at least annually by the
Committee after consultation with Executive and may from time to time be
increased as determined by the Committee. Effective as of the date of any
such increase the Base Salary as so increased shall be considered the new
Base Salary for all purposes of this Agreement and may not thereafter be
reduced. Any increase in Base Salary shall not limit or reduce any other
obligation of the Company to Executive under this Agreement.
4.2 Annual Bonus.
(a) The Company shall pay to Executive an annual cash bonus ("Annual
Bonus") in accordance with the terms hereof for each Year which
begins during the Employment Period. Executive shall be eligible for
an Annual Bonus pursuant to the Executive Bonus Program of the
Company administered by the Committee.
(b) The Company performance goals are determined annually by the Company.
These performance goals are expressed as target performance ("Target
Annual Goal"). The level of bonus awarded to the Executive pursuant
to the Executive Bonus Program shall be determined by the Committee
and will vary based upon the level of Company performance with the
target bonus award for attainment of Target Annual Goals (the "Target
Annual Bonus").
(c) In the event that it is necessary to determine the bonus due the
Executive for less than a full year, then if the bonus due pursuant
to terms of this Agreement is the Target Annual Bonus, the Executive
shall be entitled to a bonus equal to the Target Annual Bonus amount
pursuant to the Executive Bonus Program of the Company for the
preceding Year had the Target Annual Goal been met, regardless of
whether such Target Annual Goal was met. In no event shall such
Target Annual Bonus be less than the most recently awarded Annual
Bonus. The bonus calculated pursuant to this Section 4.2(c) shall be
prorated for the portion of the year for which such bonus is due.
The Committee may increase this amount in its discretion.
(d) The Company shall pay the entire Annual Bonus that is payable with
respect to a Year in a lump-sum cash payment as soon as practicable
after the Committee can determine whether and the degree to which
Target Annual Goal has been achieved following the close of such Year.
Any such Annual Bonus shall in any event be paid within 120 days
after the end of the Year.
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ARTICLE 5
STOCK OPTIONS AND GRANTS
5.1 Participation. The Executive shall be eligible to participate in stock
option plans and similar programs offered by the Company to its key
employees.
5.2 Terms and Conditions of Options. The terms and conditions of the programs
discussed in Section 5.1 shall be established by the provisions of such
programs. All stock options held by the Executive at the date of this
Agreement and all stock options granted in the future:
(a) shall become exercisable in whole or in any part, upon the death or
Disability of Executive, a Termination Without Cause, a Termination
for Good Reason, or a Change of Control;
(b) shall in other respects be on terms and conditions that are no less
favorable to Executive than the terms and conditions
applicable to Options granted at or about the same time to
other senior executives of the Company; and
(c) shall be cancelled in the event of a merger or consolidation pursuant
to the terms of which cash is to be paid for each share of Common
Stock then outstanding, such cancellation to be effective immediately
before the consummation of such merger or consolidation, subject to
the immediate payment by the Company of a cash amount to Executive
equal to the Option Spread (as defined below). The "Option Spread"
applicable to an Option shall equal the product of the number of
shares of Common Stock subject to such Option multiplied by the
positive difference, if any, between the cash amount to be paid for
each share of Common Stock in such merger or consolidation and the
exercise price of such Option.
5.3 Terms and Conditions of Options - Remedy.
(a) In the event that the provisions of Section 5.2(a) are met so that
options would become exercisable pursuant to Section 5.2(a) and such
options do not become exercisable for any reason (including failure
of any person or group to exercise discretionary authority pursuant
to provisions of a plan or program), then Executive (or, in the event
of death, his Beneficiary) shall receive immediately after
Termination Without Cause, Termination for Good Reason, Change in
Control, Disability or death of the Executive, a lump sum amount in
immediately available funds equal to the total amount (if any) of the
market value of the number of shares of stock for which options should
have, but did not, become exercisable reduced by the amount of the
exercise price of such shares of stock.
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(b) In the event that the provisions of Section 5.2(c) are met so that
options would be cancelled pursuant to Section 5.2(c) and such options
are not cancelled for any reason (including failure of any person or
group to exercise discretionary authority pursuant to provisions of a
plan or program) then, if the Executive so requests in writing, he
shall receive payment by the Company of the amount specified in
Section 5.2(c) and the Executive shall not exercise such options which
were not cancelled.
ARTICLE 6
OTHER BENEFITS
6.1 Incentive, Savings and Retirement Plans. In addition to Base Salary and an
Annual Bonus, Executive shall be entitled to participate during the
Employment Period in all incentive, savings and (except as otherwise
provided in Section 7.3) retirement plans, practices, policies and programs
that are from time to time applicable to other senior executives of the
Company.
6.2 Welfare Benefits. During the Employment Period, Executive and/or his
family, as the case may be, shall be eligible for participation in and
shall receive all benefits under welfare benefit plans, practices, policies
and programs provided by the Company (including medical, prescription,
dental, disability, salary continuance, employee life, group life,
dependent life, accidental death and travel accident insurance plans and
programs) applicable to other senior executives of the Company. After
Termination of Employment by reason of a Termination Without Cause or a
Termination for Good Reason, the Executive and/or his family, as the case
may be, shall be eligible for participation in and shall receive all
benefits under welfare benefit plans, practices and programs provided by
the Company (including medical, prescription and life insurance plans and
programs) applicable to other former employees including former senior
executives of the Company who retire from the Company at the time of
Termination of Employment of the Executive (or if earlier, at the time of a
Change in Control) provided that the requirements for the retiree medical
program (medical and prescription coverage) and participant contributions
for such coverage shall be modified as follows: (a) the requirement to
immediately receive monthly retirement income from a pension plan
maintained by the Company shall be met if the Executive begins immediately
to receive such payments from The Coastal Corporation Replacement Pension
Plan and (b) the contribution rate for the Executive and/or his family, as
the case may be, for coverage shall be calculated based upon years of
service credited for purposes of determining the benefit due from The
Coastal Corporation Replacement Pension Plan.
6.3 Fringe Benefits. During the Employment Period, Executive shall be entitled
to all fringe benefits that are from time to time available to other senior
executives of the Company.
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6.4 Vacation. During the Employment Period, Executive shall be entitled to paid
vacation time in accordance with the plans, practices, policies, and
programs applicable to other senior executives of the Company.
6.5 Expenses. During the Employment Period, Executive shall be entitled to
receive prompt reimbursement for all reasonable employment-related expenses
incurred by Executive upon the receipt by the Company of accounting in
accordance with practices, policies and procedures applicable to other
senior executives of the Company.
6.6 Office; Support Staff. During the Employment Period, Executive shall be
entitled to an office or offices of a size and with furnishings and other
appointments, and to personal secretarial and other assistance, appropriate
to his position and duties under this Agreement. After Termination of
Employment, Executive shall be entitled to an office or offices of a size
and with furnishings and other appointments, and to personal secretarial
and other assistance, pursuant to the established policy of the Company
with respect to former Chairman.
6.7 Tax Gross-Up Payment. If it shall be determined that any payment to
Executive pursuant to this Agreement or any other payment or benefit from
the Company, any Affiliate, any shareholder of the Company or any other
person would be subject to the excise tax imposed by Section 4999 of the
Code or any similar tax payable under any United States federal, state,
local or other law, then Executive shall receive a Tax Gross-Up Payment
with respect to all such excise taxes and similar taxes.
ARTICLE 7
SUPPLEMENTAL RETIREMENT BENEFIT
7.1 Supplemental Retirement Benefit. Executive shall be entitled to a
nonqualified supplemental retirement benefit pursuant to The Coastal
Corporation Replacement Pension Plan (the "Replacement Pension Plan")
provided, however, that the method used to calculate the benefit due the
Executive shall be modified as stated in Section 7.2 of this Agreement for
determining benefits under the Replacement Pension Plan in the event of a
Termination of Employment by reason of his death or Disability, a
Termination Without Cause, or a Termination for Good Reason.
7.2 Replacement Pension Plan Benefit Modification. For purposes of Section
7.1 of this Agreement, the benefit calculation method and the age at which
benefit payments may begin under the Replacement Pension Plan shall be
modified as follows: (a) the Basic Compensation (as defined in the
Replacement Pension Plan) used to determine the five year average for
purposes of determining Final Average Earnings (as defined in the
Replacement Pension Plan) shall be (i) Base Salary (as defined in this
Agreement) in effect on the Date of Termination (reduced, if necessary, to
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comply with the Replacement Pension Plan limitation of $500,000 as indexed)
for 3 of the 5 years, and (ii) Base Salary (as defined in this Agreement)
in effect for the two calendar years preceding the Date of Termination
(reduced, if necessary, to comply with the Replacement Pension Plan
limitation of $500,000 as indexed); provided, however, that if one of such
two years is 1998, then Basic Compensation (as defined in the Replacement
Pension Plan) shall be used in lieu of Base Salary for such year; and
provided, further, that if one of such 2 years is 1997, then Basic
Compensation (as defined in the Replacement Pension Plan and modified to
insert $500,000 in lieu of $160,000) shall be used in lieu of Base Salary
for such year; (b) Years of Service (as defined in the Replacement Pension
Plan) shall be increased to include the Severance Period (as defined in
this Agreement); and (c) the age of the Executive shall be equal to the sum
of his actual age and the Severance Period (as defined in this Agreement).
7.3 Other Supplemental Retirement Benefits. Executive shall not participate in,
or be entitled to benefits under, any other supplemental defined benefit
retirement plans of the Company which are not qualified under Section
401(a) of the Code, except as otherwise provided in writing by the Company.
ARTICLE 8
TERMINATION BENEFITS
8.1 Termination for Cause or Other Than for Good Reason. etc.
(a) If the Company terminates Executive's employment for Cause or
Executive terminates his employment other than for Good Reason, death
or Disability, the Company shall pay to Executive immediately after
the Date of Termination an amount equal to the sum of Executive's
Accrued Base Salary and Accrued Annual Bonus, and Executive shall not
be entitled to receive any Severance Payment.
(b) The Company may not terminate Executive's employment for Cause unless:
(i) no fewer than 60 days prior to the Date of Termination, the
Company provides Executive with written notice (the "Notice of
Consideration") of its intent to consider termination of
Executive's employment for Cause, including a detailed
description of the specific reasons which form the basis for
such consideration;
(ii) for a period of not less than 30 days after the date Notice of
Consideration is provided, Executive shall have the
opportunity to appear before the Board, with or without legal
representation, at Executive's election, to present arguments
and evidence on his own behalf; and
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(iii) following the presentation to the Board as provided in (ii)
above or Executive's failure to appear before the Board and
date and time specified in the Notice of Consideration (which
date shall not be less than 30 days after the date the Notice
of Consideration is provided), Executive may be terminated for
Cause only if (x) the Board, by the affirmative vote of all of
its members (excluding Executive if he is a member of the
Board, and any other member of the Board reasonably believed
by the Board to be involved in the events leading the Board to
terminate Executive for Cause), determines that the actions or
inactions of Executive specified in the Notice of Termination
occurred, that such actions or inactions constitute Cause, and
that Executive's employment should accordingly be terminated
for Cause; and (y) the Board provides Executive with a written
determination (a "Notice of Termination for Cause") setting
forth in specific detail the basis of such Termination of
Employment, which Notice of Termination for Cause shall be
consistent with the reasons set forth in the Notice of
Consideration.
Unless the Company establishes both (i) its full compliance with the substantive
and procedural requirements of this Section 8.1 prior to a Termination of
Employment for Cause, and (ii) that Executive's action or inaction specified in
the Notice of Termination for Cause did occur and constituted Cause, any
Termination of Employment shall be deemed a Termination Without Cause for all
purposes of this Agreement.
(c) After providing a Notice of Consideration pursuant to the provisions
of Section 8.1(b), the Board may, by the affirmative vote of all of
its members (excluding for this purpose Executive if he is a member
of the Board, and any other member of the Board reasonably believed
by the Board to be involved in the events issuing the Notice of
Consideration), suspend Executive with pay until a final
determination pursuant to such Section 8.1(b) has been made.
8.2 Termination for Death or Disability. If Executive's employment terminates
during the Employment Period due to his death or Disability, the Company
shall pay to Executive or his Beneficiaries, as the case may be,
immediately after the Date of Termination an amount which is equal to the
sum of Executive's Accrued Base Salary, Accrued Annual Bonus and Prorata
Annual Bonus.
8.3 Termination Without Cause or for Good Reason. In the event of a Termination
Without Cause or a Termination for Good Reason (whether during of after the
Employment Period), Executive shall receive the following:
(a) immediately after the Date of Termination, a lump-sum amount in
immediately available funds equal to the sum of Executive's Accured
Base Salary, Accrued Annual Bonus and Prorata Annual Bonus;
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(b) immediately after the Date of Termination, a lump-sum amount in
immediately available funds equal to the product of the number of
whole and fractional years included in the Severance Period
multiplied by Executive's Annualized Total Compensation;
(c) immediately after the Date of Termination, a lump-sum amount in
immediately available funds equal to the total amount (if any)
of Executive's unvested benefits under any plan or program sponsored
by the Company which is forfeited on account of Executive's employment
being terminated;
(d) the continuation of the benefits (or, if such benefits are not
available, the after-tax economic equivalent thereof) specified in
Sections 6.1, 6.2 and 6.3 as available during the Employment Period
to which Executive is entitled as of the Date of Termination for the
entire duration of the Severance Period or, at the election of
Executive, an immediate lump-sum cash payment equal to the value of
such benefits; provided that with respect to any benefit to be
provided on an insured basis, such value shall be the present value
of the premiums expected to be paid for such coverage, and with
respect to other benefits, such value shall be the present value of
the expected net cost to the Company of providing such benefits; and
(e) immediately after the Date of Termination, a lump-sum amount in
immediately available funds of any amount then payable to Executive
pursuant to Section 6.7.
8.4 Termination After a Change of Control. If a Termination Without Cause or a
Termination for Good Reason occurs within two years after a Change of
Control, then Executive shall receive the payments required by Section
8.3, except that for purposes of Section 8.3(b), Executive shall receive a
multiple of 2.99 times his Annualized Total Compensation.
8.5 Other Termination Benefits. In addition to any amounts or benefits payable
upon a Termination of Employment hereunder, Executive shall, except as
otherwise specifically provided herein, be entitled to any payments or
benefits provided hereunder or under the terms of any plan, policy or
program of the Company or as otherwise required by applicable law.
ARTICLE 9
RESTRICTIVE COVENANTS
9.1 Non-Solicitation of Employees: Confidentiality: Non-Competition.
(a) Executive covenants and agrees that, at no time during the period
employed pursuant to this Agreement nor during the one-year period
immediately
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following a Termination of Employment by the Company for Cause or by
Executive other than for Good Reason, death or Disability, will
Executive:
(i) directly or indirectly employ or seek to employ any person
employed at that time by the Company or any of its Subsidiaries
or otherwise encourage or entice any such person to leave such
employment;
(ii) become employed by, enter into a consulting arrangement with
or otherwise agree to perform personal services for a
Competitor (as defined in Section 9.1 (b));
(iii) acquire an ownership interest in a Competitor, or
(iv) solicit any customers or vendors of the Company on behalf of
or for the benefit of a Competitor.
(b) For purposes of this Section, "Competitor" means any Person which
sells goods or services which are directly competitive with those
sold by a business that (i) is being conducted by the Company or any
Subsidiary at the time in question and (ii) was being conducted at
the Date of Termination and, for the Company's most recently-completed
fiscal year, contributed more than 10% of the Company's consolidated
revenues. Notwithstanding anything to the contrary in this Section,
goods or services shall not be deemed to be competitive with those of
the Company (A) solely as a result of Executive being employed by or
otherwise associated with a business of which a unit is in
competition with the Company or any Subsidiary but as to which unit
Executive does not have direct or indirect responsibilities for the
products or services involved or (B) if the activity contributes less
than 10% of the consolidated revenues for the most recently-completed
fiscal year of the business by which Executive is employed or with
which he is otherwise associated.
(c) Executive covenants and agrees that at no time during the Employment
Period nor at any time following any Termination of Employment will
Executive communicate, furnish, divulge or disclose in any manner to
any Person any Confidential Information (as defined in Section 9.1(d))
without the prior express written consent of the Company. After a
Termination of Employment, Executive shall not, without the prior
written consent of the Company, or as may otherwise be required by
law or legal process, communicate or divulge such Confidential
Information to anyone other than the Company and its designees.
(d) For purposes of this Section , "Confidential Information" shall mean
financial information about the Company, contract terms with vendors
and suppliers, customer and supplier lists and data, trade secrets
and such other
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competitively-sensitive information to which Executive has access as
a result of his positions with the Company, except that Confidential
Information shall not include any information which was or becomes
generally available to the public (i) other than as a result of a
wrongful disclosure by Executive, (ii) as a result of disclosure by
Executive during the Employment Period which he reasonably and in
good faith believes is required by the performance of his duties
under this Agreement, or (iii) any information compelled to be
disclosed by applicable law or administrative regulation; provided
that Executive, to the extent not prohibited from doing so by
applicable law or administrative regulation, shall give the Company
written notice of the information to be so disclosed pursuant to
clause (iii) of this sentence as far in advance of its disclosure
as is practicable.
9.2 Injunction. Executive acknowledges that monetary damages will not be an
adequate remedy for the Company in the event of a breach of this
Article IX, and that it would be impossible for the Company to measure
damages in the event of such a breach. Therefore, Executive agrees that,
in addition to other rights that the Company may have, the Company is
entitled to an injunction preventing Executive from any breach of this
Article IX.
ARTICLE 10
MISCELLANEOUS
10.1 Full Settlement. The Company's obligation to make the payments provided
for in this Agreement and otherwise to perform its obligations hereunder
shall not be affected by any circumstances, including set-off,
counterclaim, recoupment, defense or other claim, right or action which
the Company may have against Executive or others. In no event shall
Executive be obligated to seek other employment or take any other action
to mitigate the amounts payable to Executive under any of the provisions
of this Agreement, nor shall the amount of any payment hereunder be
reduced by any compensation earned as result of Executive's employment by
another employer, except that any continued welfare benefits provided for
by Section 6.2 shall not duplicate any benefits that are provided to
Executive and his family by such other employer and shall be secondary to
any coverage provided by such other employer.
10.2 Legal Fees: Late Payments.
(a) All reasonable costs and expenses (including fees and disbursements
of counsel) incurred by Executive in negotiating the terms and
conditions of this Agreement shall be promptly paid on behalf of, or
reimbursed to, Executive by the Company.
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(b) If Executive incurs legal or other fees and expenses in an effort to
secure or preserve or establish entitlement to compensation and
benefits under this Agreement, the Company shall, regardless of the
outcome of such effort, reimburse Executive for such fees and expenses
and shall pay Executive a Tax Gross-Up Payment in respect of the
Taxes incurred by Executive with respect to such reimbursement of
fees and expenses. The Company shall reimburse Executive for such
fees and expenses on a monthly basis within 10 days after his request
for reimbursement accompanied by evidence that the fees and expenses
were incurred. If Executive does not prevail (after exhaustion of
all available judicial remedies) in respect of a claim by Executive
or by the Company hereunder, and the Company establishes before a
court of competent jurisdiction, by clear and convincing evidence,
that Executive had no reasonable basis for his claim hereunder, or
for his response to the Company's claim hereunder, and acted in bad
faith, no further reimbursement for legal fees and expenses shall be
due to Executive in respect of such claim and Executive shall refund
any amounts previously reimbursed hereunder with respect to such
claim.
(c) If the Company fails to pay any amount provided under this Agreement
when due, the Company shall pay interest on such amount at a rate
equal to (i) the highest rate of interest charged by the Company's
principal lender plus 200 basis points, or (ii) in the absence of
such a lender, 300 basis points over the prime commercial lending
rate announced by Chase Bank of Texas, N.A. on the date such amount
is due or, if no such rate shall be announced on such date, the
immediately prior date on which Chase Bank of Texas, N.A. announced
such a rate; provided, however, that if the interest rate determined
in accordance with this Section exceeds the highest legally-
permissible interest rate, then the interest rate shall the highest
legally-permissible interest rate.
10.3 Beneficiary. If Executive dies prior to receiving all of the amounts
payable to him in accordance with the terms of this Agreement, such
amounts shall be paid to one or more beneficiaries (each, a
"Beneficiary") designated by Executive in writing to the Company during
his lifetime, or if no such Beneficiary is designated, to Executive's
estate. Such payments shall be made in a lump sum to the extent so
payable and, to the extent not payable in a lump sum, in accordance
with the terms of this Agreement. Executive, without the consent of any
prior Beneficiary, may change his designation of Beneficiary or
Beneficiaries at any time or from time to time by a submitting to the
Company a new designation in writing.
10.4 Assignment; Successors. The Company may not assign its rights and
obligations under this Agreement without the prior written consent of
Executive except to a successor of the Company's business which expressly
assumes the Company's obligations hereunder in writing. This Agreement
shall be binding upon and inure
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<PAGE>
to the benefit of Executive, his estate and Beneficiaries, the Company and
the successors and permitted assigns of the Company.
10.5 Nonalienation. Benefits payable under this Agreement shall not be
subject in any manner to anticipation, alienation, sale, transfer,
assignment, pledge, encumbrance, charge, garnishment, execution or levy
of any kind, either voluntary or involuntary, prior to actually being
received by Executive or a Beneficiary, as applicable, and any such
attempt to dispose of any right to benefits payable hereunder shall be
void.
10.6 Severability. If one or more parts of this Agreement are declared by any
court or governmental authority to be unlawful or invalid, such
unlawfulness or invalidity shall not invalidate any part of this
Agreement not declared to be unlawful or invalid. Any part so declared
to be unlawful or invalid shall, if possible, be construed in a manner
which will give effect to the terms of such part to the fullest extent
possible while remaining lawful and valid.
10.7 Captions. The names of the Articles and Sections of this Agreement are
for convenience of reference only and do not constitute a part hereof.
10.8 Amendment; Waiver. This Agreement shall not be amended or modified
except by written instrument executed by the Company and Executive. A
waiver of any term, covenant or condition contained in this Agreement
shall not be deemed a waiver of any other term, covenant or condition,
and any waiver of any default in any such term, covenant or condition
shall not be deemed a waiver of any later default thereof.
10.9 Notices. All notices hereunder shall be in writing and delivered by
hand, by nationally-recognized delivery service that guarantees
overnight delivery, or by first- class, registered or certified mail,
return receipt requested, postage prepaid, addressed as follows:
If to the Company, to: The Coastal Corporation
9 Greenway Plaza
Houston, Texas 77046
Attention: Corporate Secretary
If to Executive, to: David A. Arledge
3211 Robinson Road
Missouri City, Texas 77459
Either party may from time to time designate a new address by notice given in
accordance with this Section . Notice shall be effective when actually received
by the addressee.
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<PAGE>
10.10 Counterparts. This Agreement may be executed in several counterparts,
each of which shall be deemed to be an original but all of which
together will constitute one and the same instrument.
10.11 Entire Agreement. This Agreement forms the entire agreement between the
parties hereto with respect to the subject matter contained in this
Agreement and, except as otherwise provided herein, shall supersede all
prior agreements, promises and representations regarding employment,
compensation, severance or other payments contingent upon termination
of employment, whether in writing or otherwise.
10.12 Applicable Law. This Agreement shall be interpreted and construed in
accordance with the laws of the State of Texas, without regard to its
choice of law principles.
10.13 Survival of Executive's Rights. All of Executive's rights hereunder,
including his rights to compensation and benefits, and his obligations
under Section 9.1 hereof, shall survive the termination of Executive's
employment and/or the termination of this Agreement.
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<PAGE>
IN WITNESS WHEREOF, the parties have executed this Agreement on the date first
above written.
ATTEST: THE COASTAL CORPORATION
(Seal)
__________________________________ By: ______________________________
Austin M. O'Toole Coby C. Hesse
Senior Vice President and Secretary Executive Vice President
------------------------------
David A. Arledge
Executive
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<PAGE>
Exhibit 10.21
FORM OF EMPLOYMENT AGREEMENT FOR AN EMPLOYMENT AGREEMENT
between
[each of Coby C. Hesse and
Gene T. Waguespack]
and
THE COASTAL CORPORATION
<PAGE>
EMPLOYMENT AGREEMENT
EMPLOYMENT AGREEMENT dated as of January [ ], 2000 (the "Agreement") between The
Coastal Corporation, a Delaware corporation ("Company"), and [ ] ("Executive").
WHEREAS, the Company desires to employ Executive upon the terms and subject
to the conditions set forth herein; and
WHEREAS, the Company and Executive intend that the Agreement be void ab initio
and of no force and effect if neither the transaction contemplated by the
[Agreement and Plan of Merger, dated as of _____, by and between _____] (the
"Merger Agree ment"), nor any Change of Control resulting from the Company's
pursuit of the Transaction (either such transaction, the "Transaction"), is
consummated;
NOW, THEREFORE, in consideration of the premises and the mutual agreements
contained herein, the Company and Executive hereby agree as follows:
ARTICLE 1
DEFINITIONS
The terms set forth below have the following meanings (such meanings to be
applicable to both the singular and plural forms, except where otherwise
expressly indicated):
1.1 "Accrued Annual Bonus" means the amount of any Annual Bonus earned but
not yet paid with respect to the Year ended prior to the Date of
Termination.
1.2 "Accrued Base Salary" means the amount of Executive's Base Salary which
is accrued but not yet paid as of the Date of Termination.
1.3 "Affiliate" means any Person directly or indirectly controlling,
controlled by, or under direct or indirect common control with, the
Company. For the purposes of this definition, the term "control" when
used with respect to any Person means the power to direct or cause the
direction of management or
<PAGE>
policies of such Person, directly or indirectly, whether through the
ownership of voting securities, by contract or otherwise.
1.4 "Agreement" - see the recitals to this Agreement.
1.5 "Agreement Date" means the date that is specified in the recitals to this
Agreement.
1.6 "Annual Bonus" - see Section 4.2(a).
1.7 "Annualized Total Compensation" means, as of any date, the sum of
Executive's (i) Base Salary as of such date and (ii)Target Annual Bonus
(in no event shall such Target Annual Bonus be less than the most
recently awarded Annual Bonus) applicable to the Year that includes
such date.
1.8 "Base Salary" - see Section 4.1.
1.9 "Beneficiary" - see Section 10.3.
1.10 "Board" means the Board of Directors of the Company.
1.11 (a) "Cause" means any of the following:
(i) Executive's conviction of a felony or of a misdemeanor involving
fraud, dishonesty or moral turpitude, or
(ii) Executive's willful or intentional material breach of this
Agreement that results in financial detriment that is material to
the Company and its Affiliates taken as a whole.
For purposes of clause (ii) of the preceding sentence, Cause shall not include
any one or more of the following:
(A) bad judgment,
(B) negligence,
(C) any act or omission that Executive believed in good faith to
have been in or not opposed to the interest of the Company
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(without intent of Executive to gain therefrom, directly or
indirectly, a profit to which he was not legally entitled),
or
(D) any act or omission of which any member of the Board who is
not a party to such act or omission has had actual knowledge
for at least 12 months.
(b) With respect to a termination of employment occurring prior to a
Change of Control, "Cause" also means:
(i) the willful failure by Executive to substantially perform
Executive's duties with the Company (other than any such
failure resulting from Executive's incapacity due to physical
or mental illness) or
(ii) the willful engaging by Executive in conduct which is demon
strably and materially injurious to the Company or its
subsidiaries, monetarily or otherwise.
1.12 "Change of Control" means any of the following events:
(a) any person or group (as such terms are used in Rule 13d-5 under
the Exchange Act and defined in Sections 3(a)(9) and 13(d)(3) of
the Exchange Act), other than a Subsidiary or any employee benefit
plan (or any related trust) of the Company or a Subsidiary, becomes
the beneficial owner of 15% or more of the Common Stock or of
securities of the Company that are entitled to vote generally in
the election of directors of the Company ("Voting Securities")
representing 15% or more of the combined voting power of all
Voting Securities of the Company.
(b) individuals who, as of the Agreement Date, constitute the Board
(the "Incumbent Directors") cease for any reason to constitute a
majority of the members of the Board; provided that any individual
who becomes a director after the Agreement Date whose election or
nomination for election by the Company's shareholders was approved
by a majority of the members of the Incumbent Board (other than an
election or nomination of an individual whose initial assumption
of office is in connection with an actual or threatened "election
contest" relating to the election of the directors of the Company
(as such terms
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<PAGE>
are used in Rule 14a-1 1 under the Exchange Act), "tender offer"
(as such term is used in Section 14(d) of the Exchange Act) or a
proposed Merger (as defined below)) shall be deemed to be members
of the Incumbent Board; or
(c) approval by the stockholders of the Company of either of the
following:
(i) a merger, reorganization, consolidation or similar
transaction (any of the foregoing, a "Merger") as a result
of which the Persons who were the respective beneficial
owners of the outstanding Common Stock and Voting Securities
of the Company immediately before such Merger are not
expected to beneficially own, immediately after such Merger,
directly or indirectly, more than 60% of, respectively, the
common stock and the combined voting power of the Voting
Securities of the corporation resulting from such Merger in
substantially the same proportions as immediately before
such Merger, or
(ii) a plan of liquidation of the Company or a plan or agreement
for the sale or other disposition of all or substantially all
of the assets of the Company.
Notwithstanding the foregoing, there shall not be a Change of Control if, in
advance of such event, Executive agrees in writing that such event shall not
constitute a Change of Control.
1.13 "Code" means the Internal Revenue Code of 1986, as amended from time to
time.
1.14 "Committee" means the Compensation and Executive Development Committee
of the Board.
1.15 "Common Stock" means the common stock and Class A common stock of the
Company
1.16 "Company" - see the recitals to this Agreement.
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<PAGE>
1.17 "Date of Termination" means the effective date of a Termination of
Employment for any reason, including death or Disability, whether by
either of the Company or by Executive.
1.18 "Disability" means a mental or physical condition which, in the opinion
of the Board, renders Executive unable or incompetent to carry out the
material job responsibilities which such Executive held or the material
duties to which Executive was assigned at the time the disability was
incurred, which has existed for at least three months, and which in the
opinion of a physician mutually agreed upon by the Company and Executive
(provided that neither party shall unreasonably withhold this agreement)
is expected to be perma nent or to last for an indefinite duration or a
duration in excess of six months.
1.19 "Employment Period" see Section 3.1.
1.20 "Exchange Act" means the Securities Exchange Act of 1934.
1.21 "Executive"- see the recitals to this Agreement.
1.22 [Intentionally omitted.]
1.23 "Good Reason" means the occurrence of any one or more of the following
events unless Executive specifically agrees in writing that such event
shall not be Good Reason:
(a) any material breach of this Agreement by the Company, including:
(i) the failure of the Company to comply with the provisions of
Articles II, III, IV, V, VI or VII of this Agreement;
(ii) any material adverse change in the status, responsibilities
or perquisites of Executive;
(iii) any material adverse change in Executive's title; or
(iv) assignment of duties materially inconsistent with his
position and duties described in this Agreement,
(b) the failure of the Company to assign this Agreement to a successor
to the Company or failure of a successor to the Company to
explicitly assume and agree to be bound by this Agreement,
5
<PAGE>
(c) requiring Executive to be principally based at any office or
location more than 25 miles from the current offices of the
Company in Houston, Texas, or
(d) the delivery to Executive of a Notice of Consideration pursuant to
Section 8.1 (b) if, within a period of 90 days thereafter, the
Board fails for any reason to terminate Executive for Cause in
compliance with all of the substantive and procedural requirements
of Section 8.1.
Any reasonable determination by Executive that any of the foregoing events has
occurred and constitutes Good Reason shall be conclusive and binding for all
purposes.
1.24 "Including" means including without limitation.
1.25 "Notice of Consideration" - see Section 8.1 (b).
1.26 [Intentionally omitted.]
1.27 "Person" means any individual, sole proprietorship, partnership, joint
venture, trust, unincorporated organization, association, corporation,
institution, public benefit corporation, entity or government
instrumentality, division, agency, body or department.
1.28 "Prorata Annual Bonus" means (a) the product of the amount of the Target
Annual Bonus to which Executive would have been entitled if he had been
employed by the Company on the last day of the Year that includes the
Date of Termination and if Executive had achieved his Target Annual Goals
for such Year, multiplied by (b) a fraction of which the numerator is the
numbers of days which have elapsed in such Year through the Date of
Termination and the denominator is 365.
1.29 "Replacement Pension Plan" - see Section 7.1.
1.30 "Severance Payment" means the payment of a multiple of Executive's
Annualized Total Compensation pursuant to Section 8.3(b) or Section 8.4,
as applicable.
1.31 "Severance Period" means 2.99 years.
6
<PAGE>
1.32 "Subsidiary" means, with respect to any Person, (a) any corporation of
which more than 50% of the outstanding capital stock having ordinary
voting power to elect a majority of the board of directors of such
corporation (irrespective of whether, at the time, stock of any other
class or classes of such corporation shall have or might have voting
power by reason of the happening of any contingency) is at the time,
directly or indirectly, owned by such Person, and (b) any partnership in
which such Person has a direct or indirect interest (whether in the form
of voting or participation in profits or capital contribution) of more
than 50%.
1.33 "Target Annual Bonus" - see Section 4.2.
1.34 "Target Annual Goal" - see Section 4.2.
1.35 "Termination For Good Reason" means a Termination of Employment by
Executive for a Good Reason.
1.36 "Termination of Employment" means a termination by the Company or by
Executive of Executive's employment by the Company.
1.37 "Termination Without Cause" means a Termination of Employment by the
Company for any reason other than Cause or Executive's death or
Disability.
1.38 "Year" means a calendar year period ending on December 31.
ARTICLE 2
DUTIES
2.1 Duties. The Company shall employ Executive during the Employment Period
in the position(s) which Executive holds on the Agreement Date. During
the Employment Period, Executive shall perform the duties properly
assigned to him hereunder, shall devote substantially all of his
business time, attention and effort to the affairs of the Company and
shall use his reasonable best efforts to promote the interests of the
Company. During the Employment Period, and excluding any periods of
disability, vacation, or sick leave to which Executive is entitled,
Executive agrees to devote his full attention and time to the business
and affairs of the Company.
7
<PAGE>
2.2 Other Activities. Executive may serve on corporate, civic or charitable
boards or committees, deliver lectures, fulfill speaking engagements,
teach at educational institutions, or manage personal investments;
provided that such activities do not individually or in the aggregate
significantly interfere with the performance of his duties under this
Agreement.
ARTICLE 3
EMPLOYMENT PERIOD
3.1 Employment Period. Subject to the termination provisions hereinafter
provided, the term of Executive's employment under this Agreement (the
"Employment Period") shall begin on the Agreement Date and end on the
third anniversary of the date of consummation of the Transaction. The
employment of Executive by the Company shall not be terminated other
than in accordance with Article VIII. Notwithstanding the foregoing,
the Agree ment shall be void ab initio and of no force and effect if
the Merger Agree ment is terminated in accordance with its terms and if
any Transaction other than the Transaction contemplated by the Merger
Agreement is not consum mated within six months of the termination of
the Merger Agreement in accordance with its terms.
ARTICLE 4
COMPENSATION
4.1 Salary. The Company shall pay Executive in accordance with its normal
payroll practices (but not less frequently than monthly) an annual
salary at a rate no less favorable than the rate in effect on the
Agreement Date ("Base Salary"). During the Employment Period, the Base
Salary shall be reviewed at least annually by the Committee after
consultation with Executive and may from time to time be increased as
determined by the Committee. Effective as of the date of any such
increase the Base Salary as so increased shall be considered the new
Base Salary for all purposes of this Agreement and may not thereafter be
reduced. Any increase in Base Salary shall not limit or reduce any other
obligation of the Company to Executive under this Agreement.
4.2 Annual Bonus.
(a) The Company shall pay to Executive an annual cash bonus ("Annual
Bonus") in accordance with the terms hereof for each Year which
8
<PAGE>
begins during the Employment Period. Executive shall be eligible
for an Annual Bonus pursuant to the Executive Bonus Program of the
Company administered by the Committee.
(b) The Company performance goals are determined annually by the
Company. These performance goals are expressed as target
performance ("Target Annual Goal"). The level of bonus awarded to
the Executive pursuant to the Executive Bonus Program shall be
determined by the Committee and will vary based upon the level of
Company performance with the target bonus award for attainment of
Target Annual Goals (the "Target Annual Bonus").
(c) In the event that it is necessary to determine the bonus due the
Executive for less than a full year, then if the bonus due pursuant
to terms of this Agreement is the Target Annual Bonus, the
Executive shall be entitled to a bonus equal to the Target Annual
Bonus amount pursuant to the Executive Bonus Program of the Company
for the preceding Year had the Target Annual Goal been met,
regardless of whether such Target Annual Goal was met. In no event
shall such Target Annual Bonus be less than the most recently
awarded Annual Bonus. The bonus calculated pursuant to this
Section 4.2(c) shall be prorated for the portion of the year for
which such bonus is due. The Committee may increase this amount in
its discretion.
(d) The Company shall pay the entire Annual Bonus that is payable with
respect to a Year in a lump-sum cash payment as soon as
practicable after the Committee can determine whether and the
degree to which Target Annual Goal has been achieved following the
close of such Year. Any such Annual Bonus shall in any event be
paid within 120 days after the end of the Year.
ARTICLE 5
STOCK OPTIONS AND GRANTS
5.1 Participation. The Executive shall be eligible to participate in stock
option plans and similar programs offered by the Company to its key
employees.
5.2 Terms and Conditions of Options. The terms and conditions of the
programs discussed in Section 5.1 shall be established by the provisions
of such programs.
9
<PAGE>
ARTICLE 6
OTHER BENEFITS
6.1 Incentive, Savings and Retirement Plans. In addition to Base Salary and
an Annual Bonus, Executive shall be entitled to participate during the
Employ ment Period in all incentive, savings and (except as otherwise
provided in Section 7.3) retirement plans, practices, policies and
programs that are from time to time applicable to other senior
executives of the Company.
6.2 Welfare Benefits. During the Employment Period, Executive and/or his
family, as the case may be, shall be eligible for participation in and
shall receive all benefits under welfare benefit plans, practices,
policies and programs provided by the Company (including medical,
prescription, dental, disability, salary continuance, employee life,
group life, dependent life, accidental death and travel accident
insurance plans and programs) applicable to other senior executives of
the Company. After Termination of Employ ment by reason of a
Termination Without Cause or a Termination for Good Reason, the
Executive and/or his family, as the case may be, shall be eligible for
participation in and shall receive all benefits under welfare benefit
plans, practices and programs provided by the Company (including
medical, prescription and life insurance plans and programs) applicable
to other former employees including former senior executives of the
Company who retire from the Company at the time of Termination of
Employment of the Executive (or if earlier, at the time of a Change of
Control) provided that the requirements for the retiree medical program
(medical and prescription coverage) and participant contributions for
such coverage shall be modified as follows: (a) the requirement to
immediately receive monthly retirement income from a pension plan
maintained by the Company shall be met if the Executive begins
immediately to receive such payments from The Coastal Corporation
Replacement Pension Plan and (b) the contribution rate for the
Executive and/or his family, as the case may be, for coverage shall be
calculated based upon years of service credited for purposes of
determining the benefit due from The Coastal Corporation Replacement
Pension Plan.
6.3 Fringe Benefits. During the Employment Period, Executive shall be
entitled to all fringe benefits that are from time to time available to
other senior executives of the Company.
10
<PAGE>
6.4 Vacation. During the Employment Period, Executive shall be entitled to
paid vacation time in accordance with the plans, practices, policies,
and programs applicable to other senior executives of the Company.
6.5 Expenses. During the Employment Period, Executive shall be entitled to
receive prompt reimbursement for all reasonable employment-related
expenses incurred by Executive upon the receipt by the Company of
accounting in accordance with practices, policies and procedures
applicable to other senior executives of the Company.
6.6 Office; Support Staff. During the Employment Period, Executive shall be
entitled to an office or offices of a size and with furnishings and
other ap pointments, and to personal secretarial and other assistance,
appropriate to his position and duties under this Agreement.
ARTICLE 7
SUPPLEMENTAL RETIREMENT BENEFIT
7.1 Supplemental Retirement Benefit. Executive shall be entitled to a
nonqualified supplemental retirement benefit pursuant to The Coastal
Corporation Replacement Pension Plan (the "Replacement Pension Plan")
provided, however, that the method used to calculate the benefit due
the Executive shall be modified as stated in Section 7.2 of this
Agreement for determining benefits under the Replacement Pension Plan
in the event of a Termination of Employment by reason of his death or
Disability, a Termination Without Cause, or a Termination for Good
Reason.
7.2 Replacement Pension Plan Benefit Modification. For purposes of Section
7.1 of this Agreement, the benefit calculation method and the age at
which benefit payments may begin under the Replacement Pension Plan shall
be modified as follows: (a) the Basic Compensation (as defined in the
Replace ment Pension Plan) used to determine the five year average for
purposes of determining Final Average Earnings (as defined in the
Replacement Pension Plan) shall be (i) Base Salary (as defined in this
Agreement) in effect on the Date of Termination (reduced, if necessary,
to comply with the Replacement Pension Plan limitation of $500,000 as
indexed) for 3 of the 5 years, and (ii) Base Salary (as defined in this
Agreement) in effect for the two calendar years preceding the Date of
Termination (reduced, if necessary, to comply with the Replacement
Pension Plan limitation of $500,000 as indexed);
11
<PAGE>
provided, however, that if one of such two years is 1998, then Basic
Compensation (as defined in the Replacement Pension Plan) shall be used
in lieu of Base Salary for such year; and provided, further, that if one
of such 2 years is 1997, then Basic Compensation (as defined in the
Replacement Pension Plan and modified to insert $500,000 in lieu of
$160,000) shall be used in lieu of Base Salary for such year; (b) Years
of Service (as defined in the Replacement Pension Plan) shall be
increased to include the Severance Period (as defined in this Agreement);
and (c) the age of the Executive shall be equal to the sum of his actual
age and the Severance Period (as defined in this Agreement).
7.3 Other Supplemental Retirement Benefits. Executive shall not participate
in, or be entitled to benefits under, any other supplemental defined
benefit retirement plans of the Company which are not qualified under
Section 401 (a) of the Code, except as otherwise provided in writing by
the Company.
ARTICLE 8
TERMINATION BENEFITS
8.1 Termination for Cause or Other Than for Good Reason etc.
(a) If the Company terminates Executive's employment for Cause or
Executive terminates his employment other than for Good Reason,
death or Disability, the Company shall pay to Executive
immediately after the Date of Termination an amount equal to the
sum of Executive's Accrued Base Salary and Accrued Annual Bonus,
and Executive shall not be entitled to receive any Severance
Payment.
(b) Upon and following the occurrence of a Change of Control, the
Company may not terminate Executive's employment for Cause
unless:
(i) no fewer than 60 days prior to the Date of Termination, the
Company provides Executive with written notice (the "Notice
of Consideration") of its intent to consider termination of
Executive's employment for Cause, including a detailed
description of the specific reasons which form the basis for
such consideration;
(ii) for a period of not less than 30 days after the date Notice
of Consideration is provided, Executive shall have the
opportu-
12
<PAGE>
nity to appear before the Board, with or without legal
representation, at Executive's election, to present arguments
and evidence on his own behalf; and
(iii) following the presentation to the Board as provided in (ii)
above or Executive's failure to appear before the Board and
date and time specified in the Notice of Consideration
(which date shall not be less than 30 days after the date
the Notice of Consideration is provided), Executive may be
terminated for Cause only if (x) the Board, by the
affirmative vote of all of its members (excluding Executive
if he is a member of the Board, and any other member of the
Board reasonably believed by the Board to be involved in the
events leading the Board to terminate Executive for Cause),
determines that the actions or inactions of Executive
specified in the Notice of Termination occurred, that such
actions or inactions constitute Cause, and that Executive's
employment should accordingly be terminated for Cause; and
(y) the Board provides Executive with a written determination
(a "Notice of Termination for Cause") setting forth in
specific detail the basis of such Termination of Employment,
which Notice of Termination for Cause shall be consistent
with the reasons set forth in the Notice of Consideration.
Unless the Company establishes both (i) its full compliance with the
substantive and procedural requirements of this Section 8.1 prior to a
Termination of Employment for Cause, and (ii) that Executive's action or
inaction specified in the Notice of Termination for Cause did occur and
constituted Cause, any Termination of Employment shall be deemed a Termination
Without Cause for all purposes of this Agreement.
(c) With respect to a termination of employment upon or following a
Change of Control, after providing a Notice of Consideration
pursuant to the provisions of Section 8.1 (b), the Board may, by
the affirmative vote of all of its members (excluding for this
purpose Executive if he is a member of the Board, and any other
member of the Board reasonably believed by the Board to be
involved in the events issuing the Notice of Consideration),
suspend Executive with pay until a final determination pursuant to
such Section 8.1(b) has been made.
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8.2 Termination for Death or Disability. If Executive's employment terminates
during the Employment Period due to his death or Disability, the Company
shall pay to Executive or his Beneficiaries, as the case may be,
immediately after the Date of Termination an amount which is equal to
the sum of Executive's Accrued Base Salary, Accrued Annual Bonus and
Prorata Annual Bonus.
8.3 Termination Without Cause or for Good Reason. In the event of a
Termination Without Cause or a Termination for Good Reason, Executive
shall receive the following:
(a) immediately after the Date of Termination, a lump-sum amount in
immediately available funds equal to the sum of Executive's
Accrued Base Salary, Accrued Annual Bonus and Prorata Annual
Bonus;
(b) immediately after the Date of Termination, a lump-sum amount in
immediately available funds equal to the product of 2.99
multiplied by Executive's Annualized Total Compensation;
(c) immediately after the Date of Termination, a lump-sum amount in
immediately available funds equal to the total amount (if any)
of Executive's unvested benefits (excluding equity and equity-based
benefits) under any plan or program sponsored by the Company which
is forfeited on account of Executive's employment being terminated;
and
(d) the continuation of the benefits (or, if such benefits are not
available, the after-tax economic equivalent thereof) specified in
Sections 6.1, 6.2 and 6.3, at the level provided to other senior
executives of the Company, for the entire duration of the
Severance Period or, at the election of Executive, an immediate
lump-sum cash payment equal to the value of such benefits; provided
that with respect to any benefit to be provided on an insured
basis, such value shall be the present value of the premiums
expected to be paid for such coverage, and with respect to other
benefits, such value shall be the present value of the expected
net cost to the Company of providing such benefits.
8.4 Other Termination Benefits. In addition to any amounts or benefits
payable upon a Termination of Employment hereunder, Executive shall,
except as otherwise specifically provided herein, be entitled to any
payments or benefits
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provided hereunder or under the terms of any plan, policy or program of
the Company or as otherwise required by applicable law.
ARTICLE 9
RESTRICTIVE COVENANTS
9.1 Non-Solicitation of Employees: Confidentiality, Non-Competition.
(a) Executive covenants and agrees that, at no time during the period
employed pursuant to this Agreement nor during the one-year period
immediately following a Termination of Employment by the Company
for Cause or by Executive other than for Good Reason, death or
Disability, will Executive:
(i) directly or indirectly employ or seek to employ any person
employed at that time by the Company or any of its
Subsidiaries or otherwise encourage or entice any such
person to leave such employment;
(ii) become employed by, enter into a consulting arrangement with
or otherwise agree to perform personal services for a
Competitor (as defined in Section 9.1 (b));
(iii) acquire an ownership interest in a Competitor, or
(iv) solicit any customers or vendors of the Company on behalf of
or for the benefit of a Competitor.
(b) For purposes of this Section, "Competitor" means any Person which
sells goods or services which are directly competitive with those
sold by a business that (i) is being conducted by the Company or
any Subsidiary at the time in question and (ii) was being conducted
at the Date of Termination and, for the Company's most recently-
completed fiscal year, contributed more than 10% of the Company's
consolidated revenues. Notwithstanding anything to the contrary
in this Section, goods or services shall not be deemed to be
competitive with those of the Company (A) solely as a result of
Executive being employed by or otherwise associated with a business
of which a unit is in competition with the Company or any
Subsidiary but as to which unit Executive does not have direct or
indirect responsibilities for the products or
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services involved or (B) if the activity contributes less than 10%
of the consolidated revenues for the most recently-completed
fiscal year of the business by which Executive is employed or with
which he is otherwise associated.
(c) Executive covenants and agrees that at no time during the
Employment Period nor at any time following any Termination of
Employment will Executive communicate, furnish, divulge or disclose
in any manner to any Person any Confidential Information (as
defined in Section 9.1 (d)) without the prior express written
consent of the Company. After a Termination of Employment,
Executive shall not, without the prior written consent of the
Company, or as may otherwise be required by law or legal process,
communicate or divulge such Confidential Information to anyone
other than the Company and its designees.
(d) For purposes of this Section, "Confidential Information" shall
mean financial information about the Company, contract terms with
vendors and suppliers, customer and supplier lists and data, trade
secrets and such other competitively-sensitive information to
which Executive has access as a result of his positions with the
Company, except that Confidential Information shall not include
any information which was or becomes generally available to the
public (i) other than as a result of a wrongful disclosure by
Executive, (ii) as a result of disclosure by Executive during the
Employment Period which he reasonably and in good faith believes
is required by the performance of his duties under this Agreement,
or (iii) any information compelled to be disclosed by applicable
law or administrative regulation; provided that Executive, to the
extent not prohibited from doing so by applicable law or admin
istrative regulation, shall give the Company written notice of
the information to be so disclosed pursuant to clause (iii) of
this sentence as far in advance of its disclosure as is
practicable.
9.2 Injunction. Executive acknowledges that monetary damages will not be an
adequate remedy for the Company in the event of a breach of this
Article IX, and that it would be impossible for the Company to measure
damages in the event of such a breach. Therefore, Executive agrees
that, in addition to other rights that the Company may have, the
Company is entitled to an injunction preventing Executive from any
breach of this Article IX.
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ARTICLE 10
MISCELLANEOUS
10.1 Full Settlement. The Company's obligation to make the payments provided
for in this Agreement and otherwise to perform its obligations hereunder
shall not be affected by any circumstances, including set-off,
counterclaim, recoup ment, defense or other claim, right or action which
the Company may have against Executive or others. In no event shall
Executive be obligated to seek other employment or take any Other action
to mitigate the amounts payable to Executive under any of the provisions
of this Agreement, nor shall the amount of any payment hereunder be
reduced by any compensation earned as result of Executive's employment
by another employer, except that any continued welfare benefits provided
for by Section 6.2 shall not duplicate any benefits that are provided to
Executive and his family by such other employer and shall be secondary
to any coverage provided by such other employer.
10.2 Legal Fees: Late Payments.
(a) All reasonable costs and expenses (including fees and disbursements
of counsel) incurred by Executive in negotiating the terms and
conditions of this Agreement shall be promptly paid on behalf of,
or reimbursed to, Executive by the Company.
(b) If Executive incurs legal or other fees and expenses in an effort
to secure or preserve or establish entitlement to compensation and
benefits under this Agreement, the Company shall, regardless of the
outcome of such effort, reimburse Executive for such fees and ex
penses. The Company shall reimburse Executive for such fees and
expenses on a monthly basis within 10 days after his request for
reimbursement accompanied by evidence that the fees and expenses
were incurred. If Executive does not prevail (after exhaustion of
all available judicial remedies) in respect of a claim by Executive
or by the Company hereunder, and the Company establishes before a
court of competent jurisdiction, by clear and convincing evidence,
that Executive had no reasonable basis for his claim hereunder, or
for his response to the Company's claim hereunder, and acted in
bad faith, no further reimbursement for legal fees and expenses
shall be due to Executive in respect of such claim and Executive
shall refund any amounts previously reimbursed hereunder with
respect to such claim.
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(c) If the Company fails to pay any amount provided under this
Agreement when due, the Company shall pay interest on such amount
at a rate equal to (i) the highest rate of interest charged by the
Company's principal lender plus 200 basis points, or (ii) in the
absence of such a lender, 300 basis points over the prime
commercial lending rate announced by Chase Bank of Texas, N.A. on
the date such amount is due or, if no such rate shall be announced
on such date, the immediately prior date on which Chase Bank of
Texas, N.A. announced such a rate; provided, however, that if the
interest rate determined in accordance with this Section exceeds
the highest legally permissible interest rate, then the interest
rate shall the highest legally permissible interest rate.
10.3 Beneficiary. If Executive dies prior to receiving all of the amounts
payable to him in accordance with the terms of this Agreement, such
amounts shall be paid to one or more beneficiaries (each, a
"Beneficiary") designated by Executive in writing to the Company during
his lifetime, or if no such Beneficiary is designated, to Executive's
estate. Such payments shall be made in a lump sum to the extent so
payable and, to the extent not payable in a lump sum, in accordance with
the terms of this Agreement. Executive, without the consent of any prior
Beneficiary, may change his designation of Beneficiary or Beneficiaries
at any time or from time to time by a submitting to the Company a new
designation in writing.
10.4 Assignment; Successors. The Company may not assign its rights and
obligations under this Agreement without the prior written consent of
Executive except to a successor of the Company's business which
expressly assumes the Company's obligations hereunder in writing. This
Agreement shall be binding upon and inure to the benefit of Executive,
his estate and Beneficiaries, the Company and the successors and
permitted assigns of the Company.
10.5 Nonalienation. Benefits payable under this Agreement shall not be
subject in any manner to anticipation, alienation, sale, transfer,
assignment, pledge, encumbrance, charge, garnishment, execution or levy
of any kind, either voluntary or involuntary, prior to actually being
received by Executive or a Beneficiary, as applicable, and any such
attempt to dispose of any right to benefits payable hereunder shall be
void.
10.6 Severability. If one or more parts of this Agreement are declared by
any court or governmental authority to be unlawful or invalid, such
unlawfulness or
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invalidity shall not invalidate any part of this Agreement not declared
to be unlawful or invalid. Any part so declared to be unlawful or
invalid shall, if possible, be construed in a manner which will give
effect to the terms of such part to the fullest extent possible while
remaining lawful and valid.
10.7 Captions. The names of the Articles and Sections of this Agreement are
for convenience of reference only and do not constitute a part hereof.
10.8 Amendment; Waiver. This Agreement shall not be amended or modified
except by written instrument executed by the Company and Executive. A
waiver of any term, covenant or condition contained in this Agreement
shall not be deemed a waiver of any other term, covenant or condition,
and any waiver of any default in any such term, covenant or condition
shall not be deemed a waiver of any later default thereof.
10.9 Notices. All notices hereunder shall be in writing and delivered by
hand, by nationally-recognized delivery service that guarantees
overnight delivery, or by first-class, registered or certified mail,
return receipt requested, postage prepaid, addressed as follows:
If to the Company, to: The Coastal Corporation
9 Greenway Plaza
Houston, Texas 77046
Attention: Corporate Secretary
and if to Executive, to the most recent address furnished by Executive to the
Com pany. Either party may from time to time designate a new address by notice
given in accordance with this Section. Notice shall be effective when actually
received by the addressee.
10.10 Counterparts. This Agreement may be executed in several counterparts,
each of which shall be deemed to be an original but all of which
together will constitute one and the same instrument.
10.11 Entire Agreement. This Agreement forms the entire agreement between the
parties hereto with respect to the subject matter contained in this
Agreement and, except as otherwise provided herein, shall supersede all
prior agree ments, promises and representations regarding employment,
compensation, severance or other payments contingent upon termination
of employment, whether in writing or otherwise.
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10.12 Applicable Law. This Agreement shall be interpreted and construed in
accordance with the laws of the State of Texas, without regard to its
choice of law principles.
10.13 Survival of Executive's Rights. All of Executive's rights hereunder,
including his rights to compensation and benefits, and his obligations
under Section 9.1 hereof, shall survive the termination of Executive's
employment and/or the termination of this Agreement.
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IN WITNESS WHEREOF, the parties have executed this Agreement on ________, 2000.
ATTEST : THE COASTAL CORPORATION
(Seal)
By:
- -------------------------------- --------------------------------
Name: Name:
Position: Position:
--------------------------------
Executive
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Exhibit 10.22
FORM OF EMPLOYMENT AGREEMENT FOR AN EMPOYMENT AGREEMENT
between
[each of James A. King,
Jeffrey A. Connelly,
Carl A. Corrallo,
Rodney D. Erskine,
Donald H. Gullquist,
Dan J. Hill,
Austin M. O'Toole,
Keith O. Rattie,
James L. Van Lanen and
Thomas M. Wade]
and
THE COASTAL CORPORATION
<PAGE>
EMPLOYMENT AGREEMENT
EMPLOYMENT AGREEMENT dated as of the Agreement Date (the "Agreement") between
The Coastal Corporation, a Delaware corporation ("Company"), and [ ]
("Executive").
WHEREAS, the Company desires to employ Executive upon the terms and subject
to the conditions set forth herein; and
NOW, THEREFORE, in consideration of the premises and the mutual agreements
contained herein, the Company and Executive hereby agree as follows:
ARTICLE 1
DEFINITIONS
The terms set forth below have the following meanings (such meanings to be
applicable to both the singular and plural forms, except where otherwise
expressly indicated):
1.1 "Accrued Annual Bonus" means the amount of any Annual Bonus earned but
not yet paid with respect to the Year ended prior to the Date of
Termination.
1.2 "Accrued Base Salary" means the amount of Executive's Base Salary which
is accrued but not yet paid as of the Date of Termination.
1.3 "Affiliate" means any Person directly or indirectly controlling,
controlled by, or under direct or indirect common control with, the
Company. For the purposes of this definition, the term "control" when
used with respect to any Person means the power to direct or cause the
direction of management or policies of such Person, directly or
indirectly, whether through the ownership of voting securities, by
contract or otherwise.
1.4 "Agreement" - see the recitals to this Agreement.
1.5 "Agreement Date" means the date on which occurs the consummation of the
transaction contemplated by the [Agreement and Plan of Merger, dated as
of
<PAGE>
____, by and between _____], or any Change of Control resulting from
the Company's pursuit of such transaction (either such transaction, the
"Transaction").
1.6 "Annual Bonus" - see Section 4.2(a).
1.7 "Annualized Total Compensation" means, as of any date, the sum of Execu-
tive's (i) Base Salary as of such date and (ii)Target Annual Bonus (in
no event shall such Target Annual Bonus be less than the most recently
awarded Annual Bonus) applicable to the Year that includes such date.
1.8 "Base Salary" - see Section 4.1.
1.9 "Beneficiary" - see Section 10.3.
1.10 "Board" means the Board of Directors of the Company.
1.11 "Cause" means any of the following:
(a) Executive's conviction of a felony or of a misdemeanor involving
fraud, dishonesty or moral turpitude, or
(b) Executive's willful or intentional material breach of this
Agreement that results in financial detriment that is material
to the Company and its Affiliates taken as a whole.
For purposes of clause (b) of the preceding sentence, Cause shall not include
any one or more of the following:
(i) bad judgment,
(b) negligence,
(c) any act or omission that Executive believed in good faith to
have been in or not opposed to the interest of the Company
(without intent of Executive to gain therefrom, directly or
indirectly, a profit to which he was not legally entitled), or
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(d) any act or omission of which any member of the Board who is
not a party to such act or omission has had actual knowledge
for at least 12 months.
1.12 "Change of Control" means any of the following events:
(a) any person or group (as such terms are used in Rule 13d-5 under the
Exchange Act and defined in Sections 3(a)(9) and 13(d)(3) of the
Exchange Act), other than a Subsidiary or any employee benefit plan
(or any related trust) of the Company or a Subsidiary, becomes the
beneficial owner of 15% or more of the Common Stock or of securi
ties of the Company that are entitled to vote generally in the
election of directors of the Company ("Voting Securities")
representing 15% or more of the combined voting power of all Voting
Securities of the Company.
(b) individuals who, as of the Agreement Date, constitute the Board (the
"Incumbent Directors") cease for any reason to constitute a majority
of the members of the Board; provided that any individual who
becomes a director after the Agreement Date whose election or nomi
nation for election by the Company's shareholders was approved by a
majority of the members of the Incumbent Board (other than an
election or nomination of an individual whose initial assumption of
office is in connection with an actual or threatened "election
contest" relating to the election of the directors of the Company
(as such terms are used in Rule 14a-1 1 under the Exchange Act),
"tender offer" (as such term is used in Section 14(d) of the Exchange
Act) or a proposed Merger (as defined below)) shall be deemed to be
members of the Incumbent Board; or
(c) approval by the stockholders of the Company of either of the follow-
ing:
(i) a merger, reorganization, consolidation or similar transaction
(any of the foregoing, a "Merger") as a result of which the
Persons who were the respective beneficial owners of the
outstanding Common Stock and Voting Securities of the Company
immediately before such Merger are not expected to
beneficially own, immediately after such Merger, directly or
indirectly, more than 60% of, respectively, the common stock
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and the combined voting power of the Voting Securities of the
corporation resulting from such Merger in substantially the
same proportions as immediately before such Merger, or
(ii) a plan of liquidation of the Company or a plan or agreement
for the sale or other disposition of all or substantially all
of the assets of the Company.
Notwithstanding the foregoing, there shall not be a Change of Control if, in
advance of such event, Executive agrees in writing that such event shall not
constitute a Change of Control.
1.13 "Code" means the Internal Revenue Code of 1986, as amended from time to
time.
1.14 "Committee" means the Compensation and Executive Development Committee
of the Board.
1.15 "Common Stock" means the common stock and Class A common stock of the
Company
1.16 "Company" - see the recitals to this Agreement.
1.17 "Date of Termination" means the effective date of a Termination of
Employment for any reason, including death or Disability, whether by
either of the Company or by Executive.
1.18 "Disability" means a mental or physical condition which, in the opinion
of the Board, renders Executive unable or incompetent to carry out the
material job responsibilities which such Executive held or the material
duties to which Executive was assigned at the time the disability was
incurred, which has existed for at least three months, and which in the
opinion of a physician mutually agreed upon by the Company and
Executive (provided that neither party shall unreasonably withhold this
agreement) is expected to be perma nent or to last for an indefinite
duration or a duration in excess of six months.
1.19 "Employment Period" see Section 3.1.
1.20 "Exchange Act" means the Securities Exchange Act of 1934.
4
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1.21 "Executive"- see the recitals to this Agreement.
1.22 [Intentionally omitted.]
1.23 "Good Reason" means the occurrence of any one or more of the following
events unless Executive specifically agrees in writing that such event
shall not be Good Reason:
(a) any material breach of this Agreement by the Company, including:
(i) the failure of the Company to comply with the provisions of
Articles II, III, IV, V, VI or VII of this Agreement;
(ii) any material adverse change in the status, responsibilities
or perquisites of Executive;
(iii) any material adverse change in Executive's title; or
(iv) assignment of duties materially inconsistent with his
position and duties described in this Agreement,
(b) the failure of the Company to assign this Agreement to a successor
to the Company or failure of a successor to the Company to
explicitly assume and agree to be bound by this Agreement,
(c) requiring Executive to be principally based at any office or
location more than 25 miles from the current offices of the
Company in Hous ton, Texas, or
(d) the delivery to Executive of a Notice of Consideration
pursuant to Section 8.1 (b) if, within a period of 90 days
thereafter, the Board fails for any reason to terminate
Executive for Cause in compliance with all of the substantive
and procedural requirements of Section 8.1.
Any reasonable determination by Executive that any of the foregoing events has
occurred and constitutes Good Reason shall be conclusive and binding for all
purposes.
1.24 "Including" means including without limitation.
1.25 "Notice of Consideration" - see Section 8.1 (b).
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1.26 [Intentionally omitted.]
1.27 "Person" means any individual, sole proprietorship, partnership, joint
venture, trust, unincorporated organization, association, corporation,
institution, public benefit corporation, entity or government
instrumentality, division, agency, body or department.
1.28 "Prorata Annual Bonus" means (a) the product of the amount of the
Target Annual Bonus to which Executive would have been entitled if he
had been employed by the Company on the last day of the Year that
includes the Date of Termination and if Executive had achieved his
Target Annual Goals for such Year, multiplied by (b) a fraction of
which the numerator is the numbers of days which have elapsed in such
Year through the Date of Termination and the denominator is 365.
1.29 "Replacement Pension Plan" - see Section 7.1.
1.30 "Severance Payment" means the payment of a multiple of Executive's Annu
alized Total Compensation pursuant to Section 8.3(b) or Section 8.4, as
applicable.
1.31 "Severance Period" means 2.99 years.
1.32 "Subsidiary" means, with respect to any Person, (a) any corporation of
which more than 50% of the outstanding capital stock having ordinary
voting power to elect a majority of the board of directors of such
corporation (irrespective of whether, at the time, stock of any other
class or classes of such corporation shall have or might have voting
power by reason of the happening of any contingency) is at the time,
directly or indirectly, owned by such Person, and (b) any partnership
in which such Person has a direct or indirect interest (whether in the
form of voting or participation in profits or capital contribu tion) of
more than 50%.
1.33 "Target Annual Bonus" - see Section 4.2.
1.34 "Target Annual Goal" - see Section 4.2.
1.35 "Termination For Good Reason" means a Termination of Employment by
Executive for a Good Reason.
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1.36 "Termination of Employment" means a termination by the Company or by
Executive of Executive's employment by the Company.
1.37 "Termination Without Cause" means a Termination of Employment by the
Company for any reason other than Cause or Executive's death or
Disability.
1.38 "Year" means a calendar year period ending on December 31.
ARTICLE 2
DUTIES
2.1 Duties. The Company shall employ Executive during the Employment Period
in the position(s) which Executive holds on the Agreement Date. During
the Employment Period, Executive shall perform the duties properly
assigned to him hereunder, shall devote substantially all of his
business time, attention and effort to the affairs of the Company and
shall use his reasonable best efforts to promote the interests of the
Company. During the Employment Period, and excluding any periods of
disability, vacation, or sick leave to which Executive is entitled,
Executive agrees to devote his full attention and time to the business
and affairs of the Company.
2.2 Other Activities. Executive may serve on corporate, civic or charitable
boards or committees, deliver lectures, fulfill speaking engagements,
teach at educational institutions, or manage personal investments;
provided that such activities do not individually or in the aggregate
significantly interfere with the performance of his duties under this
Agreement.
ARTICLE 3
EMPLOYMENT PERIOD
3.1 Employment Period. Subject to the termination provisions hereinafter
provided, the term of Executive's employment under this Agreement (the
"Employment Period") shall begin immediately prior to the consummation of
the Transaction on the Agreement Date and end on the second anniversary
of the Agreement Date. The employment of Executive by the Company shall
not be terminated other than in accordance with Article VIII.
7
<PAGE>
ARTICLE 4
COMPENSATION
4.1 Salary. The Company shall pay Executive in accordance with its normal
payroll practices (but not less frequently than monthly) an annual
salary at a rate no less favorable than the rate in effect on the
Agreement Date ("Base Salary"). During the Employment Period, the Base
Salary shall be reviewed at least annually by the Committee after
consultation with Executive and may from time to time be increased as
determined by the Committee. Effective as of the date of any such
increase the Base Salary as so increased shall be considered the new
Base Salary for all purposes of this Agreement and may not thereafter be
reduced. Any increase in Base Salary shall not limit or reduce any other
obligation of the Company to Executive under this Agreement.
4.2 Annual Bonus.
(a) The Company shall pay to Executive an annual cash bonus ("Annual
Bonus") in accordance with the terms hereof for each Year which
begins during the Employment Period. Executive shall be eligible
for an Annual Bonus pursuant to the Executive Bonus Program of the
Company administered by the Committee.
(b) The Company performance goals are determined annually by the
Company. These performance goals are expressed as target
performance ("Target Annual Goal"). The level of bonus
awarded to the Executive pursuant to the Executive Bonus
Program shall be determined by the Committee and will vary
based upon the level of Company performance with the target
bonus award for attainment of Target Annual Goals (the "Target
Annual Bonus").
(c) In the event that it is necessary to determine the bonus due the
Executive for less than a full year, then if the bonus due
pursuant to terms of this Agreement is the Target Annual Bonus,
the Executive shall be entitled to a bonus equal to the Target
Annual Bonus amount pursuant to the Executive Bonus Program of the
Company for the preceding Year had the Target Annual Goal been met,
regardless of whether such Target Annual Goal was met. In no event
shall such Target Annual Bonus be less than the most recently
awarded Annual Bonus. The bonus calculated pursuant to this
Section 4.2(c) shall be prorated
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<PAGE>
for the portion of the year for which such bonus is due. The
Committee may increase this amount in its discretion.
(d) The Company shall pay the entire Annual Bonus that is payable with
respect to a Year in a lump-sum cash payment as soon as
practicable after the Committee can determine whether and the
degree to which Target Annual Goal has been achieved following the
close of such Year. Any such Annual Bonus shall in any event be
paid within 120 days after the end of the Year.
ARTICLE 5
STOCK OPTIONS AND GRANTS
5.1 Participation. The Executive shall be eligible to participate in stock
option plans and similar programs offered by the Company to its key
employees.
5.2 Terms and Conditions of Options. The terms and conditions of the
programs discussed in Section 5.1 shall be established by the provisions
of such programs.
ARTICLE 6
OTHER BENEFITS
6.1 Incentive, Savings and Retirement Plans. In addition to Base Salary and
an Annual Bonus, Executive shall be entitled to participate during the
Employment Period in all incentive, savings and (except as otherwise
provided in Section 7.3) retirement plans, practices, policies and
programs that are from time to time applicable to other senior
executives of the Company.
6.2 Welfare Benefits. During the Employment Period, Executive and/or his
family, as the case may be, shall be eligible for participation in and
shall receive all benefits under welfare benefit plans, practices,
policies and programs provided by the Company (including medical,
prescription, dental, disability, salary continuance, employee life,
group life, dependent life, accidental death and travel accident
insurance plans and programs) applicable to other senior executives of
the Company. After Termination of Employment by reason of a Termination
Without Cause or a Termination for Good Reason, the Executive and/or his
family, as the case may be, shall be eligible for participation in and
shall receive all benefits under welfare benefit plans, practices and
programs provided by the Company (including medical, pre-
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scription and life insurance plans and programs) applicable to other
former employees including former senior executives of the Company who
retire from the Company at the time of Termination of Employment of the
Executive (or if earlier, at the time of a Change of Control) provided
that the requirements for the retiree medical program (medical and
prescription coverage) and participant contributions for such coverage
shall be modified as follows: (a) the requirement to immediately receive
monthly retirement income from a pension plan maintained by the Company
shall be met if the Executive begins immediately to receive such payments
from The Coastal Corporation Replacement Pension Plan and (b) the
contribution rate for the Executive and/or his family, as the case may
be, for coverage shall be calculated based upon years of service
credited for purposes of determining the benefit due from The Coastal
Corporation Replacement Pension Plan.
6.3 Fringe Benefits. During the Employment Period, Executive shall be
entitled to all fringe benefits that are from time to time available to
other senior executives of the Company.
6.4 Vacation. During the Employment Period, Executive shall be entitled to
paid vacation time in accordance with the plans, practices, policies,
and programs applicable to other senior executives of the Company.
6.5 Expenses. During the Employment Period, Executive shall be entitled to
receive prompt reimbursement for all reasonable employment-related ex-
penses incurred by Executive upon the receipt by the Company of
accounting in accordance with practices, policies and procedures
applicable to other senior executives of the Company.
6.6 Office; Support Staff. During the Employment Period, Executive shall be
entitled to an office or offices of a size and with furnishings and
other appointments, and to personal secretarial and other assistance,
appropriate to his position and duties under this Agreement.
ARTICLE 7
SUPPLEMENTAL RETIREMENT BENEFIT
7.1 Supplemental Retirement Benefit. Executive shall be entitled to a
nonqualified supplemental retirement benefit pursuant to The Coastal
Corpora-
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tion Replacement Pension Plan (the "Replacement Pension Plan") provided,
however, that the method used to calculate the benefit due the Executive
shall be modified as stated in Section 7.2 of this Agreement for deter-
mining benefits under the Replacement Pension Plan in the event of a
Termination of Employment by reason of his death or Disability, a
Termination Without Cause, or a Termination for Good Reason.
7.2 Replacement Pension Plan Benefit Modification. For purposes of Section
7.1 of this Agreement, the benefit calculation method and the age at
which benefit payments may begin under the Replacement Pension Plan
shall be modified as follows: (a) the Basic Compensation (as defined in
the Replace ment Pension Plan) used to determine the five year average
for purposes of determining Final Average Earnings (as defined in the
Replacement Pension Plan) shall be (i) Base Salary (as defined in this
Agreement) in effect on the Date of Termination (reduced, if necessary,
to comply with the Replacement Pension Plan limitation of $500,000 as
indexed) for 3 of the 5 years, and (ii) Base Salary (as defined in this
Agreement) in effect for the two calendar years preceding the Date of
Termination (reduced, if necessary, to comply with the Replacement
Pension Plan limitation of $500,000 as indexed); provided, however,
that if one of such two years is 1998, then Basic Compensation (as
defined in the Replacement Pension Plan) shall be used in lieu of Base
Salary for such year; and provided, further, that if one of such 2
years is 1997, then Basic Compensation (as defined in the Replacement
Pension Plan and modified to insert $500,000 in lieu of $160,000) shall
be used in lieu of Base Salary for such year; (b) Years of Service (as
defined in the Replacement Pension Plan) shall be increased to include
the Severance Period (as defined in this Agreement); and (c) the age of
the Executive shall be equal to the sum of his actual age and the
Severance Period (as defined in this Agreement).
7.3 Other Supplemental Retirement Benefits. Executive shall not participate
in, or be entitled to benefits under, any other supplemental defined
benefit retirement plans of the Company which are not qualified under
Section 401 (a) of the Code, except as otherwise provided in writing by
the Company.
ARTICLE 8
TERMINATION BENEFITS
8.1 Termination for Cause or Other Than for Good Reason etc.
11
<PAGE>
(a) If the Company terminates Executive's employment for Cause or
Executive terminates his employment other than for Good Reason,
death or Disability, the Company shall pay to Executive immediately
after the Date of Termination an amount equal to the sum of
Executive's Accrued Base Salary and Accrued Annual Bonus, and
Executive shall not be entitled to receive any Severance Payment.
(b) The Company may not terminate Executive's employment for Cause
unless:
(i) no fewer than 60 days prior to the Date of Termination, the
Company provides Executive with written notice (the "Notice
of Consideration") of its intent to consider termination of
Executive's employment for Cause, including a detailed de-
scription of the specific reasons which form the basis for
such consideration;
(ii) for a period of not less than 30 days after the date
Notice of Consideration is provided, Executive shall
have the opportunity to appear before the Board,
with or without legal representation, at Executive's
election, to present arguments and evidence on his
own behalf; and
(iii) following the presentation to the Board as provided in (ii)
above or Executive's failure to appear before the Board and
date and time specified in the Notice of Consideration
(which date shall not be less than 30 days after the date
the Notice of Consideration is provided), Executive may be
terminated for Cause only if (x) the Board, by the
affirmative vote of all of its members (excluding Executive
if he is a member of the Board, and any other member of the
Board reasonably believed by the Board to be involved in the
events leading the Board to terminate Executive for Cause),
determines that the actions or inactions of Executive
specified in the Notice of Termination occurred, that such
actions or inactions constitute Cause, and that Executive's
employment should accordingly be terminated for Cause; and
(y) the Board provides Executive with a written
determination (a "Notice of Termination for Cause") setting
forth in specific detail the basis of such Termination of
Employment, which Notice of Termination for Cause shall be
12
<PAGE>
consistent with the reasons set forth in the Notice of
Consider ation.
Unless the Company establishes both (i) its full compliance with the substantive
and procedural requirements of this Section 8.1 prior to a Termination of
Employment for Cause, and (ii) that Executive's action or inaction specified in
the Notice of Termination for Cause did occur and constituted Cause, any
Termination of Employment shall be deemed a Termination Without Cause for all
purposes of this Agreement.
(c) After providing a Notice of Consideration pursuant to the
provisions of Section 8.1 (b), the Board may, by the affirmative
vote of all of its members (excluding for this purpose Executive
if he is a member of the Board, and any other member of the Board
reasonably believed by the Board to be involved in the events
issuing the Notice of Consideration), suspend Executive with pay
until a final determination pursuant to such Section 8.1(b) has
been made.
8.2 Termination for Death or Disability. If Executive's employment
terminates during the Employment Period due to his death or Disability,
the Company shall pay to Executive or his Beneficiaries, as the case
may be, immediately after the Date of Termination an amount which is
equal to the sum of Executive's Accrued Base Salary, Accrued Annual
Bonus and Prorata Annual Bonus.
8.3 Termination Without Cause or for Good Reason. In the event of a Termina-
tion Without Cause or a Termination for Good Reason, Executive shall
receive the following:
(a) immediately after the Date of Termination, a lump-sum amount in
immediately available funds equal to the sum of Executive's
Accrued Base Salary, Accrued Annual Bonus and Prorata Annual
Bonus;
(b) immediately after the Date of Termination, a lump-sum amount in
immediately available funds equal to the product of 2.99
multiplied by Executive's Annualized Total Compensation;
(c) immediately after the Date of Termination, a lump-sum amount in
immediately available funds equal to the total amount (if any)
of Executive's unvested benefits (excluding equity or equity-based
13
<PAGE>
benefits) under any plan or program sponsored by the Company which
is forfeited on account of Executive's employment being terminated;
and
(d) the continuation of the benefits (or, if such benefits are not
available, the after-tax economic equivalent thereof) specified in
Sections 6.1, 6.2 and 6.3 at the level provided to other senior
executives of the Company for the entire duration of the Severance
Period or, at the election of Executive, an immediate lump-sum
cash payment equal to the value of such benefits; provided that
with respect to any benefit to be provided on an insured basis,
such value shall be the present value of the premiums expected to
be paid for such coverage, and with respect to other benefits,
such value shall be the present value of the expected net cost to
the Company of providing such benefits.
8.4 Other Termination Benefits. In addition to any amounts or benefits
payable upon a Termination of Employment hereunder, Executive shall,
except as otherwise specifically provided herein, be entitled to any
payments or bene fits provided hereunder or under the terms of any
plan, policy or program of the Company or as otherwise required by
applicable law.
ARTICLE 9
RESTRICTIVE COVENANTS
9.1 Non-Solicitation of Employees: Confidentiality, Non-Competition.
(a) Executive covenants and agrees that, at no time during the period
employed pursuant to this Agreement nor during the one-year period
immediately following a Termination of Employment by the Company
for Cause or by Executive other than for Good Reason, death or
Disability, will Executive:
(i) directly or indirectly employ or seek to employ any person
employed at that time by the Company or any of its
Subsidiaries or otherwise encourage or entice any such
person to leave such employment;
(ii) become employed by, enter into a consulting arrangement with
or otherwise agree to perform personal services for a
Competitor (as defined in Section 9.1 (b));
14
<PAGE>
(iii) acquire an ownership interest in a Competitor, or
(iv) solicit any customers or vendors of the Company on behalf of
or for the benefit of a Competitor.
(b) For purposes of this Section , "Competitor" means any Person which
sells goods or services which are directly competitive with those
sold by a business that (i) is being conducted by the Company or
any Subsidiary at the time in question and (ii) was being
conducted at the Date of Termination and, for the Company's most
recently-completed fiscal year, contributed more than 10% of the
Company's consolidated revenues. Notwithstanding anything to the
contrary in this Section, goods or services shall not be deemed to
be competitive with those of the Company (A) solely as a result of
Executive being employed by or otherwise associated with a
business of which a unit is in competition with the Company or any
Subsidiary but as to which unit Executive does not have direct or
indirect responsibilities for the products or services involved or
(B) if the activity contributes less than 10% of the consolidated
revenues for the most recently-completed fiscal year of the
business by which Executive is employed or with which he is
otherwise associated.
(c) Executive covenants and agrees that at no time during the
Employment Period nor at any time following any Termination of
Employment will Executive communicate, furnish, divulge or
disclose in any manner to any Person any Confidential Information
(as defined in Section 9.1 (d)) without the prior express written
consent of the Company. After a Termination of Employment,
Executive shall not, without the prior written consent of the
Company, or as may otherwise be required by law or legal process,
communicate or divulge such Confidential Information to anyone
other than the Company and its designees.
(d) For purposes of this Section , "Confidential Information" shall
mean financial information about the Company, contract terms with
vendors and suppliers, customer and supplier lists and data, trade
secrets and such other competitively-sensitive information to which
Executive has access as a result of his positions with the Company,
except that Confidential Information shall not include any
information which was
15
<PAGE>
or becomes generally available to the public (i) other than as a
result of a wrongful disclosure by Executive, (ii) as a result of
disclosure by Executive during the Employment Period which he
reasonably and in good faith believes is required by the
performance of his duties under this Agreement, or (iii) any
information compelled to be disclosed by applicable law or
administrative regulation; provided that Executive, to the extent
not prohibited from doing so by applicable law or administrative
regulation, shall give the Company written notice of the
information to be so disclosed pursuant to clause (iii) of this
sentence as far in advance of its disclosure as is practicable.
9.2 Injunction. Executive acknowledges that monetary damages will not be an
adequate remedy for the Company in the event of a breach of this
Article IX, and that it would be impossible for the Company to measure
damages in the event of such a breach. Therefore, Executive agrees
that, in addition to other rights that the Company may have, the
Company is entitled to an injunction preventing Executive from any
breach of this Article IX.
ARTICLE 10
MISCELLANEOUS
10.1 Full Settlement. The Company's obligation to make the payments provided
for in this Agreement and otherwise to perform its obligations
hereunder shall not be affected by any circumstances, including
set-off, counterclaim, recoupment, defense or other claim, right or
action which the Company may have against Executive or others. In no
event shall Executive be obligated to seek other employment or take any
Other action to mitigate the amounts payable to Executive under any of
the provisions of this Agreement, nor shall the amount of any payment
hereunder be reduced by any compensation earned as result of Executive's
employment by another employer, except that any continued welfare
benefits provided for by Section 6.2 shall not duplicate any benefits
that are provided to Executive and his family by such other employer and
shall be secondary to any coverage provided by such other employer.
10.2 Legal Fees: Late Payments.
(a) All reasonable costs and expenses (including fees and disbursements
of counsel) incurred by Executive in negotiating the terms and
conditions of this Agreement shall be promptly paid on behalf of,
or reimbursed to, Executive by the Company.
16
<PAGE>
(b) If Executive incurs legal or other fees and expenses in an effort
to secure or preserve or establish entitlement to compensation and
benefits under this Agreement, the Company shall, regardless of the
outcome of such effort, reimburse Executive for such fees and ex-
penses. The Company shall reimburse Executive for such fees and
expenses on a monthly basis within 10 days after his request for
reimbursement accompanied by evidence that the fees and expenses
were incurred. If Executive does not prevail (after exhaustion of
all available judicial remedies) in respect of a claim by Executive
or by the Company hereunder, and the Company establishes before a
court of competent jurisdiction, by clear and convincing evidence,
that Executive had no reasonable basis for his claim hereunder, or
for his response to the Company's claim hereunder, and acted in
bad faith, no further reimbursement for legal fees and expenses
shall be due to Executive in respect of such claim and Executive
shall refund any amounts previously reimbursed hereunder with
respect to such claim.
(c) If the Company fails to pay any amount provided under this Agree-
ment when due, the Company shall pay interest on such amount at a
rate equal to (i) the highest rate of interest charged by the
Company's principal lender plus 200 basis points, or (ii) in the
absence of such a lender, 300 basis points over the prime
commercial lending rate announced by Chase Bank of Texas, N.A. on
the date such amount is due or, if no such rate shall be announced
on such date, the immediately prior date on which Chase Bank of
Texas, N.A. announced such a rate; provided, however, that if the
interest rate determined in accordance with this Section exceeds
the highest legally permissible interest rate, then the interest
rate shall the highest legally permissible interest rate.
10.3 Beneficiary. If Executive dies prior to receiving all of the amounts
payable to him in accordance with the terms of this Agreement, such
amounts shall be paid to one or more beneficiaries (each, a
"Beneficiary") designated by Executive in writing to the Company during
his lifetime, or if no such Beneficiary is designated, to Executive's
estate. Such payments shall be made in a lump sum to the extent so
payable and, to the extent not payable in a lump sum, in accordance with
the terms of this Agreement. Executive, without the consent of any prior
Beneficiary, may change his designation of
17
<PAGE>
Beneficiary or Beneficiaries at any time or from time to time by a
submitting to the Company a new designation in writing.
10.4 Assignment; Successors. The Company may not assign its rights and
obligations under this Agreement without the prior written consent of
Executive except to a successor of the Company's business which
expressly assumes the Company's obligations hereunder in writing. This
Agreement shall be binding upon and inure to the benefit of Executive,
his estate and Beneficiaries, the Company and the successors and
permitted assigns of the Company.
10.5 Nonalienation. Benefits payable under this Agreement shall not be
subject in any manner to anticipation, alienation, sale, transfer,
assignment, pledge, encumbrance, charge, garnishment, execution or levy
of any kind, either voluntary or involuntary, prior to actually being
received by Executive or a Beneficiary, as applicable, and any such
attempt to dispose of any right to benefits payable hereunder shall be
void.
10.6 Severability. If one or more parts of this Agreement are declared by
any court or governmental authority to be unlawful or invalid, such
unlawfulness or invalidity shall not invalidate any part of this
Agreement not declared to be unlawful or invalid. Any part so declared
to be unlawful or invalid shall, if possible, be construed in a manner
which will give effect to the terms of such part to the fullest extent
possible while remaining lawful and valid.
10.7 Captions. The names of the Articles and Sections of this Agreement are
for convenience of reference only and do not constitute a part hereof.
10.8 Amendment; Waiver. This Agreement shall not be amended or modified
except by written instrument executed by the Company and Executive. A
waiver of any term, covenant or condition contained in this Agreement
shall not be deemed a waiver of any other term, covenant or condition,
and any waiver of any default in any such term, covenant or condition
shall not be deemed a waiver of any later default thereof.
10.9 Notices. All notices hereunder shall be in writing and delivered by
hand, by nationally-recognized delivery service that guarantees
overnight delivery, or by first-class, registered or certified mail,
return receipt requested, postage prepaid, addressed as follows:
18
<PAGE>
If to the Company, to: The Coastal Corporation
9 Greenway Plaza
Houston, Texas 77046
Attention: Corporate Secretary
and if to Executive, to the most recent address furnished by Executive to the
Company. Either party may from time to time designate a new address by notice
given in accordance with this Section. Notice shall be effective when actually
received by the addressee.
10.10 Counterparts. This Agreement may be executed in several counterparts,
each of which shall be deemed to be an original but all of which
together will constitute one and the same instrument.
10.11 Entire Agreement. This Agreement forms the entire agreement between the
parties hereto with respect to the subject matter contained in this
Agreement and, except as otherwise provided herein, shall supersede all
prior agreements, promises and representations regarding employment,
compensation, severance or other payments contingent upon termination
of employment, whether in writing or otherwise.
10.12 Applicable Law. This Agreement shall be interpreted and construed in
accordance with the laws of the State of Texas, without regard to its
choice of law principles.
10.13 Survival of Executive's Rights. All of Executive's rights hereunder,
including his rights to compensation and benefits, and his obligations
under Section 9.1 hereof, shall survive the termination of Executive's
employment and/or the termination of this Agreement.
19
<PAGE>
IN WITNESS WHEREOF, the parties have executed this Agreement on ______, 2000.
ATTEST : THE COASTAL CORPORATION
(Seal)
- --------------------------------------------------------------------------------
By:
- ------------------------------------ ------------------------------------
Name: Name:
Position: Position:
------------------------------------
Executive
20
<PAGE>
Exhibit 11
THE COASTAL CORPORATION AND SUBSIDIARIES
STATEMENT RE COMPUTATION OF PER SHARE EARNINGS
(Millions of Dollars, Except Per Share Amounts, and Thousands of Shares)
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------
1999 1998 1997
--------- --------- ---------
<S> <C> <C> <C>
BASIC EARNINGS PER SHARE
Net earnings....................................................... $ 498.9 $ 444.4 $ 301.5
Dividends on preferred stock....................................... .3 6.0 17.4
--------- --------- ---------
Net earnings available to common stockholders...................... $ 498.6 $ 438.4 $ 284.1
========= ========= =========
Average number of common shares outstanding............................ 212,934 212,184 211,518
Average number of Class A common shares outstanding.................... 349 359 374
--------- --------- ---------
213,283 212,543 211,892
========= ========= =========
Basic earnings per share:
From continuing operations before extraordinary item............... $ 2.34 $ 2.24 $ 1.80
Discontinued operations............................................ - (.18) (.03)
Extraordinary item................................................. - - (.43)
--------- --------- ---------
Net basic earnings per share....................................... $ 2.34 $ 2.06 $ 1.34
========= ========= =========
DILUTED EARNINGS PER SHARE
Net earnings used in calculating basic earnings per share.......... $ 498.6 $ 438.4 $ 284.1
Dividends applicable to dilutive preferred stock:
Series A........................................................ .1 .1 .1
Series B........................................................ .1 .1 .1
Series C........................................................ .1 .1 .2
--------- --------- ---------
Income available to common shareholders plus
assumed conversions............................................. $ 498.9 $ 438.7 $ 284.5
========= ========= ---------
Average number of shares used in calculating basic earnings
per share.......................................................... 213,283 212,543 211,892
Effect of dilutive securities:
Options............................................................ 2,465 2,248 1,798
Series A, B and C preferred stock.................................. 1,244 1,317 1,412
--------- --------- ---------
216,992 216,108 215,102
========= ========= =========
Diluted earnings per share:
From continuing operations before extraordinary item............... $ 2.30 $ 2.21 $ 1.77
Discontinued operations............................................ - (.18) (.03)
Extraordinary item................................................. - - (.42)
--------- --------- ---------
Net diluted earnings per share..................................... $ 2.30 $ 2.03 $ 1.32
========= ========= =========
</TABLE>
- -------------
Convertible securities and options are not considered in the calculations if
the effect of the conversion is anti-dilutive.
<PAGE>
Exhibit 21
SUBSIDIARIES OF THE COASTAL CORPORATION
<TABLE>
<CAPTION>
State or Other Jurisdiction of
Incorporation or Organization
<S> <C>
Coastal Alliance Pipeline Company, L.L.C.............................................. Delaware
Alliance Pipeline, LP (14.44% LP).............................................. Delaware*
Coastal Capital Corporation .......................................................... Delaware
Coastal Finance Corporation.................................................... Delaware
Coastal Midwest, Inc........................................................... Delaware
Coastal Alliance Pipeline Company, L.L.C. (50%)....................................... Delaware
Coastal Capital Corporation .......................................................... Delaware
Coastal Finance Corporation.................................................... Delaware
Coastal Midwest, Inc........................................................... Delaware
Coastal Coal Company, LLC (52.3%)..................................................... Delaware
Coastal Coal, Inc..................................................................... Delaware
Coastal Credit, Inc............................................................ Delaware
Coastal Finance I..................................................................... Delaware
Coastal Gas International Company..................................................... Delaware
Coastal Gas & Power India I Ltd................................................ Cayman Islands
Coastal Gas India Holdings Ltd................................................. Cayman Islands
Coastal Gas India Ltd................................................... Cayman Islands
Coastal Gas International Ltd.................................................. Cayman Islands
Coastal Gas Australia Pty Ltd........................................... Cayman Islands
Coastal Gas International Ventures, Inc........................................ Delaware
Coastal Gas Storage Victoria Ltd............................................... Cayman Islands
Coastal Gas Storage Victoria Pty Ltd.................................... Australia
Coastal Gas Toluca Ltd......................................................... Cayman Islands
Coastal Gas Venezuela Ltd...................................................... Cayman Islands
Coastal Gas Services Company.......................................................... Delaware
ANR Gas Supply Company......................................................... Delaware
ANR Transportation Services Company............................................ Delaware
CES Gas & Electric, Inc................................................. Delaware
Coastal Canada Gas Services, Inc............................................... New Brunswick
Engage Energy Canada, Inc. (50%)**...................................... Alberta
Coastal Electric Services Company.............................................. Delaware
Coastal Field Services Company................................................. Delaware
CFS Holding Company..................................................... Delaware
CFS Louisiana, L.P. (1% LP)....................................... Delaware*
CFS Louisiana Midstream Company................................... Delaware
CFS Louisiana, L.P. (1% GP and 98% LP).................................. Delaware*
CIG Merchant Company.................................................... Delaware
Coastal Gas Gathering and Processing Company............................ Delaware
CFS Processing Company............................................ Delaware
CGGP Texas, L.P. (49.1% LP)................................ Delaware*
CGGP Texas, L.P. (1% GP and 49.9% LP)............................. Delaware*
Coastal Aux Sable Liquid Products Company.................. Delaware
Aux Sable Liquid Products L.P. (14.44% LP)**......... Delaware*
Aux Sable Liquid Products, Inc. (14.4%).................... Delaware
Aux Sable Liquid Products L.P. (1% GP)**............. Delaware*
Coastal Dauphin Island Company, L.L.C........................... Delaware
DIGP Holding Company, L.L.C................................ Delaware
MBPP Holding Company, L.L.C................................ Delaware
</TABLE>
1
<PAGE>
SUBSIDIARIES OF THE COASTAL CORPORATION
<TABLE>
<CAPTION>
State or Other Jurisdiction of
Incorporation or Organization
<S> <C>
Blacks Fork Gas Processing Company (50%)**........................ Wyoming*
Coastal States Gas Transmission Company................................. Delaware
Starr County Gathering System (30%)**............................. Texas*
Starr-Zapata Pipe Line Company (50% GP)**......................... Texas*
Coastal Gas Marketing Company.................................................. Delaware
CGM, Inc................................................................ Delaware
Coastal Mineral Financing, L.P. (99%)............................. Delaware*
Engage Energy US, L.P. (50%)**.................................... Delaware*
Coastal Gas Marketing Direct Link Corp. ................................ Delaware
Engage Energy US, Inc. (50%)**.......................................... Delaware
Engage Energy US, L.P. (1%)**........................................... Delaware*
Coastal Horsham Pipeline I Ltd................................................. Cayman Islands
Coastal Gas Pipelines Victoria, L.L.C................................... Delaware
Coastal Multi-Fuels, Inc....................................................... Delaware
Coastal Pan American Corporation............................................... Delaware
Coastal Cape Horn Ltd................................................... Cayman Islands
Coastal Austral Ltd............................................... Cayman Islands
Coastal Aruba Holding Company N.V. (1.68%)................. Aruba
Coastal TDF Ltd................................................... Cayman Islands
Coastal Aruba Holding Company N.V. (1.68%)................. Aruba
Coastal Southern Pipeline Company.............................................. Delaware
Gulfstream Natural Gas System, L.L.C. (49%)............................. Delaware
Coastal Health Management Corporation (46%)........................................... Delaware
Coastal Holding Corporation........................................................... Delaware
CIC Industries, Inc............................................................ Delaware
Coastal Chem, Inc....................................................... Delaware
Coastal Pipeline Company................................................ Delaware
Coastal Refining & Marketing, Inc....................................... Delaware
Coastal Liquids Partners, L.P. (6.212% LP)**...................... Delaware*
Coastal Petroleum (Bahamas) Limited............................... The Bahamas
Coastal Refined Products Corporation.............................. Delaware
Coastal Liquids Transportation, L.P. (88% LP).............. Delaware*
Coastal States Crude Gathering Company............................ Texas
Coastal Liquids Transportation, L.P. (2% GP)............... Delaware*
Coastal Liquids Partners, L.P. (.804% GP and
21.138% LP)**........................................ Delaware*
Distribuidora Coastal, S.A. de C.V................................ El Salvador
Fulton Cogeneration Associates, L.P. (3%GP and 64-2/3% LP)........ New York*
Lube & Wax Ventures, L.L.C. (50%)**............................... Delaware
Coastal Catalyst Technology, Inc............................................... Delaware
Coastal Cat Process Marketing, Inc............................................. Delaware
BAR-CO Processes Joint Venture (50%)**.................................. Texas*
Coastal Eagle Point Oil Company................................................ Delaware
Coastal Energy Corporation..................................................... Delaware
Coastal Mobile Refining Company................................................ Delaware
Coastal Petrochemical International A.V.V...................................... Aruba
Coastal Petrochemical International (L) Limited......................... Labuan (Malaysia)
Coastal Aruba Holding Company N.V. (13.19%)....................... Aruba
</TABLE>
2
<PAGE>
SUBSIDIARIES OF THE COASTAL CORPORATION
<TABLE>
<CAPTION>
State or Other Jurisdiction of
Incorporation or Organization
<S> <C>
Coastal West Ventures, Inc..................................................... Delaware
Coastal Limited Ventures, Inc (.99%).................................................. Texas
ANR Financial Services, Inc.................................................... Delaware
Coastal Mart, Inc..................................................................... Delaware
Coastal Mart Holdings, Inc..................................................... Delaware
Coastal Markets, Ltd.................................................... Texas*
TND Beverage Corporation....................................................... Texas
Coastal Medical Services, Inc......................................................... Delaware
Coastal Midland, Inc.................................................................. Delaware
Coastal Micogen Partner, Inc................................................... Delaware
Micogen Limited Partnership (1% GP)..................................... Delaware*
Midland Cogeneration Venture Limited Partnership
(4.531% LP)**..................................................... Delaware*
Source Midland Limited Partnership (20% GP)............................. Delaware*
MEI Limited Partnership (1% GP and 49% LP)........................ Delaware*
Midland Cogeneration Venture Limited
Partnership (9.063% GP and 0.906% LP)**.................... Delaware*
Midland Cogeneration Venture Limited Partnership
(18.125% GP)**.................................................... Delaware*
MEI Limited Partnership (1% GP and 49% LP)..................................... Delaware*
Micogen Limited Partnership (99%LP)............................................ Delaware*
Midland Cogeneration Venture Limited Partnership (10.875% GP)**................ Delaware*
Source Midland Limited Partnership (80% LP).................................... Delaware*
Coastal Natural Gas Company........................................................... Delaware
ANR Gulfstream, L.L.C.......................................................... Delaware
Gulfstream Natural Gas System, L.L.C. (51%) ............................ Delaware
American Natural Resources Company............................................. Delaware
ANR Alliance Transportation Services Company............................ Delaware
ANR Credit Corporation.................................................. Delaware
ANR Development Corporation............................................. Delaware
ANR Real Estate Corporation....................................... Connecticut
ANR Field Services Company.............................................. Delaware
ANR Independence Pipeline Company....................................... Delaware
ANR Intrastate Gas Company, Inc......................................... Delaware
ANR Pipeline Company.................................................... Delaware
ANR Alliance Pipeline Company Canada, Inc......................... Canada
Alliance Pipeline Ltd. (14.44%) **......................... Canada
Alliance Pipeline Limited Partnership (1% GP)**...... Canada*
ANR Alliance Pipeline Company U.S., Inc........................... Delaware
Alliance Pipeline, Inc. (14.44%)**......................... Delaware
Alliance Pipeline, L.P. (1% GP)**.................... Delaware*
ANR Atlantic Pipeline Company..................................... Delaware
ANR Capital Corporation........................................... Delaware
ANR Energy Conversion Company..................................... Michigan
Coastal Minerals Financing, L.P. (1% GP)................... Delaware*
ANR Iroquois, Inc................................................. Delaware
ANR New England Pipeline Company........................... Delaware
Iroquois Gas Transmission System, L.P. (6.6%)**...... Delaware*
</TABLE>
3
<PAGE>
SUBSIDIARIES OF THE COASTAL CORPORATION
<TABLE>
<CAPTION>
State or Other Jurisdiction of
Incorporation or Organization
<S> <C>
Iroquois Gas Transmission System, L.P. (9.4%)**............ Delaware*
ANR Southern Pipeline Company..................................... Delaware
ANR Western Gulf Holdings, L.L.C.................................. Delaware
Deepwater Holdings, L.L.C. (17.645%)**..................... Delaware
Stingray Pipeline Company, L.L.C..................... Delaware
U-T Offshore System, L.L.C........................... Delaware
West Cameron Dehydration Company, L.L.C.............. Delaware
Western Gulf Holdings, L.L.C......................... Delaware
East Breaks Gathering Company, L.L.C.......... Delaware
High Island Offshore System, L.L.C............ Delaware
American Natural Offshore Company................................. Delaware
Deepwater Holdings, L.L.C. (14.819%)**..................... Delaware
Texas Offshore Pipeline System, Inc........................ Delaware
Deepwater Holdings, L.L.C. (14.819%)**............... Delaware
Unitex Offshore Transmission Company....................... Delaware
Deepwater Holdings, L.L.C. (2.717%)**................ Delaware
ANR Production Company.................................................. Delaware
ANRPC Holdings, Inc............................................... Delaware
Coastal Oil & Gas USA, L.P. (30% LP)....................... Delaware*
Coastal Health Management Corporation (50%).......... Delaware
Coastal Limited Ventures, Inc. (20.98%)........................... Texas
Coastal Liquids Transportation, L.P. (10% LP)..................... Delaware*
Coastal Oil & Gas Resources, Inc. (20.98%)........................ Delaware
ANR Storage Company..................................................... Michigan
ANR Blue Lake Company............................................. Delaware
Blue Lake Gas Storage Company (75%)**...................... Michigan*
ANR Cold Springs Company.......................................... Delaware
Kalkaska Gas Storage Limited Partnership (75%)**........... Michigan*
ANR Eaton Company................................................. Michigan
Eaton Rapids Gas Storage System (50%)**.................... Michigan*
ANR Jackson Company............................................... Delaware
Jackson Pipeline Company (25%)**........................... Michigan
ANR Northeastern Gas Storage Company.............................. Delaware
Steuben Gas Storage Company (50%)**........................ New York*
ANR Western Storage Company....................................... Delaware
ANR Venture Eagle Point Company......................................... Delaware
Eagle Point Cogeneration Partnership (.01%)**..................... New Jersey*
ANR Venture Management Company.......................................... Delaware
Capitol District Energy Center Cogeneration
Associates (50%)**................................................ Connecticut*
ANR Western Coal Development Company.................................... Delaware
ANRFS Holdings, Inc..................................................... Delaware
ANR Advance Holdings, Inc. (50%)**................................ Delaware
Transport USA, Inc......................................... Pennsylvania
Coastal Coal Company, LLC (47.7%)....................................... Delaware
Coastal Coal - West Virginia, LLC................................. Delaware
Coastal International Finance Ltd....................................... Honduras
Coastal Offshore Finance Ltd...................................... Cayman Islands
</TABLE>
4
<PAGE>
SUBSIDIARIES OF THE COASTAL CORPORATION
<TABLE>
<CAPTION>
State or Other Jurisdiction of
Incorporation or Organization
<S> <C>
Coastal Offshore Insurance Ltd............................. Bermuda
Coastal Great Lakes, Inc................................................ Delaware
Great Lakes Gas Transmission Limited Partnership (32.44%)**....... Delaware*
Empire State Pipeline Company, Inc...................................... New York
Empire State Pipeline (50%)**..................................... New York
Mid Michigan Gas Storage Company........................................ Michigan
CIC Stock Corporation.......................................................... Delaware
CIG Gas Storage Company................................................. Delaware
Young Gas Storage Company, Ltd. (47.5%)**......................... Colorado*
CIG Resources Company................................................... Delaware
CIG-Nitrotec Joint Venture (90%).................................. Colorado
CIG Production Company, L. P. (1%GP).............................. Delaware*
Fort Union Gas Gathering, LLC (10.01%)**.......................... Delaware
Johnstown Cogeneration Company, LLC (50%)**....................... Colorado
Keyes Helium Company, LLC (81.45%)................................ Colorado
CIG-Canyon Compression Company................................................. Delaware
CIG Gas Supply Company......................................................... Delaware
Wyco Development, LLC (50%)**........................................... Colorado
Wyoming Interstate Company, Ltd. (50% GP)............................... Colorado*
CIG Overthrust, Inc............................................................ Delaware
Overthrust Pipeline Company (10%)**..................................... Illinois
CIG Trailblazer Gas Company.................................................... Delaware
Coastal Alliance Pipeline Company, L.L.C. (50%)................................ Delaware
Alliance Pipeline, L.P. (14.44% LP)**................................... Delaware*
Colorado Interstate Gas Company................................................ Delaware
CIG Exploration, Inc.................................................... Delaware
Coastal Limited Ventures, Inc. (4.43%)............................ Texas
Coastal Oil & Gas Resources, Inc. (4.43%)......................... Delaware
CIG Field Services Company.............................................. Delaware
Colorado Water Supply Company........................................... Delaware
Colorado Interstate Production Company............................ Delaware
CIG Production Company, L.P. (99% LP)...................... Delaware*
Great Lakes Gas Transmission Company (50%)**................................... Delaware
Great Lakes Gas Transmission Limited Partnership (35.12%)**............. Delaware*
Wyoming Gas Supply, Inc........................................................ Delaware
Wyoming Interstate Company, Ltd (50% LP)................................ Colorado*
Coastal Oil & Gas Corporation......................................................... Delaware
COGC Resale Company............................................................ Delaware
Coastal Australia AC 96-3 Ltd.................................................. Cayman Islands
Coastal Oil & Gas Australia 20 Pty Ltd.................................. Australia
Coastal Australia AC 96-4 Ltd.................................................. Cayman Islands
Coastal Oil & Gas Australia 21 Pty Ltd.................................. Australia
Coastal BAS-97 Ltda............................................................ Brazil
Coastal BCAM-2 Ltda............................................................ Brazil
Coastal Buenos Aires I Ltd..................................................... Cayman Islands
Coastal Buenos Aires II Ltd.................................................... Cayman Islands
Coastal Buenos Aires III Ltd................................................... Cayman Islands
Coastal Buenos Aires IV Ltd.................................................... Cayman Islands
</TABLE>
5
<PAGE>
SUBSIDIARIES OF THE COASTAL CORPORATION
<TABLE>
<CAPTION>
State or Other Jurisdiction of
Incorporation or Organization
<S> <C>
Coastal Colombia Ltd........................................................... Cayman Islands
Coastal Development I Ltd...................................................... Cayman Islands
Coastal Development II Ltd..................................................... Cayman Islands
Coastal Oil & Gas Australia Pty Ltd..................................... Australia
Coastal Oil & Gas Canada, Inc........................................... Canada
Coastal Development III Ltd.................................................... Cayman Islands
Coastal Oil & Gas Australia 283 Pty Ltd................................. Australia
Coastal Development IV Ltd..................................................... Cayman Islands
CoastalDril, Inc............................................................... Delaware
Coastal Hungary Ltd............................................................ Hungary
Coastal Indonesia Bangko Ltd................................................... Cayman Islands
Coastal Indonesia Sampang Ltd.................................................. Cayman Islands
Coastal Javelina, Inc.......................................................... Delaware
Javelina Company (40%)**................................................ Texas*
Javelina Pipeline Company (40%)**....................................... Texas*
Coastal Limited Ventures, Inc. (73.6%)......................................... Texas
Coastal Oil & Gas Gathering, L.P. ............................................. Delaware*
Coastal Oil & Gas Holdings, Inc................................................ Delaware
Coastal Oil & Gas USA, L.P. (69% LP).................................... Delaware*
Coastal Oil & Gas Resources, Inc. (73.59%)..................................... Delaware
Coastal Oil & Gas USA, L.P. (1% GP)............................................ Delaware*
Coastal Peru Ltd............................................................... Cayman Islands
Coastal Peru 73 Ltd............................................................ Cayman Islands
Coastal Power Company................................................................. Delaware
ANRV-EP, Inc................................................................... Delaware
ANR Eagle Point, L.P.................................................... Delaware
Eagle Point Cogeneration Partnership (49.9%)**.................... New Jersey*
Coastal Bangchak Power Ltd..................................................... Cayman Islands
Coastal Henan Power Ltd........................................................ Cayman Islands
Coastal Henan Power I Ltd............................................... Cayman Islands
Coastal Henan Power II Ltd.............................................. Cayman Islands
Coastal Clark Investor Ltd..................................................... Cayman Islands
Coastal Clark Manager Ltd...................................................... Cayman Islands
Coastal Manager Ltd............................................................ Cayman Islands
Coastal Mexicana Northeast Ltd................................................. Cayman Islands
Coastal Mexicana Northwest Ltd................................................. Cayman Islands
Coastal Nanjing Investor Ltd................................................... Cayman Islands
Coastal Nanjing Power Ltd............................................... Cayman Islands
Coastal Nanjing Manager Ltd.................................................... Cayman Islands
Coastal Palembang Power Ltd.................................................... Cayman Islands
Coastal Palembang Power (Singapore) Pte Ltd............................. Singapore
Coastal Peenya Investor Ltd.................................................... Cayman Islands
Coastal Peenya Power Ltd................................................ Mauritius
Peenya Power Company (50%)**............................................ India
Coastal Peenya Manager Ltd..................................................... Cayman Islands
Coastal Power Central America Ltd.............................................. Cayman Islands
Coastal Power Dominicana Generation Ltd........................................ Cayman Islands
Coastal Itabo, Ltd...................................................... Cayman Islands
</TABLE>
6
<PAGE>
SUBSIDIARIES OF THE COASTAL CORPORATION
<TABLE>
<CAPTION>
State or Other Jurisdiction of
Incorporation or Organization
<S> <C>
Coastal Power Guatemala Distribution Ltd....................................... Cayman Islands
Coastal Power Guatemala Ltd.................................................... Cayman Islands
Coastal Power India (Cayman) Ltd............................................... Cayman Islands
Coastal Power India I Ltd............................................... Mauritius
Coastal Power International Ltd................................................ Cayman Islands
Compania de Electricidad de Puerto Plata, S.A. (48%)**.................. Dominican Republic
Energia Coastal Guatemala, S.A.......................................... Guatemala
Coastal Power International II Ltd............................................. Cayman Islands
Quetta Power Holding Company I Ltd. (50%)**............................. Cayman Islands
......Habibullah Coastal Power (Private) Company........................ Pakistan
......Quetta Power Holding Company II Ltd............................... Cayman Islands
Coastal Power International III Ltd............................................ Cayman Islands
Coastal Power International IV Ltd............................................. Cayman Islands
Coastal Power International V Ltd.............................................. Cayman Islands
Coastal Power Khulna Holding Ltd............................................... Cayman Islands
Coastal Khulna Power ApS................................................ Denmark
Khulna Power Company Ltd. (73.9%)**............................... Bangladesh
Coastal Power Lanka Ltd........................................................ Cayman Islands
Coastal Power Nicaragua Ltd.................................................... Cayman Islands
Tipitapa Power Company Ltd. (59%)**..................................... Cayman Islands
Coastal Power Nicaragua Holding Company Ltd............................. Cayman Islands
CEG Finance Company Ltd................................................. Cayman Islands
Coastal Power Noapara Ltd...................................................... Cayman Islands
Coastal Power Panama Generation Ltd............................................ Cayman Islands
Coastal Power Panama Investor, S.A...................................... Panama
Pedregal Power Company S.R.L...................................... Panama
Americas Holding Corp. (49%)**.................................... Panama
Americas Generation Corp................................... Panama
Coastal Power Pecem Ltd........................................................ Cayman Islands
Coastal Saba Investor Ltd...................................................... Cayman Islands
Coastal Saba Investor II Ltd............................................ Cayman Islands
Coastal Saba Power Ltd............................................ Mauritius
Saba Power Company (Private) Limited**..................... Pakistan
Coastal Saba Manager II Ltd............................................. Cayman Islands
Coastal Saba Manager Ltd....................................................... Cayman Islands
Coastal Salvadoran Power Ltd................................................... Cayman Islands
Coastal Nejapa Ltd. (90%)............................................... Cayman Islands
Coastal Suzhou Investor Ltd.................................................... Cayman Islands
Coastal Suzhou Power Ltd................................................ Cayman Islands
Suzhou New District Cogeneration Company (60%)**.................. Jiangsu Province, China
Coastal Suzhou Manager Ltd..................................................... Cayman Islands
Coastal Gusu Heat & Power Ltd........................................... Cayman Islands
Suzhou Suda Cogeneration Power Company Ltd. (60%)**............... China
Coastal Wisconsin Energy, LLC.................................................. Wisconsin
Coastal Wisconsin Manager, Inc................................................. Delaware
Coastal Wisconsin Power, Inc................................................... Delaware
Coastal Wuxi Investor Ltd...................................................... Cayman Islands
Coastal Wuxi New District Ltd........................................... Cayman Islands
</TABLE>
7
<PAGE>
SUBSIDIARIES OF THE COASTAL CORPORATION
<TABLE>
<CAPTION>
State or Other Jurisdiction of
Incorporation or Organization
<S> <C>
Wuxi Shunda Gas Turbine Company (60%)**........................... China
Coastal Wuxi Manager Ltd....................................................... Cayman Islands
Coastal Wuxi Power Ltd.................................................. Cayman Islands
Wuxi Huada Gas Turbine Electric Power Company (60%)**............. Jiangsu Province, China
Front Range Power, LLC (51%)**................................................. Delaware
Fulton Cogeneration Associates, L.P. (32-1/3% LP).............................. New York*
Thermal Power Salvador Ltd..................................................... Cayman Islands
El Salvador Distribution Holding Company Ltd............................ Cayman Islands
Coastal States Management Corporation................................................. Colorado
ABCO Aviation, Inc............................................................. Delaware
ABCO Leasing, Inc.............................................................. Delaware
ANR Media Company.............................................................. Michigan
Coastal (Cayman Islands) Construction Company Ltd.............................. Cayman Islands
Coastal do Brasil S/C Ltda..................................................... Brazil
Coastal Travel Mart, Inc....................................................... Delaware
Rancho Paloma Company, S.A. de C.V............................................. Mexico
Coastal States Trading, Inc........................................................... Delaware
Atchafalaya Pipeline, L.L.C. (33-1/3%)**....................................... Delaware
Coastal Bridger Lake Pipeline Corporation...................................... Delaware
Coastal Technology, Inc............................................................... Delaware
Coastal Technology Dominicana, S.A............................................. Dominican Republic
Coastal Technology Ltd......................................................... Cayman Islands
Coastal Technology Palembang, Inc....................................... South Dakota
Coastal Technology Palembang (Cayman) Ltd......................... Cayman Islands
Palembang Coastal Technology (Singapore) Pte Ltd........... Singapore
Coastal Technology Nicaragua S.A............................................... Nicaragua
Coastal Technology Pakistan (Private) Limited.................................. Pakistan
Coastal Technology Salvador, S.A. de C.V....................................... El Salvador
Coastal Unilube, Inc.................................................................. Tennessee
Coastal Unilube of Iowa L.C........................................................... Iowa
Coastalcorp.Com, Inc.................................................................. Delaware
Coastalcorp.Com Properties, Inc................................................ Delaware
Cosbel Petroleum Corporation.......................................................... Delaware
Coastal Canada Petroleum, Inc.................................................. New Brunswick,
Canada
Alliance Pipeline Limited Partnership (14.44% LP)....................... Canada*
Engage Energy Canada, L.P. (50%)**...................................... Canada*
Coastal Fuels Marketing, Inc................................................... Florida
Coastal Fuels of Puerto Rico, Inc....................................... Delaware
Coastal Offshore Fuels, Inc............................................. Liberia
Coastal Terminals, Inc.................................................. Florida
Coastal Tug and Barge, Inc.............................................. Florida
Coastal Oil & Gas Resources, Inc. (1%)......................................... Delaware
Coastal Oil New England, Inc................................................... Massachusetts
Coastal Oil New York, Inc...................................................... Delaware
Coscol Petroleum Corporation.......................................................... Delaware
Coastal CFC Ltd................................................................ Cayman Islands
Coastal Baltica Holding Company Ltd. (50%)**............................ Cayman Islands
Coastal Baltica Marketing Company Ltd. (50%)**.......................... Cayman Islands
</TABLE>
8
<PAGE>
SUBSIDIARIES OF THE COASTAL CORPORATION
<TABLE>
<CAPTION>
State or Other Jurisdiction of
Incorporation or Organization
<S> <C>
Enterprise Investments Ltd. (50%)**..................................... Cayman Islands
Estonia Holdings Ltd. (50%)**........................................... Cayman Islands
Coastal Coker Corporation Aruba N.V............................................ Aruba
Coastal India Petroleum Ltd.................................................... Cayman Islands
Coastal Energy Resources Ltd............................................ Mauritius
Coastal Wartsila Petroleum Private Limited (50%)**................ India
Coastal LPG Dominicana Ltd..................................................... Cayman Islands
Coastal Petroleum Dominicana S.A........................................ Dominican Republic
Coastal Securities Company Limited............................................. Bermuda
Coastal Aruba Holding Company N.V. (51.25%)............................. Aruba
Coastal Aruba Fuels Company N.V................................... Aruba
Coastal Aruba Maintenance/Operations Company N.V.................. Aruba
Coastal Aruba Refining Company N.V................................ Aruba
Clark Pipeline and Depot Company, Inc. (50%)**............. Philippines
Coastal Energy of Panama, Inc.............................. Panama
Coastal Petroleum N.V...................................... Aruba
Coastal Fuji Oil Ltd. (50%)**........................ Cayman Islands
Coastal Petroleum Argentina, S.A..................... Argentina
Coastal Petroleum N.V. Chile Limitada (99%).......... Chile*
United Summit Coastal Oil Ltd. (50%)**............... Bangladesh
Coastal Petroleum Overseas N.V.................................... Aruba
Coastal Aruba Investor N.V................................. Aruba
Prima Purveyors Ltd. (50%)**......................... Cayman Islands
Coastal Petroleum Dominicana, Ltd. (50%)**........... Cayman Islands
Subic Bay Distribution, Inc. (50%)**.............................. Philippines
Subic Bay Energy Company Ltd. (50%)**............................. Cayman Islands
Subic Bay Fuels Company, Inc. (50%)**............................. Philippines
Subic Bay Petroleum Products Ltd.................................. Cayman Islands
Coastal Belcher Petroleum Pte. Ltd...................................... Singapore
Coastal (Bermuda) Petroleum Limited..................................... Bermuda
Coastal Cayman Finance Ltd........................................ Cayman Islands
Coastal Management Services (Singapore) Pte. Ltd........................ Singapore
Coastal Petroleum (Far East) Pte Ltd.................................... Singapore
Holborn Oil Trading Limited............................................. Bermuda
Coastal (Subic Bay) Petroleum, Inc............................................. Texas
Coastal Subic Bay Terminal, Inc......................................... Philippines
Coastal Stock Company Limited.................................................. Bermuda
Coastal Aruba Holding N.V. (32.2%)...................................... Aruba
Coastal Europe Limited.................................................. England
Coastal Services Petroleum (U.K.) Limited......................... England
Coastal States Petroleum (U.K.) Limited........................... England
Coastal States Tankers (U.K.) Limited............................. England
Colbourne Insurance Company Limited............................... England
Coastal Tankships U.S.A., Inc.................................................. Delaware
Coscol Marine Corporation...................................................... Texas
Coastal Mart of Oklahoma, Inc........................................... Oklahoma
Coastal Interstate Corporation.................................... Delaware
Texas Tank Ship Agency, Inc.................................................... Delaware
</TABLE>
9
<PAGE>
The above subsidiaries, with the exception of those indicated with a
double asterisk (**) are included in the Consolidated Financial Statements of
The Coastal Corporation. The names of certain subsidiaries have been omitted
from the above listing because such subsidiaries, considered in the aggregate as
a single subsidiary, would not constitute a significant subsidiary. The voting
stock of each corporation is owned 100% by its immediate parent or by its
immediate parent together with an affiliate of such parent, unless otherwise
indicated above.
* Partnership
** Not consolidated
10
<PAGE>
Exhibit 23
CONSENT OF DELOITTE & TOUCHE LLP
We consent to the incorporation by reference in Registration Statements No.
33-53952, 33-5214, 33-5218, 33-42696, 333-70285 and 333-72153 of The Coastal
Corporation on Forms S-8 and Registration Statements No. 333-08135, 333-81095
and 333-93463 of The Coastal Corporation on Forms S-3 of our report dated
February 8, 2000, appearing in this Annual Report on Form 10-K of The Coastal
Corporation for the year ended December 31, 1999.
DELOITTE & TOUCHE LLP
Houston, Texas
February 22, 2000
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND> THE SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION
EXTRACTED FROM THE COASTAL CORPORATION FORM 10-K ANNUAL
REPORT FOR THE PERIOD ENDED DECEMBER 31, 1999 AND IS
QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH
FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> DEC-31-1999
<CASH> 44
<SECURITIES> 0
<RECEIVABLES> 1,933
<ALLOWANCES> 0
<INVENTORY> 733
<CURRENT-ASSETS> 2,924
<PP&E> 13,297
<DEPRECIATION> 3,960
<TOTAL-ASSETS> 15,123
<CURRENT-LIABILITIES> 3,038
<BONDS> 4,798
<COMMON> 73
0
0
<OTHER-SE> 3,864
<TOTAL-LIABILITY-AND-EQUITY> 15,123
<SALES> 8,197
<TOTAL-REVENUES> 8,312
<CGS> 5,149
<TOTAL-COSTS> 7,316
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 323
<INCOME-PRETAX> 673
<INCOME-TAX> 174
<INCOME-CONTINUING> 499
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 499
<EPS-BASIC> 2.34
<EPS-DILUTED> 2.30
</TABLE>
