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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, 1998 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 ____________
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 (I.R.S. Employer
incorporation or organization) 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
10-1/4% Senior Debentures 8-1/8% Senior Notes } New York Stock Exchange
10-3/8% Senior Notes 7-3/4% Senior Debentures
10-3/4% Senior Debentures 7.42% Senior Debentures
10% Senior Notes 6.70% Senior Debentures
9-3/4% Senior Debentures 6.50% Senior Debentures
8-3/4% Senior Notes 6.95% Senior Debentures
9-5/8% Senior Debentures 6.375% Senior Debentures
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 March 10, 1999, there were outstanding 212,486,660 shares of common
stock, 351,624 shares of Class A common stock, 55,809 shares of $1.19 Cumulative
Convertible Preferred Stock, Series A, 60,696 shares of $1.83 Cumulative
Convertible Preferred Stock, Series B and 27,714 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 $6.81 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 1999 Annual Meeting of
Stockholders, filed pursuant to Regulation 14A under the Securities Exchange Act
of 1934, 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
Natural Gas Systems......................................... 1
Operations.............................................. 1
ANR Pipeline............................................ 2
Colorado................................................ 3
ANR Storage Company..................................... 4
Gas System Reserves..................................... 4
Alliance Pipeline Project............................... 5
Wyoming Interstate Company, Ltd......................... 5
Great Lakes Gas Transmission Limited Partnership........ 5
Unregulated Gas Operations.............................. 6
Regulations Affecting Gas Systems....................... 6
Refining, Marketing and Distribution, and Chemicals......... 7
Exploration and Production.................................. 10
Coal........................................................ 15
Power....................................................... 16
Competition................................................. 18
Environmental............................................... 18
Other Developments.......................................... 19
2. Properties...................................................... 19
3. Legal Proceedings............................................... 20
4. Submission of Matters to a Vote of Security Holders............. 21
PART II
5. Market for the Registrant's Common Equity and Related
Stockholder Matters............................................. 22
6. Selected Financial Data......................................... 23
7. Management's Discussion and Analysis of Financial Condition
and Results of Operations....................................... 23
7A. Quantitative and Qualitative Disclosures About Market Risk...... 24
8. Financial Statements and Supplementary Data..................... 24
9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure........................................ 24
PART III
10. Directors and Executive Officers of the Registrant............... 25
11. Executive Compensation........................................... 26
12. Security Ownership of Certain Beneficial Owners and Management... 26
13. Certain Relationships and Related Transactions................... 26
PART IV
14. Exhibits, Financial Statement Schedules, and Reports on
Form 8-K......................................................... 27
(i)
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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
"EPA" means 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
"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)
"Long tons" means weight measurement of 2,240 pounds
"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
"TransCanada" means TransCanada PipeLines Limited
"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, changing
legislation and regulations, and the impact of the Year 2000 issue. 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 13,300 persons as
of December 31, 1998.
Annual Reports on Form 10-K for the year ended December 31, 1998 are also
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, 1998, 1997 and 1996, 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.
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 transportation, storage, gathering and
balancing of natural gas. 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 federal waters. ANR
Pipeline operates two offshore gas pipeline systems in the Gulf of Mexico which
are owned by High Island Offshore System, a limited liability company, and U-T
Offshore System, a general partnership, both of which are composed of ANR
Pipeline subsidiaries and subsidiaries of other companies. ANR Pipeline operates
wholly owned and partially owned storage fields of ANR Storage in Michigan. ANR
Pipeline also operates Empire State Pipeline, an intrastate pipeline extending
from Niagara Falls to Syracuse, New York, in which an affiliate of ANR Pipeline
has a 50% interest.
ANR Pipeline's two interconnected, large-diameter multiple pipeline systems
transport gas to the Midwest and the Northeast from (a) the Hugoton Field and
other fields in the Anadarko Basin in Texas and Oklahoma, (b) the Louisiana
onshore and the Louisiana and Texas offshore areas and (c) gas originating in
other basins received through interconnections located throughout its system.
ANR Pipeline's principal pipeline facilities at December 31, 1998 consisted
of 10,600 miles of pipeline and 74 compressor stations with 1,022,031 installed
horsepower. At December 31, 1998, the design peak day delivery capacity of the
transmission system, considering supply sources, storage, markets and
transportation for others, was approximately 5.9 Bcf per day.
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
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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, 1998 consisted of 4,351 miles of pipeline and 58
compressor stations with approximately 296,300 installed horsepower. At December
31, 1998, 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 2,372 miles of gathering lines and
approximately 50,700 horsepower of compression. Colorado owned and operated five
gas processing plants in 1998. These plants, with a total operating capacity of
approximately 512 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, 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 has issued orders which have resulted in more
competition within the natural gas industry. This competition has intensified,
resulting in more rate competition among pipelines in order to increase and
maintain market share and maximize capacity utilization. ANR Pipeline's and
Colorado's transportation and storage services are influenced by their
respective customers' access to alternative service providers and the price of
such services. The FERC's orders have also resulted in competition between ANR
Pipeline and Colorado and their respective customers by allowing the customers
to resell their unused capacity.
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 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 Services
ANR Pipeline offers an array of transportation, storage and balancing
service options under Order 636. Additional information concerning Order 636,
including transportation and storage, is set forth in "Management's Discussion
and Analysis of Financial Condition and Results of Operations" included herein.
ANR Pipeline transports gas to markets on its system and also transports
gas to other markets off its system under transportation agreements with other
companies, including distributors, intrastate and interstate pipelines,
producers, brokers, marketers and end users. Transportation service revenues
amounted to $481 million for 1998 compared to $497 million for 1997 and $510
million for 1996. During 1998, approximately 23% of ANR Pipeline's
transportation service revenues were from its three largest customers: Wisconsin
Gas Company, Wisconsin Electric Power Company Inc. and
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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 1998, ANR Pipeline provided approximately 67% and
30% of the total gas requirements of Wisconsin and Michigan, respectively.
ANR Pipeline's system deliveries for the years 1998, 1997 and 1996 were as
follows:
Total System Daily Average
Year Deliveries System Deliveries
(Bcf) (MMcf)
1998 1,354 3,710
1997 1,424 3,901
1996 1,517 4,145
Gas Storage
ANR Pipeline has approximately 202 Bcf of underground working gas storage
capacity, with a maximum day delivery capacity of 3 Bcf as late as the end of
February. 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. Gas storage revenues
amounted to $139 million for 1998 as compared to $146 million for 1997 and $131
million for 1996.
COLORADO
Gas Sales, Storage and Transportation
Colorado's gas sales consist primarily of Company-owned production.
Additionally, Colorado engages in "open access" storage and transportation of
gas owned by third parties.
Pursuant to an operating agreement with an affiliate, Colorado operates the
Young Gas Storage Field located in northeastern Colorado. The field has a
working gas storage capacity of 5.3 Bcf, with a peak day delivery capacity of
approximately 200 MMcf per day. Such capacity is fully subscribed under 30-year
contracts.
Colorado's deliveries for the years 1998, 1997 and 1996 were as follows:
Total System Daily Average
Year Deliveries System Deliveries
(Bcf) (MMcf)
1998 480 1,315
1997 486 1,333
1996 475 1,298
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.
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The gas processing plants recovered approximately 46 million gallons of
liquid hydrocarbons in 1998 compared to 55 million gallons in 1997, and 66
million gallons in 1996, as well as 300 long tons of sulfur in 1998, compared to
500 long tons in 1997 and 3,100 long tons in 1996. Additionally, Colorado
processed approximately 25 million gallons of liquid hydrocarbons owned by
others in 1997 compared to 24 million gallons in 1997 and 6 million gallons in
1996.
Colorado operates two helium processing facilities, one located in eastern
Colorado and the other in the western Oklahoma panhandle area. These helium
facilities are partially owned by affiliates of Colorado.
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 gas
producing areas in the United States, 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 79% 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 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 and Viking Gas Transmission Company ("Viking")
and a new interconnection with Northern Border Pipeline Company ("Northern
Border").
Gas deliverability available to shippers on ANR Pipeline's system from the
Mid-Continent, Rocky Mountain and Gulf Coast producing areas through direct
connections and interconnecting pipelines and gatherers is approximately 4,000
MMcf per day. Deliverability of 1,100 MMcf per day from Western Canada is
accessible to ANR Pipeline shippers through the Great Lakes and Viking
interconnections. The interconnection with Northern Border has the capacity to
provide shippers access to an additional 500 MMcf per day of Western Canadian
gas.
ANR Pipeline remains active in locating and connecting new sources of
natural gas to facilitate transportation arrangements made by third-party
shippers. During 1998, field development, newly connected gas wells, gas
production facilities and pipeline interconnections contributed over 1,600 MMcf
per day to total deliverability accessible to shippers on ANR Pipeline's system.
Colorado
Colorado has reported in its Form 10-K for the year ended December 31,
1998, its Natural Gas System reserves based on information prepared by
Huddleston, the Company's independent engineers, while its Exploration and
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Production segment reserves are as prepared by the Company and reviewed by
Huddleston. Additional information is set forth in "Reserves Dedicated to a
Particular Customer," presented below.
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
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. Alliance will interconnect
with, among other pipelines, ANR Pipeline's proposed SupplyLink project and
through SupplyLink to the proposed Independence Pipeline, in which an ANR
subsidiary owns a one-third general partnership interest. The Independence
Pipeline will interconnect with the SupplyLink pipeline at Defiance, Ohio and
will extend 400 miles to Leidy, Pennsylvania. 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.
WYOMING INTERSTATE COMPANY, LTD.
WIC, a limited partnership owned by two wholly owned Coastal subsidiaries,
owns a 269-mile, 36-inch diameter pipeline across southern Wyoming. The WIC
pipeline connects with an 88-mile western segment in which a Coastal subsidiary
has a 10% interest and 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 756 MMcf daily. In
1998, the WIC line transported an average of 622 MMcf daily, compared to 546
MMcf daily and 486 MMcf daily in 1997 and 1996, respectively. In November 1998,
WIC placed in service a further expansion of facilities involving the addition
of 7,380 horsepower of compression at WIC's Laramie and Cheyenne compressor
stations, which in turn created additional capacity of 52 MMcf per day on the
Powder River Lateral. In December, WIC filed with the FERC for approval to
construct the Medicine Bow Lateral, a 151-mile pipeline for transporting
coal-bed methane gas from the Powder River Basin to WIC's main line west of
Cheyenne, Wyoming. WIC has obtained long-term transportation commitments for the
Medicine Bow Lateral beginning at 184 MMcf per day and increasing to 454 MMcf
per day over a four-year period. The initial phase of this $80.5 million project
will provide approximately 269 MMcf per day of capacity, and subject to timely
receipt of regulatory approvals, is expected to be in-service by January 1,
2000. WIC intends to file with the FERC in the future for approval to construct
additional facilities on the Medicine Bow Lateral to increase capacity to meet
the additional contractual commitments.
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 907 Bcf in 1998 as
compared to 910 Bcf in 1997 and 933 Bcf in 1996. 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.
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UNREGULATED GAS OPERATIONS
Coastal's unregulated natural gas business, including certain of Coastal's
natural gas gathering and processing, gas supply and marketing activities, 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 gathering and
processing assets in Alabama, Colorado, Kansas, Louisiana, Oklahoma, Texas,
Utah, Wyoming, and offshore in the Gulf of Mexico. These assets include
interests in more than 3,800 miles of gathering pipelines, which collect gas
from almost 3,800 wells. CFSC gathered approximately 1 Bcf per day of gas in
1998, 1997 and 1996. CFSC and its affiliates also have an ownership interest in
ten gas processing plants, six of which are operated by CFSC. Natural gas
liquids produced at CFSC operated plants and from gas processed by others for
CFSC averaged more than 23,000 barrels per day in 1998, as compared to more than
25,000 barrels per day in 1997 and almost 23,000 barrels per day in 1996.
CFSC holds a 13.6% interest in the 250-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 Alabama, where CFSC holds an interest in a 600 MMcf
per day gas processing plant and a 40 MW cogeneration plant. The cogeneration
plant will provide power and process heat for the gas plant. The gas plant and
associated cogeneration plant are expected to be operational in 1999.
In November 1998, CFSC acquired a 60 MMcf per day gas processing plant and
480 miles of gas gathering systems in Colorado and Utah. During 1998, CFSC also
completed the sale of certain Mid-Continent gathering and processing assets.
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 was formed in February 1997 and is a
joint venture of Coastal (50%) and Westcoast Energy Inc. (50%), a major Canadian
natural gas company. In 1998, Engage had physical sales volumes averaging 7 Bcf
per day of natural gas, and annual power sales of 36 million megawatt hours.
REGULATIONS AFFECTING GAS SYSTEMS
General
Under the NGA, the FERC has jurisdiction over ANR Pipeline, Colorado, WIC,
ANR Storage and Great Lakes 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 and Great
Lakes 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 and Great Lakes 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 Department of Transportation. Additionally, subsidiaries of
the Company are subject to similar safety requirements from the Department of
Labor's Occupational Safety and Health Administration related to their
processing plants. Operations on United States government land are regulated by
the Department of the Interior.
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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."
On January 31, 1996, the FERC issued a "Statement of Policy and Request for
Comments" ("Policy"). Under this Policy, (i) a pipeline and a customer are
allowed to negotiate a contract which provides for rates and charges that exceed
the pipeline's posted maximum tariff rates, provided that the customer agreeing
to such negotiated rates has the ability to elect to receive service at the
pipeline's posted maximum rate (known as a "recourse rate"), and (ii) a pipeline
must also make subsequent tariff filings each time the pipeline negotiates a
rate for service which is outside of the minimum and maximum range for the
pipeline's cost-based recourse rates. To implement this Policy, a pipeline must
make an initial tariff filing with the FERC to indicate that it intends to
contract for services under this Policy. CIG has received FERC authority to
enter into negotiated rate transactions. Separately, the FERC has determined
that pipelines who seek to include negotiated rate transactions in the discount
adjustment used to calculate their rates must file tariff sheets demonstrating
that existing customers who purchase service under the pipeline's
cost-of-service rates will not be harmed by negotiated rate discounts.
On July 29, 1998, the FERC issued a "Notice of Proposed Rulemaking," in
which the FERC has proposed a number of further 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. The due date for comments on both of these
matters has been rescheduled twice and is currently scheduled for April 22,
1999. The FERC has indicated that it may consider both proposals together
inasmuch as they raise several common issues.
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. After the filing of
testimony by WIC and other parties on July 2, 1998, WIC filed a settlement offer
which, if approved, would have resolved all of the issues in the case. That
settlement, however, was remanded to the Administrative Law Judge ("ALJ")
because of opposition to the settlement by certain parties. In response to the
remand, WIC and the parties have resubmitted a settlement offer which contains
the same substantive provisions, but provides for the Commission to approve the
settlement for some, if not all, parties, with the "severed" parties being able
to litigate their issues in the case. The ALJ has certified the new settlement
to the FERC, and dates for filing briefs on the new settlement have been
established.
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.
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.
7
<PAGE>
Refining
Subsidiaries of the Company operated their refineries at 85% of average
combined capacity in 1998 compared to 89% in 1997 and at 97% in 1996. The
aggregate sales volumes (millions of barrels) of Coastal's wholly owned
refineries for the three years ended December 31, 1998 were 154.4 (1998), 160.7
(1997) and 160.4 (1996). Of the total refinery sales in 1998, 27% was gasoline,
43% was middle distillates, such as jet fuel, diesel fuel and home heating oil,
and 30% was heavy industrial fuels and other products.
At December 31, 1998, average daily throughput and storage capacity at the
Company's wholly owned refineries are set forth below:
<TABLE>
<CAPTION>
Daily Average Daily Storage
Capacity Throughput (Barrels) Capacity
--------------------------
Refinery Location (Barrels) 1998 1997 (Barrels)
- -------- -------- --------- ----------- ----------- ---------
<S> <C> <C> <C> <C>
Aruba Aruba 225,000 162,300 180,600 15,300,000
Corpus Christi Corpus Christi, Texas 100,000 88,600 87,100 7,100,000
Eagle Point Westville, New Jersey 140,000 140,400 133,400 10,600,000
Mobile Mobile, Alabama 18,000 10,400 12,900 600,000
----------- ----------- ----------- --------------
Total 483,000 401,700 414,000 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 1,800,000 barrels for crude oil and 5,200,000 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 1998, 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 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.
8
<PAGE>
Sales volumes for Coastal Chem and St. Helens for the three years ended
December 31, 1998, are set forth below (thousands of tons):
<TABLE>
<CAPTION>
1998 1997 1996
-------- -------- ---------
<S> <C> <C> <C>
Agricultural Sales................................................... 346 340 276
Industrial Sales..................................................... 550 566 608
MTBE................................................................. 210 223 204
-------- -------- ---------
Total .......................................................... 1,106 1,129 1,088
======== ======== =========
</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 temporarily 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, 1998, was 203,500 (1998), 338,400 (1997) and 289,100
(1996).
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, 1998, was 45,000. 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, 1998, are set forth
below (thousands of barrels):
<TABLE>
<CAPTION>
Type of Sale 1998 1997 1996
- ------------ -------- --------- ---------
<S> <C> <C> <C>
Company Produced Refined Products........................................ 154,427 160,703 160,383
Refined Products Purchased from Others................................... 131,508 101,495 130,240
Natural Gas Liquids...................................................... 14,292 16,593 16,205
-------- --------- ---------
Total............................... 300,227 278,791 306,828
======== ========= =========
</TABLE>
Subsidiaries of the Company market refined products and liquefied petroleum
gas at wholesale in 32 states plus Canada and Panama through 223 terminals.
Coastal Refining & Marketing, Inc. serves customers primarily in the Midwest,
Mississippi Valley and the Southwest through 168 product and liquefied petroleum
gas terminals in 23 states. On the Gulf and East Coasts, divisions of Coastal
Refining & Marketing, Inc. serve home, industry, utility, defense and marine
energy needs. In 1998, these divisions' sales volumes were 67.6 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.
9
<PAGE>
Coastal Baltica Holding Company Ltd., a joint venture in which a Coastal
subsidiary is a 50% partner, commenced operations at its terminal and new port
facilities near Tallinn, Estonia on the Baltic Sea in 1996. The terminal
operation handled imports and exports of approximately 13.5 million barrels of
petroleum products in 1998, 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 approximately 1,550 Coastal branded
outlets, with 414 of those outlets operated by the Company. Fleet fueling
operations include 23 outlets in Texas and 6 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 14 warehouses servicing customers in 45
states, plus the District of Columbia, Puerto Rico and 20 foreign countries.
Transportation. The Company's transportation facilities include petroleum
liquids pipelines, tank cars, tankers, tank trucks and barges. Coastal operates
over 1,700 miles of pipeline for gathering and transporting an average of
223,123 barrels daily of crude oil, condensate, natural gas liquids and refined
products. These pipelines include 304 miles of crude oil pipelines, 718 miles of
refined products pipelines, and 582 miles of natural gas liquids pipelines, all
located principally in Texas, in which the Company has approximately a 32%
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. In 1998, throughput of crude oil pipelines averaged
15,323 barrels per day, compared to 13,117 barrels per day in 1997 and 14,323
barrels per day in 1996. In 1998, throughput of refined products and natural gas
liquid pipelines averaged 207,800 barrels per day, compared to 216,204 barrels
per day in 1997 and 215,897 barrels per day in 1996.
The marine transportation fleet at December 31, 1998 consisted of 15 tug
boats, 19 oil barges, 4 owned tankers and 5 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.
EXPLORATION AND PRODUCTION
Gas and Oil Properties
Coastal subsidiaries are engaged in gas and oil exploration, development
and production operations principally in California, Colorado, Kansas,
Louisiana, New Mexico, Oklahoma, Texas, Utah, West Virginia, Wyoming and
offshore in the Gulf of Mexico. In addition, Coastal subsidiaries have
exploration and production rights in Argentina, Australia, Brazil, Hungary,
Indonesia and Peru.
In 1998, the Company's domestic exploration and production operations sold
approximately 10% of all the gas it produced to certain of Coastal's wholly
owned natural gas system subsidiaries and approximately 82% to Engage. The
Company's domestic operations also make short-term gas sales directly to
industrial users and distribution companies to increase utilization of its
excess current gas production capacity. 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.
10
<PAGE>
Acreage held under gas and oil mineral leases as of December 31, 1998 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.......................................... 542 430 1,059 573
Offshore......................................... 453 328 240 151
--------- -------- --------- ---------
Total Domestic................................... 995 758 1,299 724
--------- -------- --------- ---------
International
Argentina........................................ 9,850 2,462 - -
Australia........................................ 1,770 614 - -
Brazil........................................... 131 52 - -
Hungary.......................................... 568 568 - -
Indonesia........................................ 1,374 443 - -
Peru............................................. 2,813 1,407 - -
--------- -------- --------- ---------
Total International.............................. 16,506 5,546 - -
--------- -------- --------- ---------
Total Exploration and Production................. 17,501 6,304 1,299 724
--------- -------- --------- ---------
Natural Gas Systems
-------------------
Domestic Onshore....................................... - - 263 259
--------- -------- --------- ---------
Total Acreage.......................................... 17,501 6,304 1,562 983
========= ======== ========= =========
</TABLE>
The domestic net developed acreage is concentrated principally in Texas
(30%), Utah (31%), offshore Gulf of Mexico (15%), Colorado (13%) and Kansas
(5%). Approximately 11%, 8% and 11% of the Company's total domestic net
undeveloped acreage is under leases that have minimum remaining primary terms
expiring in 1999, 2000 and 2001, respectively.
Productive wells as of December 31, 1998 are as follows (domestic):
<TABLE>
<CAPTION>
Type of Well Gross Net
------------------------------------------------------------------------------------ --------- ---------
<S> <C> <C>
Exploration and Production
--------------------------
Oil............................................................................ 611 362
Gas............................................................................ 2,465 1,640
--------- ---------
Total Exploration and Production............................................... 3,076 2,002
--------- ---------
Natural Gas Systems
-------------------
Oil............................................................................ 9 8
Gas............................................................................ 777 773
--------- ---------
Total Natural Gas Systems...................................................... 786 781
--------- ---------
Total.................................................................... 3,862 2,783
========= =========
</TABLE>
11
<PAGE>
Exploration and Drilling
During 1998, Coastal's domestic subsidiaries participated in drilling 212
gross wells, 158.3 net wells, to the Company's interest. Coastal's participation
in wells drilled in the three years ended December 31, 1998, is summarized as
follows:
<TABLE>
<CAPTION>
Exploration and Production 1998 1997 1996
-------------------------- ------------------- ------------------- --------------------
Exploratory Wells Gross Net Gross Net Gross Net
----------------- -------- -------- --------- -------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
Oil...................... - - - - - -
Gas...................... 7 5.1 8 3.3 7 2.3
Dry Holes................ 7 3.4 5 2.9 4 1.9
-------- -------- --------- -------- --------- ---------
14 8.5 13 6.2 11 4.2
======== ======== ========= ======== ========= =========
Development Wells
-----------------
Oil...................... 4 2.9 2 1.7 5 1.6
Gas...................... 186 139.5 128 96.7 80 56.8
Dry Holes................ 2 1.4 4 2.2 3 1.4
-------- -------- --------- -------- --------- ---------
192 143.8 134 100.6 88 59.8
======== ======== ========= ======== ========= =========
Natural Gas Systems
-------------------
Development Wells
-----------------
Oil...................... - - - - 2 2.0
Gas...................... 6 6.0 3 3.0 8 8.0
Dry Holes................ - - - - - -
-------- -------- --------- -------- --------- ---------
6 6.0 3 3.0 10 10.0
======== ======== ========= ======== ========= =========
Total.......................... 212 158.3 150 109.8 109 74.0
======== ======== ========= ======== ========= =========
</TABLE>
Wells in progress as of December 31, 1998 are as follows (domestic):
<TABLE>
<CAPTION>
Type of Well Gross Net
------------------------------------------------------------------------------------- --------- ---------
<S> <C> <C>
Exploration and Production
--------------------------
Exploratory.................................................................... 3 2.1
Development.................................................................... 23 18.9
--------- ---------
Total Exploration and Production............................................... 26 21.0
--------- ---------
Natural Gas Systems
-------------------
Exploratory.................................................................... - -
Development.................................................................... - -
--------- ---------
Total Natural Gas Systems...................................................... - -
--------- ---------
Total.......................................................................... 26 21.0
========= =========
</TABLE>
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.
12
<PAGE>
In 1998, the Texas Coastal Plain continued its significant contribution
with net average production of approximately 220 MMcf per day for the second
consecutive year. Redevelopment of the Jeffress Field, beginning in 1995, led
the way to achieving this current production level. Field production grew from
its 20 MMcf per day 1995 level to a 1998 average of 160 MMcf per day. The
Company has acquired several additional properties in the immediate Jeffress
area, and the redevelopment of these properties has added net equivalent
reserves of 235 Bcf.
At the end of 1998, Coastal held interests in 145 blocks and 58 platforms
in the Gulf of Mexico. Net annual 1998 natural gas production increased to 191
MMcf per day from 1997's average of 119 MMcf per day. Oil and condensate
production averaged 7,511 barrels per day in 1998 compared to an average level
of 3,557 barrels per day in 1997. The Company operates 41 of the platforms as
compared with 36 at the end of the previous year.
In November 1998, Coastal Oil & Gas Corporation ("COGC") acquired interests
in 21 oil and gas producing fields and approximately 305,000 acres of producing
and non-producing leasehold interests in the Uinta Basin of Utah and the
Piceance Basin of Colorado - two gas basins in the Rocky Mountains. Average net
gas production for the Rocky Mountain area was 79 MMcf per day in 1998 as
compared with 67 MMcf per day in 1997.
In 1998, Coastal positioned itself for active exploration and development
programs in Canada, Brazil and Australia to be undertaken in 1999. In Canada,
Coastal will seek to develop or acquire production to support its shipping
commitment on the Alliance Pipeline. In Australia, Coastal plans to begin
exploration of two operated leases off the continent's northern coast in the
Timor Sea. In October 1998, COGC contracted with Petroleo Brasileiro S.A., the
national oil company of Brazil, to participate in the exploration and production
of two offshore concession blocks in the Camamu Basin.
Gas and Oil Production
Natural gas production during 1998 averaged 616 MMcf daily, compared to 540
MMcf daily in 1997. Production from non-pipeline-owned wells averaged 509 MMcf
daily in 1998, compared to 436 MMcf daily in 1997. Crude oil, condensate and
natural gas liquids production averaged 15,401 barrels daily in 1998, compared
to 13,736 barrels daily in 1997.
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, 1998:
<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
--------------------------
1998 185,732 3,725 1,633 220
1997 159,127 3,425 1,224 308
1996 129,149 3,885 853 324
Natural Gas Systems
-------------------
1998 39,058 44 - -
1997 38,135 57 - -
1996 39,405 23 - -
</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 lease 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.
13
<PAGE>
The following table summarizes sales price and production cost information
for domestic exploration and production operations during the three years ended
December 31, 1998:
<TABLE>
<CAPTION>
1998 1997 1996
-------- -------- --------
<S> <C> <C> <C>
Average sales price:
Gas - per Mcf................................................. $ 1.95 $ 2.40 $ 2.19
Oil - per barrel.............................................. 11.87 18.01 20.28
Condensate - per barrel....................................... 11.08 18.37 20.76
Natural Gas Liquids - per barrel.............................. 15.24 28.41 21.74
Average production cost per unit (equivalent Mcf)................ 0.41 0.49 0.46
</TABLE>
Company-Owned Reserves
Coastal's estimated domestic proved reserves of crude oil, condensate and
natural gas liquids at December 31, 1998, as estimated by the Company and
reviewed by Huddleston, the Company's independent engineers, were 52.3 million
barrels, compared to 40.1 million barrels at the end of 1997. Proved gas
reserves as of December 31, 1998, net to Coastal's interest, were estimated by
the Company and reviewed by Huddleston to be 2,527.1 Bcf compared to 1,752.5 Bcf
as of December 31, 1997. All of the 1997 proved reserves were estimated by
Huddleston. For the fourth consecutive year, Coastal added in 1998 proved
reserves 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.
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 Department of
the Interior and other federal agencies.
14
<PAGE>
COAL
Through the operations of Coastal Coal Company, LLC (formerly ANR 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.
In December 1996, the Company sold its western coal operations, which
consisted of the Utah mines, for approximately $610 million in cash to a limited
liability company jointly owned by subsidiaries of Atlantic Richfield Co. and
ITOCHU. See Item 3 and Notes 10 and 16 of the Notes to Consolidated Financial
Statements included herein.
At December 31, 1998, coal properties consisted of the following:
<TABLE>
<CAPTION>
Coal Holdings (Acres) Clean,
------------------------------------------------------------
Leased Recoverable
Owned Exchanged Total Tons
--------------------------------
Fee Mineral Surface (Net) Acres (Millions)(1)
-------- --------- -------- -------- -------- -------------
<S> <C> <C> <C> <C> <C> <C>
Kentucky......................... 14,121 76,131 2,454 30,590 123,296 198
Virginia......................... 24,378 36,909 2,090 16,545 79,922 166
West Virginia.................... 334 56,097 7,031 90,662 154,124 171
-------- --------- -------- -------- -------- ------
Total...................... 38,833 169,137 11,575 137,797 357,342 535
======== ========= ======== ======== ======== ======
<FN>
- ------------------------
(1) Based on a 65% recovery rate.
</FN>
</TABLE>
At December 31, 1998, the Company controlled approximately 535 million
recoverable tons of bituminous coal reserves and resources. Production in 1998
from Coastal Coal's reserves totaled 10.8 million tons, of which 7.0 million
tons were produced from captive operations and 3.8 million tons were produced by
lessees under royalty agreements. In its eastern captive operations, Coastal
Coal contracts with independent mine operators to deliver coal to Company owned
and operated processing and loading facilities for the majority of its
production. The remaining production is derived from nine company mines operated
by Coastal Coal in Virginia, Kentucky and West Virginia. Captive production and
clean coal processed from these mines totaled 3.5 million tons in 1998.
Captive sales by Coastal Coal were 8.2 million tons in 1998, as compared to
7.2 million tons in 1997. Brokerage sales in which the Company receives a
commission totaled 0.8 million tons for both 1998 and 1997.
In 1998, approximately 78% of the captive sales were to domestic utilities,
9% of the sales were to domestic industrial customers and 13% of the sales were
to export markets in Europe, Canada and South America. Additionally, 0.3 million
tons of Coastal Coal's production were sold to domestic and foreign
metallurgical markets. Of the total 1998 tonnage sold, 5.7 million tons (70%)
were sold under long-term contracts. At December 31, 1998, the weighted average
remaining life of these contracts was 40 months.
The Company had approximately 10.3 million tons of annual production
capacity at December 31, 1998 from four coal preparation plants and seven
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 425 million tons of lignite
reserves in North Dakota. Production from these reserves in 1998 totaled 9.7
million tons.
The Company, through its captive operations, leasing programs and brokerage
activities, participates in all aspects of the eastern bituminous coal industry
and is a significant competitor in international metallurgical coal markets. 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.
15
<PAGE>
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 nine 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") owns a
combined-cycle cogeneration facility with a capacity of approximately 56
megawatts, located in Hartford, Connecticut. 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 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. In 1998,
Coastal completed the restructuring of the power purchase agreement for the
Fulton plant.
Coastal, through direct and indirect subsidiaries, has a 20.4% equity
interest in the Midland Cogeneration Venture Limited Partnership, a 1,370
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 transmission
services for a portion of the project's fuel requirements.
In March 1999, Fulton acquired the 79.6-megawatt Rensselaer combined-cycle,
cogeneration facility near Albany, New York. The Rensselaer facility is located
on a site leased from the Albany Port District Commission. The facility is
natural gas fired, but is capable of utilizing No. 2 fuel oil. Fulton will
manage the facility and CTI will operate the facility.
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
16
<PAGE>
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.
Coastal Power Guatemala, a wholly owned subsidiary of Coastal Power,
effectively owns a 46% interest of Central Generadora Electrica San Jose,
Limitada, with the remainder of the project held by parties unrelated to Coastal
Power. Central Generadora Electrica San Jose, Limitada was formed to develop,
construct, own, and operate a 120-megawatt coal-fired power plant near San Jose,
Guatemala. Construction of the plant commenced in 1997 and is expected to be
completed in the first quarter of 2000. The power from the plant will be sold to
a Guatemalan utility under a long-term contract.
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 and represents approximately one-third of Panama's total
installed capacity.
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 the first quarter of 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 the fourth quarter of 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 24 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%. The power from the project will be sold to a national utility
under a long-term contract. The plant should be in service by mid year 1999.
A subsidiary of Coastal Power has a financial stake of approximately 93% of
a 125-megawatt heavy-fuel oil project in Farouqabad, Pakistan. The power from
the project will be sold to a national utility under a long-term contract, with
operations expected to commence by mid year 1999.
17
<PAGE>
In September 1998, Coastal Power Khulna Ltd., a subsidiary of Coastal
Power, acquired a 66.7% interest in a 110- megawatt, fuel oil-fired power plant
located in Khulna in southwestern Bangladesh. 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 is 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. International 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 U.S. states are restructuring
their applicable laws, rules and regulations. This restructuring is likely to
result in new development opportunities in the U.S. and increased competition in
response to such opportunities.
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 $13 million in 1998 on environmental
capital projects and anticipates capital expenditures of approximately $44
million in 1999 in order to comply with such laws and regulations. The majority
of the 1999 expenditures is attributable to projects at the Company's refining,
chemical and terminal facilities. The Company currently anticipates capital
expenditures for environmental compliance for the years 2000 through 2002 of $20
million to $40 million per year.
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
several Superfund waste disposal sites. At the 11 sites for which there is
sufficient information, total cleanup costs are estimated to be approximately
$620 million, and the Company estimates its pro-rata exposure, to be paid over a
period of several years, is approximately $7.5 million and has made appropriate
provisions. At nine other sites, the Environmental Protection Agency ("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 two
state sites. At one site, the North Carolina Department of Health, Environment
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 the second state site,
18
<PAGE>
the Florida Department of Environmental Protection has demanded reimbursement of
its costs, which total $100,000, and suitable remediation. There is not
sufficient information to estimate the remedial costs or the Company's pro-rata
exposure at this site.
In Michigan, where ANR Pipeline has extensive operations, the Environmental
Response Act requires individuals (including corporations) who have caused
contamination to remediate the contamination to regulatory standards. Owners or
operators of contaminated property who did not cause the contamination are not
required to remediate the contamination, but must exercise due care in their use
of the property so that the contamination is not exacerbated and the property
does not pose a threat to human health. ANR Pipeline estimates that its costs to
comply with the Michigan regulations will be approximately $10 million, which
will be expended over a period of several years and for which appropriate
provisions have been made.
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.
OTHER DEVELOPMENTS
Natural Gas
In March 1999, Coastal announced the development of the proposed Gulfstream
Natural Gas System ("Gulfstream System"), consisting of 700 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. The Gulfstream System is expected to be
in service in June 2002, subject to receipt of satisfactory governmental
approvals.
Power
In July 1998, the Government of Pakistan ("GOP") issued letters purporting
to be "Notices of Intent to Terminate" (the "Notices") to two independent power
projects affiliated with Coastal Power Company, a subsidiary of Coastal, as well
as to several other independent power projects. The Company asserted that the
Notices were deficient under the terms of the applicable agreement and
unequivocally denied the allegations of wrongdoing contained in the Notices. In
December 1998, each of the power projects and the GOP entered into Withdrawal
Agreements, in which the GOP withdrew and cancelled the Notices and stated that
there was no finding of wrongdoing by the projects, their shareholders,
directors, officers, employees or agents.
Other
The Company is pursuing disposition of its 50% indirect ownership of ANR
Advance Transportation Company, Inc. ("ANR Advance"), the Company's joint
venture trucking operation. The Company expects that ANR Advance will be fully
liquidated.
Item 2. Properties.
Information on properties of Coastal is included in Item 1, "Business"
included herein.
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
19
<PAGE>
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 connection with the December 20, 1996 sale of the Company's western coal
operations, the Company assumed control of a pending dispute with the
Intermountain Power Agency ("IPA") involving two coal sales agreements of
Coastal States Energy Company, which contracts were included in the sale, and
for which the Company continued to have certain responsibilities. On July 14,
1997, IPA made a demand for arbitration between the parties, asserting a claim
of a gross inequity under the contracts requiring a reduction in the purchase
price of coal sold before and after the sale of these coal operations. The
Company believed that no gross inequity had occurred and that it would prevail
in the arbitration on the merits. However, in an attempt to resolve this and
several other unrelated issues concerning the Company's continuing
responsibilities under the terms of the December 1996 sale, the Company entered
into negotiation with several interested parties. Pursuant to a January 20, 1999
multi-party agreement, in which virtually all of the Company's indemnification
obligations were terminated, IPA dismissed its "gross inequity" claim. This
favorable resolution of all outstanding claims arising under the original sale
of the western coal operations had no adverse impact on the Company.
In December 1992, certain of CIG's natural gas lessors in the West
Panhandle Field filed a complaint in the U.S. District Court for the 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, that 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 United States District Court, Southern District of Texas. The
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 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
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 1996, Jack Grynberg filed a claim under the False Claims Act on behalf
of the U.S. government in the U.S. District Court, District of Columbia, against
70 defendants, including ANR Pipeline and CIG. The suit sought damages for the
alleged underpayment of royalties due to the purported improper measurement of
gas. The 1996 suit was dismissed without prejudice in March 1997 and the
dismissal was affirmed by the D.C. Court of Appeals in October 1998. In
September 1997, Mr. Grynberg filed 77 separate, similar False Claims Act suits
against natural gas transmission companies and producers, gatherers, and
processors of natural gas, seeking unspecified damages. Coastal and several of
its subsidiaries have been included in two of the September 1997 suits. The
suits were filed in both the U.S. District Court, District of Colorado and the
U.S. District Court, Eastern District of Michigan. The United States Department
of
20
<PAGE>
Justice has notified the Company that it is reviewing these lawsuits to
determine whether or not the United States will intervene.
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.
21
<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 March 1, 1999, the approximate number of holders of
record of Common Stock was 12,900 and of the Class A Common Stock was 2,720.
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>
1998 1997
----------------------------------- ------------------------------------
Quarters High Low Dividends High Low Dividends
- -------------------- -------- ----- --------- -------- ----- ---------
<S> <C> <C> <C> <C> <C> <C>
First Quarter $34.13 $26.59 $.0500 $25.56 $22.32 $.05
Second Quarter 38.25 32.34 .0625 26.94 21.94 .05
Third Quarter 35.75 25.25 .0625 31.75 26.38 .05
Fourth Quarter 38.75 30.88 .0625 32.53 28.13 .05
</TABLE>
Coastal expects to continue paying dividends in the future. Dividends of
$.05625 per share were paid on the Class A Common Stock for the last three
quarters of 1998 and $.045 per share for each quarterly period in 1997 and the
first quarter of 1998. At December 31, 1998, 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 $686.1 million.
22
<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, 1997, 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,
------------------------------------------------------------------------
1998 1997 1996**** 1995 1994
----------- --------------- ------------ ------------ ----------
<S> <C> <C> <C> <C> <C>
Operating revenues* $ 7,368.2 $ 9,730.1 $12,166.9** $ 10,343.2 $ 10,072.4
Earnings from continuing operations
before extraordinary items 482.9 398.7 508.0** 285.6 240.3
Net earnings 444.4 301.5 402.6** 270.4 232.6
Basic earnings per share from
continuing operations before
extraordinary items*** 2.24 1.80 2.33** 1.28 1.07
Diluted earnings per share from
continuing operations before
extraordinary items*** 2.21 1.77 2.30** 1.27 1.06
Cash dividends per common share*** .2375 .20 .20 .20 .20
Total assets 12,304.1 11,639.7 11,620.4 10,660.5 10,501.8
Debt, excluding current maturities 3,999.3 3,663.2 3,526.1 3,661.7 3,719.0
Preferred stock of subsidiaries,
excluding current maturities***** 400.0 100.0 100.0 .6 .6
<FN>
* Amounts for 1997 include revenues for two months while 1994 through 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 $.2138 per
share were paid on the Company's Class A Common Stock in 1998, and $.18
was paid in 1997, 1996, 1995 and 1994.
**** 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. Additional information is set forth in Management's
Discussion and Analysis of Financial Condition and Results of
Operations and Note 14 of the Notes to Consolidated Financial
Statements.
***** Amounts for 1998 include $300.0 million of Company-obligated mandatory
redemption preferred securities of a consolidated trust.
</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-12 hereof.
23
<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.
24
<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 under "Election of Directors" and "Information Regarding Directors" in
the Coastal Proxy Statement for the May 6, 1999 Annual Meeting of Stockholders
filed pursuant to Regulation 14A under the Securities Exchange Act of 1934, and
is incorporated herein by reference.
The executive officers of the Registrant as of March 10, 1999, were as
follows:
Name (Age), Year First Positions and Offices
Elected An Officer with the Registrant
------------------------------ ------------------------------
David A. Arledge (54), 1982 Chairman of the Board, President
and Chief Executive Officer
Coby C. Hesse (51), 1986 Executive Vice President
James A. King (59), 1992 Executive Vice President
Jeffrey A. Connelly (52), 1988 Senior Vice President
Carl A. Corrallo (55), 1993 Senior Vice President and
General Counsel
Rodney D. Erskine (54), 1997 Senior Vice President
Donald H. Gullquist (55), 1994 Senior Vice President
Dan J. Hill (58), 1978 Senior Vice President
Kenneth O. Johnson (78), 1978 Senior Vice President and
Director
Austin M. O'Toole (63), 1974 Senior Vice President and
Secretary
Jack C. Pester (64), 1987 Senior Vice President
James L. Van Lanen (54), 1985 Senior Vice President
Thomas M. Wade (46), 1995 Senior Vice President
M. Truman Arnold (70), 1993 Vice President
Daniel F. Collins (57), 1989 Vice President
Thomas E. Jackson (59), 1997 Vice President
Jeffrey B. Levos (38), 1997 Vice President and Controller
John J. Lipinski (48), 1995 Vice President
Stirling D. Pack, Jr. (51), 1999 Vice President
M. Frank Powell (48), 1993 Vice President
Keith O. Rattie (44), 1996 Vice President
Ronald D. Matthews (51), 1994 Treasurer
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. Gullquist was elected Senior Vice President of Coastal in March 1994.
From 1988 to 1989 he served as Vice President, Finance at Enron Corporation;
from 1989 to 1990 he served as president of Enron Finance Corporation.
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.
25
<PAGE>
Mr. Rattie was elected Vice President of Coastal in December 1996. He was
formerly President of Coastal Gas International, Ltd., a Coastal subsidiary
responsible for international gas project development. Mr. Rattie joined Coastal
in 1995. Previously he 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 is set forth under "Compliance
with Section 16(a) of the Exchange Act" in the Coastal Proxy Statement for the
May 6, 1999 Annual Meeting of Stockholders filed pursuant to Regulation 14A
under the Securities Exchange Act of 1934, and is incorporated herein by
reference.
Item 11. Executive Compensation.
The information called for by this item is set forth under "Executive
Compensation," "Compensation and Executive Development Committee Report on
Executive Compensation," "Pension Plan Table" and "Performance Graph -
Shareholder Return on Common Stock" in the Coastal Proxy Statement for the May
6, 1999 Annual Meeting of Stockholders filed pursuant to Regulation 14A under
the Securities Exchange Act of 1934, and is incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management.
The information called for by this item is set forth under "Stock
Ownership," "Election of Directors" and "Information Regarding Directors" in the
Coastal Proxy Statement for the May 6, 1999 Annual Meeting of Stockholders filed
pursuant to Regulation 14A under the Securities Exchange Act of 1934, and is
incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions.
The information called for by this item is set forth under "Election of
Directors" and "Transactions with Officers and Directors" in the Coastal Proxy
Statement for the May 6, 1999 Annual Meeting of Stockholders filed pursuant to
Regulation 14A under the Securities Exchange Act of 1934, and is incorporated
herein by reference.
26
<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-13
Statement of Consolidated Operations for the years ended
December 31, 1998, 1997 and 1996............................. F-14
Consolidated Balance Sheet at December 31, 1998 and 1997....... F-15
Statement of Consolidated Cash Flows for the years ended
December 31, 1998, 1997 and 1996.............................. F-17
Statement of Consolidated Common Stock and Other Stockholders'
Equity for the years ended December 31, 1998, 1997 and 1996... F-18
Notes to Consolidated Financial Statements...................... F-19
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+ 1984 Stock Option Plan (Appendix B to Coastal's Proxy
Statement for the 1984 Annual Meeting of Stockholders, dated
May 14, 1984).
10.2+ 1985 Stock Option Plan (Appendix A to Coastal's Proxy
Statement for the 1986 Annual Meeting of Stockholders, dated
March 27, 1986).
-------------------------
Note:
+ Indicates documents incorporated by reference from the prior
filing indicated.
27
<PAGE>
10.3+ 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).
10.4+ 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).
10.5+ 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).
10.6+ The Coastal Corporation Stock Purchase Plan, as restated on
January 1, 1994 (Appendix B to Coastal's Proxy Statement for
the 1994 Annual Meeting of Stockholders dated March 29, 1994).
10.7+ 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.)
10.8+ 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.)
10.9+ 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).
10.10+ 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.)
10.11+ 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).
10.12+ 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).
10.13+ 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).
10.14+ 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).
10.15+ 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).
10.16+ 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).
-------------------------
Note:
+ Indicates documents incorporated by reference from the prior
filing indicated.
* Indicates documents filed herewith.
28
<PAGE>
10.17+ 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.)
10.18+ 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.)
10.19+ 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.)
10.20+ 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).
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,
1998.
29
<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
March 26, 1999
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,
Chief Executive Officer and Chief Financial
Officer (Principal Executive Officer and
Principal Financial Officer)
March 26, 1999
By: COBY C. HESSE
---------------------------------------
Coby C. Hesse
Principal Accounting Officer
March 26, 1999
By: JOHN M. BISSELL
---------------------------------------
John M. Bissell
Director
March 26, 1999
* * *
30
<PAGE>
By: GEORGE L. BRUNDRETT, JR. By: KENNETH O. JOHNSON
------------------------ ------------------------
George L. Brundrett, Jr. Kenneth O. Johnson
Director Director
March 26, 1999 March 26, 1999
By: HAROLD BURROW By: JEROME S. KATZIN
------------------------ ------------------------
Harold Burrow Jerome S. Katzin
Director Director
March 26, 1999 March 26, 1999
By: ROY D. CHAPIN, JR. By: J. CARLETON MACNEIL, JR.
------------------------ ------------------------
Roy D. Chapin, Jr. J. Carleton MacNeil, Jr.
Director Director
March 26, 1999 March 26, 1999
By: JAMES F. CORDES By: THOMAS R. McDADE
------------------------ ------------------------
James F. Cordes Thomas R. McDade
Director Director
March 26, 1999 March 26, 1999
By: ROY L. GATES By: O. S. WYATT, JR.
------------------------ ------------------------
Roy L. Gates O. S. Wyatt, Jr.
Director Director
March 26, 1999 March 26, 1999
31
<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,
changing legislation and regulations, and the impact of the Year 2000 issue. 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>
1998 1997 1996
-------- -------- --------
<S> <C> <C> <C>
Return on average common stockholders' equity................................ 14.6% 13.1% 18.8%
Cash flow from operating activities to long-term debt........................ 28.7% 26.7% 16.3%
Total debt to total capitalization........................................... 52.1% 53.0% 53.7%
Times interest earned (before tax)........................................... 3.2 2.7 2.8
</TABLE>
The above ratios reflect increased stockholders' equity and debt in 1998
and 1997. The increases 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 $1,146.3 million in
1998, $976.9 million in 1997 and $574.6 million in 1996. The change in 1998 was
due to increases for earnings from continuing operations before extraordinary
items and deferred income taxes. The 1997 increase can be primarily attributed
to decreases for working capital requirements.
Capital expenditures amounted to $1,404.0 million, $996.7 million and
$880.8 million in 1998, 1997 and 1996, respectively. Exploration and Production
capital expenditures increased by $360.4 million over 1997, 88% of the Company's
total increase, as the continued successful programs again resulted in reserve
additions which were more than three times 1998 production. Capital expenditures
for Refining, Marketing and Chemicals increased 37%, primarily due to expansion
projects at the Aruba refinery. Natural Gas capital expenditures decreased 14%
as system expansions for the interstate pipelines were down from 1997. Capital
expansion for the Coal segment was up 85% 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. The
increased 1997 capital expenditures were primarily due to continued expansion in
the Exploration and Production segment which resulted in reserve additions which
were also more than three times 1997 production. Natural Gas expenditures
increased 6% due to system expansions for the interstate pipelines. Capital
expenditures decreased for the Refining, Marketing and Chemicals segment as
major projects were completed in 1996 at the refineries and for the Coal segment
as a result of the sale of the Utah mines in 1996.
The increase in proceeds from the sale of property, plant and equipment for
1998 of $14.4 million results primarily from the sale of certain non-core
Natural Gas processing and gathering assets. Proceeds from the sale of property,
plant and equipment in 1997, of which 37% was from the Refining, Marketing and
Chemicals segment, were comparable to the 1996 amount. The proceeds from the
Refining, Marketing and Chemicals segment partially resulted from its strategy
of eliminating marginal activities. Additions to investments increased in 1998
as a result of the Power segment increasing
F-1
<PAGE>
its interest in existing plants, completing new projects and pursuing
opportunities in the United States and abroad, while the 1997 increase included
a $50 million investment in marketable securities, as well as increases for gas
pipeline ventures. Proceeds from investments decreased in 1998 due to a
reduction in amounts from Refining, Marketing and Chemical ventures and
increased in 1997 as a result of amounts received from gas pipeline ventures.
The Company increased total debt by $393.6 million in 1998 and $180.1
million in 1997. The 1998 and 1997 increases were used for capital expenditures
and additions to investments.
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.
A two-for-one stock split of Coastal's common stock was declared in May
1998. Stockholders of record received one additional share of common stock for
each share of common and/or Class A common stock held.
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 proceeds were used to
refinance borrowings incurred to finance the redemption of the Series H
Preferred Stock discussed above and to repay certain outstanding subsidiary
indebtedness. 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.
In June 1998, the Company completed public offerings of $200 million of
6.5% senior debentures due 2008 and $200 million of 6.95% senior debentures due
2028. The net proceeds from the sale were used to repay variable rate
indebtedness, including indebtedness of a subsidiary under a revolving credit
facility.
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.
Capital expenditures for 1999, including the Company's equity investments
in partnerships and joint ventures, are currently projected at approximately
$1.5 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 1999
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.
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.
The Company is undertaking an aggressive and comprehensive program in 1999
to reduce costs and improve efficiencies, as well as continuing an emphasis on
divestment of less profitable non-core operations.
Unused lines of credit at December 31, 1998 were as follows (Millions of
Dollars):
Short-term.................................... $ 649.0
Long-term*.................................... 456.0
---------
$ 1,105.0
=========
*$45.1 million of unused long-term credit lines is dedicated
to a specific use.
F-2
<PAGE>
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, 1998, net assets of
consolidated subsidiaries amounted to approximately $6.8 billion, of which
approximately $653.0 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 Standards Board ("FASB") has issued Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities" ("FAS 133") to be effective for all fiscal quarters of
fiscal years beginning after June 15, 1999. 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 FASB Emerging Issues Task Force Issue No. 98-10, to be effective for
years beginning after December 15, 1998, states that energy trading contracts
(as defined) should be marked to market with the gains and losses included in
earnings and separately disclosed in the financial statements or footnotes
thereto. The Company does not believe the application of Issue No. 98-10 will
have a material effect on its consolidated financial statements.
The Accounting Standards Executive Committee of the American Institute of
Certified Public Accountants has issued Statement of Position 98-5 ("SOP 98-5"),
to be effective for periods beginning after December 15, 1998. SOP 98-5 provides
guidance on accounting for costs incurred to open new facilities, conduct
business in new territories or otherwise commence some new operation. The
application of SOP 98-5 is not expected to have a material effect on the
Company's consolidated financial statements.
In January 1999, certain countries of the European Union adopted the Euro
as their legal common currency. This conversion to the Euro is not expected to
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.
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 $13 million in 1998 on environmental
capital projects and anticipates capital expenditures of approximately $44
million in 1999 in order to comply with such laws and regulations. The majority
of the 1999 expenditures are attributable to projects at the Company's refining,
chemical and terminal facilities. The Company currently anticipates capital
expenditures for environmental compliance for the years 2000 through 2002 of $20
million to $40 million per year.
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
several "Superfund" waste disposal sites. At the 11 sites for which there is
sufficient information, total cleanup costs are estimated to be approximately
$620 million, and the Company estimates its pro-rata exposure, to be paid over a
period of several years, is approximately $7.5 million and has made appropriate
provisions. At nine other sites, the Environmental Protection Agency ("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 two
state sites. At one site, the North Carolina Department of Health, Environment
and Natural Resources has estimated the total cleanup costs to be approximately
$50 million, but the Company believes that the subsidiaries' activities at this
site were de minimis. At the second state site, the Florida Department of
Environmental Protection has demanded reimbursement of its costs, which total
$100,000, and suitable remediation. There is not sufficient information to
estimate the remedial costs or the Company's pro-rata exposure at this site.
F-3
<PAGE>
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, 1998 and 1997. 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>
Assets
Notes receivable and marketable debt
securities
1998......................... $ 312.2 $ 305.2 $ (7.0) $ 319.8 $ 7.6
1997......................... 279.4 271.1 (8.3) 288.6 9.2
Liabilities
Long-term debt subject to fixed interest
rates
1998......................... $ 2,982.7 $ 2,875.9 $ (106.8) $ 3,097.3 $ 114.6
1997......................... 2,619.5 2,513.2 (106.3) 2,733.6 114.1
Preferred Stock of Subsidiaries
Mandatory redemption preferred
securities of a consolidated trust
1998......................... $ 295.6 $ 279.2 $ (16.4) $ 313.4 $ 17.8
1997......................... - - - - -
</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 $2,071.8 million at December
31, 1998. 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, 1998 levels and continue through 1999 assuming no changes in debt levels,
interest expense, including the effects of interest rate swaps, would increase
by approximately $11.4 million with a corresponding decrease in earnings before
taxes, as compared to a $10.7 million increase at December 31, 1997.
A subsidiary of the Company has issued preferred stock with a fair value of
$100 million. The preferred stock pays cumulative preferred dividends at a
variable rate tied to market rates of interest. This stock exposes the Company
to potential decreases in earnings should interest rates increase. An immediate
10% increase in market rates of interest,
F-4
<PAGE>
continuing through 1999, assuming no change in outstanding shares, would
decrease earnings before taxes by approximately $0.5 million, compared to a $0.6
million decrease at December 31, 1997.
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 $23.0 million at December 31, 1998. An immediate decrease
in the market prices of these securities of 10% would result in a fair value of
approximately $20.7 million, or a decrease in earnings before taxes of
approximately $2.3 million. The potential loss at December 31, 1997 was $1.8
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, 1998 and 1997. 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, 1998, and the results of such trading were not material
to the financial results of the Company for 1998.
<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>
Commodity futures
1998......................... $ (27.3) $ (30.7) $ (3.4) $ (23.9) $ 3.4
1997......................... (15.3) (20.3) (5.0) (10.3) 5.0
</TABLE>
In addition, the repayment terms of certain long-term variable rate debt
with a fair value of $141.2 million at December 31, 1998, 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, 1998 would result in an increase of $12.9 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, 1997 was $18.9 million. The decrease in the hypothetical change is due to
the decrease in oil prices in 1998.
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. Coastal, like most other companies, is addressing the Year 2000
issue. This issue is the result of computer programs written with two digits
rather than four to define the applicable year. Computer programs that have
date-sensitive software using two digits to define the applicable year may
recognize a date using "00" as the year 1900 instead of the year 2000. This
could result in a system failure or miscalculations causing disruptions of
operations, including, among other things, a temporary inability to process
transactions, send invoices, or engage in similar normal business activities.
The Company's Year 2000 compliance project relates to both information
technology and embedded systems throughout the Company and focuses on all
technology hardware and software, external interfaces with customers and
suppliers, operations process control, automation and instrumentation systems.
Systems are being reviewed in an order of priority that includes an assessment
of the potential adverse effects of noncompliance as well as an assessment of
the complexity of the system. Assessment has been substantially completed for
all systems. It will be necessary to modify or replace certain noncompliant
software and hardware so that they will properly utilize dates beyond December
31, 1999. The Company believes that with such remediation, the Year 2000 issue
can be mitigated. Necessary remediation and testing activities have begun and
are planned to be completed for all material systems by mid-1999. Remaining
systems modifications, replacement and testing are planned to be completed
before the end of 1999.
F-5
<PAGE>
The Company is continuing with a formal communications process with outside
entities with which the Company conducts business to determine the extent to
which those companies are addressing their Year 2000 compliance. In connection
with this process, the Company has been sending letters and questionnaires to
these parties and is evaluating the responses as received and is following up
with those parties that have not responded. The Company does not expect any
single noncompliant third party to have a material effect on the Company as it
does not rely to a material extent on any single customer or supplier, including
telecommunications providers, utilities and banks. However, the Company does not
control these parties and there can be no assurance that third-party systems
will be timely converted, or that any failure to convert would not have an
adverse effect on the Company's systems. The Company will continue to cooperate
and communicate with these parties to mitigate potential adverse effects.
The Company is currently preparing and will periodically update a Year 2000
contingency plan. The primary goals of the plan are to maintain continuity of
operations, timely resume any operations that have been interrupted, preserve
Company assets and protect the environment. Coastal's diversity and distribution
on a business unit, geographical and customer basis are expected to naturally
reduce the risk of major disruptions to worldwide operations due to any Year
2000-related occurrence. Similarly, the Company's distributed information
systems and wide scope of relationships with financial institutions, suppliers
and vendors will most likely aid in limiting and localizing any individual Year
2000 failure to specific operations or facilities. Also, in recent years the
Company has replaced or updated a significant portion of its computer hardware
and software. The plan will include possible manual intervention to operate
noncompliant facilities or systems until they can be modified or replaced.
Notwithstanding the foregoing, due to the nature of contingency planning, there
can be no assurance that such plans will acceptably mitigate the risk of
material impact to the Company's operations due to any Year 2000-related
incident.
The Company has been using both external and internal resources to
reprogram or replace its software and embedded systems for the Year 2000 issue.
While the Company has included the Year 2000 project in its overall information
systems planning process since 1996, certain systems were identified for
replacement prior to the organization of the Year 2000 project. These amounts
are not included in the Year 2000 project cost estimates, except where the
replacement date has been accelerated in order to address Year 2000 issues. To
date, the amounts incurred and expensed for developing and carrying out the plan
total approximately $12 million. The total remaining cost for addressing the
Year 2000 issue, which will be funded through operating cash flows, is currently
estimated by management to be approximately $5 million.
It should be noted that the ultimate amount of Year 2000 costs is difficult
to estimate due to possible disruptions in business arising from Year 2000
noncompliance of vendors, suppliers, customers and other third parties over whom
the Company has no control. Notwithstanding the Company's efforts, disruptions
could occur in its business due to Year 2000 problems and such disruptions could
have an adverse effect.
Results of Operations
The Company operates principally in the following lines of business:
natural gas; refining, marketing and chemicals; exploration and production;
coal; and power.
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 Federal Energy
Regulatory Commission ("FERC"). The Company's subsidiaries historically followed
the reporting and accounting requirements of Statement of Financial Accounting
Standards No. 71, "Accounting for the Effects of Certain Types of Regulation"
("FAS 71"). Effective November 1, 1996, these subsidiaries discontinued
application of FAS 71. This accounting change has no direct effect on either the
subsidiaries' ability to include the previously deferred items in future rate
proceedings or on their ability to collect the rates set thereby. The Company
believes this accounting change results in financial reporting which better
reflects the results of operations in the economic environment in which these
subsidiaries operate.
F-6
<PAGE>
The Company's interstate pipelines operate under FERC Order 636. The intent
of Order 636 is to insure 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
--------------------------------------------
1998 1997 1996
----------- ----------- -----------
<S> <C> <C> <C>
Operating revenues.............................................. $ 1,358.4 $ 2,166.2 $ 3,989.5
Depreciation, depletion and amortization........................ 118.3 136.5 161.7
Earnings before interest and income taxes....................... 594.3 583.0 490.8
Total throughput volume (Bcf)................................... 2,132 2,190 2,246
</TABLE>
1998 Versus 1997. The decrease in operating revenues of $808 million is
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 are
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 include a $42
million gain from an equalization payment recognized in connection with the
Engage combination. The 1998 revenues include 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.
Earnings before interest and income taxes ("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 operations of gas plants and sale of extracted products;
and other decreases of $13 million. The reduced transportation, storage and
gathering revenues result 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 the Notes to
Consolidated Financial Statements. The decreased earnings from equity
investments includes 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 are primarily due to reduced gross profit from
gas sales.
Demand for natural gas is expected to increase substantially in North
America. In anticipation of this demand growth, Coastal's pipelines' strategy is
to find and develop new gas reserves and position our assets to move gas from
the primary supply areas to our core growth markets in the Midwest and the East.
1997 Versus 1996. The decrease in operating revenues of $1,823 million can
be primarily attributed to the Company's unregulated gas marketing operations
which became a part of Engage. The revenues from those operations, which are not
included in the Company's revenues after February 1997, resulted in a decrease
of $2,320 million in 1997.
F-7
<PAGE>
Partially offsetting the decrease noted above were increased prices and volumes
for gas sales, primarily during the first two months of 1997, and a $42 million
gain from an equalization payment recognized in connection with the Engage
combination. Transportation, storage and gathering revenues increased slightly
in 1997.
Purchases decreased by $1,880 million from 1996, primarily due to the
combination of the unregulated gas marketing operations noted above, partially
offset by increased prices and volumes for gas purchases, primarily in the first
two months of 1997. Gross profit increased by $57 million in 1997.
The increase in EBIT of $92 million resulted from increased gas sales
volumes of $22 million; the $42 million gain from the equalization payment
discussed above; increased transportation, storage and gathering revenues of $3
million; decreased depreciation, depletion and amortization of $25 million; and
decreased operating expenses of $33 million offset by lower gas sales margins of
$8 million; a decrease of $12 million from the combination of gas marketing
operations; and other decreases of $13 million. The reduction in depreciation,
depletion and amortization was primarily due to the revision of depreciation
rates for certain assets of the regulated interstate pipelines and certain
storage subsidiaries during 1997. Operating expenses decreased due to reductions
for recovery amortizations and transportation services. The other decreases were
primarily due to reduced revenue related to the sale of property, plant and
equipment.
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
-------------------------------------------
1998 1997 1996
----------- ----------- ----------
<S> <C> <C> <C>
Operating revenues.............................................. $ 5,202.7 $ 6,877.1 $ 7,364.8
Depreciation, depletion and amortization........................ 78.3 74.6 73.3
Earnings before interest and income taxes....................... 243.9 95.6 94.4
Refined product sales (millions of barrels)..................... 300 279 307
</TABLE>
1998 Versus 1997. The decrease in operating revenues of $1,674 million is
due to reduced prices partially offset by increased volumes. Although throughput
at the Company's refineries was down in 1998 due to scheduled turnarounds, sales
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 results 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 results 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
result 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.
Coastal's improved performance results from operational enhancements and
investments to produce lighter, higher value products from lower cost heavy and
sour crudes. The Company will continue its strategy of refocusing its marketing
assets to eliminate marginal activities and focus on businesses that support its
core refining assets and reduce working capital requirements.
1997 Versus 1996. Operating revenues decreased by $488 million due to
reduced sales volumes and prices. The volume decrease was partially due to mild
weather in the northeastern United States as well as the ongoing refocusing
F-8
<PAGE>
of the Company's marketing assets to eliminate marginal activities and expand
operations directly supporting the Company's core refining assets. Throughput at
the Company's refineries was down 13,000 barrels per day from 1996.
Purchases for the segment decreased by $497 million, resulting in a gross
profit increase of $9 million. Increased margins of $32 million were partially
offset by lower sales volumes of $16 million and other decreases of $7 million.
The other decreases were due to reduced gross profit from the sale of
convenience store merchandise of $3 million and other reductions of $4 million.
The improved margins, which include the impact of inventory losses that resulted
from falling product and crude oil prices, increased significantly in the last
three quarters due to the Company's ability to use less expensive sour and heavy
crudes.
The increase in EBIT of $1 million resulted from the increased gross profit
of $9 million and increased earnings from equity investments of $7 million
partially offset by increased operating expenses of $14 million and higher
depreciation, depletion and amortization of $1 million. The increased operating
expenses were attributable to increases for maintenance, catalyst and other
expenses at the Company's refineries.
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
-------------------------------------------
1998 1997 1996
----------- ----------- ----------
<S> <C> <C> <C>
Operating revenues.............................................. $ 463.0 $ 490.2 $ 398.5
Depreciation, depletion and amortization........................ 209.2 185.5 158.2
Earnings before interest and income taxes....................... 109.8 167.6 135.1
Natural gas production (MMcf per day)........................... 509 436 353
Oil, condensate and natural gas liquids production (bpd)........ 15,281 13,580 13,831
Average sales price (dollars):
Gas (per Mcf)............................................. $ 1.95 $ 2.40 $ 2.19
Oil, condensate and natural gas liquids (per barrel)...... 11.77 18.75 20.46
</TABLE>
1998 Versus 1997. The decrease in operating revenues of $27 million results
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
other 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 result 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 results 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
results from increased production. Operating expenses were higher as a result of
increased expenses for producing wells.
For the fourth year in a row, Coastal added reserves in 1998 that were more
than triple production due to its successful exploration and production
programs.
1997 Versus 1996. Operating revenues increased by $92 million as increased
volumes and prices for natural gas were partially offset by lower prices and
volumes for oil, condensate and natural gas liquids. Natural gas revenue
increases of $98 million and other increases of $5 million were partially offset
by decreased revenues of $11 million for crude oil, condensate and natural gas
liquids. Average daily net production of natural gas increased by 24% over 1996
and net production of crude oil, condensate and natural gas liquids decreased by
2% from the prior year. The volume increase for natural gas resulted from
Coastal's ongoing successful programs in the Gulf of Mexico, Texas Coastal Plain
and Utah's Uinta Basin.
F-9
<PAGE>
The increase in EBIT of $33 million resulted from increased volumes of $60
million and higher prices of $23 million partially offset by increased operating
expenses of $23 million and higher depreciation, depletion and amortization of
$27 million. The increased operating expenses resulted primarily from increased
levels of offshore activity and increased production. Increased production
volumes and a higher rate accounted for the depreciation, depletion and
amortization increase.
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
-------------------------------------------
1998 1997 1996
----------- ----------- ----------
<S> <C> <C> <C>
Operating revenues.............................................. $ 241.7 $ 226.8 $ 713.6
Depreciation, depletion and amortization........................ 14.6 14.1 37.3
Earnings before interest and income taxes....................... 17.4 25.3 356.0
Captive and brokered sales (millions of tons)................... 9.0 8.0 17.9
</TABLE>
1998 Versus 1997. The increase in coal revenues of $15 million results
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 results 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, are primarily due to
the increased volumes sold.
Coastal made significant progress in 1998 toward transforming its coal
business from a processing and marketing company using contract mining into an
integrated company that mines, processes and sells its own coal.
1997 Versus 1996. The decrease in coal revenues resulted primarily from the
sale of the Utah coal mining operations in December 1996 (See Notes 10 and 16 of
the Notes to the Consolidated Financial Statements). In addition to the
reduction in revenues from operating those mines, the 1996 revenues also
included a gain of $272 million from the sale. The segment experienced a 3%
increase in volumes sold from its remaining mines in the Eastern United States
and a 4% decrease in the average sales price per ton as compared to 1996.
The decrease in EBIT of $331 million resulted from the $272 million gain
noted above and a decrease of $62 million due to not operating the Western mines
in 1997 offset by other increases of $3 million. The other increases of $3
million resulted from the favorable resolution of a contingency in 1997 and
other increases partially offset by reduced sales of coke from the Company's
Aruba refinery.
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
-------------------------------------------
1998 1997 1996
----------- ----------- ----------
<S> <C> <C> <C>
Operating revenues.............................................. $ 121.1 $ 103.8 $ 92.6
Depreciation, depletion and amortization........................ 3.2 3.1 2.4
Earnings before interest and income taxes....................... 67.8 43.4 41.4
</TABLE>
1998 Versus 1997. The increase in operating revenues of $17 million is
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 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. The EBIT increase of $24 million
reflects this $17
F-10
<PAGE>
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.
Coastal added 434 megawatts of operating capacity (292 megawatts net to
Coastal's interest), during 1998 through both the acquisition of interests in
existing plants and new projects.
1997 Versus 1996. The increase in operating revenues of $11 million
resulted primarily from increased revenues related to the El Salvador operations
partially offset by a development fee received in 1996. The increase in EBIT of
$2 million resulted from increased equity earnings of $12 million offset by a $4
million development fee received in 1996, a $2 million decrease at a domestic
cogeneration plant due to mechanical problems and increased administrative and
development expenses of $4 million related to the operations of joint venture
projects. The equity income increase was due primarily to improved results from
both domestic and foreign plants, some of which were operated only a partial
year in 1996.
Corporate and Other. Other operations involve real estate and corporate
income and expense not allocated to the operating segments.
<TABLE>
<CAPTION>
Millions of Dollars
-------------------------------------------
1998 1997 1996
----------- ----------- ----------
<S> <C> <C> <C>
Operating revenues.............................................. $ 23.0 $ 29.4 $ 32.7
Depreciation, depletion and amortization........................ 7.0 4.1 6.0
Loss before interest and income taxes........................... (88.7) (70.4) (74.1)
</TABLE>
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 is attributable to
dividends on the Company-obligated mandatory redemption preferred securities of
a consolidated trust of $16 million and other of $2 million.
1997 Versus 1996. The $3 million decrease in operating revenues resulted
primarily from the sale of certain real estate properties in 1997. The reduced
loss before earnings and income taxes of $4 million resulted primarily from
increased interest income.
Interest and Debt Expense
1998 Versus 1997. The interest and debt expense decrease of $13 million
results from reduced average interest rates, reduced interest associated with
regulatory matters and increased capitalized interest partially offset by
increases due to higher average debt.
1997 Versus 1996. Interest and debt expense decreased by $61 million in
1997 due to lower average debt and a lower average interest rate.
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 result from the Company pursuing the
disposition of its 50% owned trucking operation as described in Note 13 of the
Notes to Consolidated Financial Statements.
F-11
<PAGE>
Extraordinary Items
The extraordinary items, net of income taxes, resulted from the early
retirement of debt in 1997 and 1996 and the discontinuation of regulatory
accounting in 1996. See Note 14 of the Notes to Consolidated Financial
Statements.
F-12
<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, 1998 and 1997, 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, 1998. 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, 1998 and 1997, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 1998, 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 4, 1999
F-13
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED OPERATIONS
(Millions of Dollars Except Per Share)
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------
1998 1997 1996
----------- ----------- -----------
<S> <C> <C> <C>
OPERATING REVENUES.............................................. $ 7,368.2 $ 9,730.1 $ 12,166.9
----------- ----------- -----------
OPERATING COSTS AND EXPENSES
Purchases.................................................... 4,376.8 6,863.5 8,979.8
Operating and general expenses............................... 1,674.9 1,700.4 1,786.9
Depreciation, depletion and amortization..................... 443.2 433.5 453.6
----------- ----------- -----------
6,494.9 8,997.4 11,220.3
----------- ----------- -----------
OTHER INCOME - NET.............................................. 71.2 111.8 97.0
----------- ----------- -----------
EARNINGS BEFORE INTEREST AND INCOME TAXES....................... 944.5 844.5 1,043.6
----------- ----------- -----------
OTHER EXPENSES
Interest and debt expense.................................... 294.9 307.5 368.3
Taxes on income.............................................. 166.7 138.3 167.3
----------- ----------- -----------
EARNINGS FROM CONTINUING OPERATIONS
BEFORE EXTRAORDINARY ITEMS................................... 482.9 398.7 508.0
DISCONTINUED OPERATIONS - NET OF INCOME TAXES
Loss from operations......................................... (3.5) (6.6) (7.8)
Estimated loss on disposal................................... (35.0) - -
----------- ----------- -----------
EARNINGS BEFORE EXTRAORDINARY ITEMS............................. 444.4 392.1 500.2
EXTRAORDINARY ITEMS - NET OF INCOME TAXES
Loss on early extinguishment of debt......................... - (90.6) (12.0)
Discontinuation of regulatory accounting .................... - - (85.6)
----------- ----------- -----------
NET EARNINGS.................................................... 444.4 301.5 402.6
DIVIDENDS ON PREFERRED STOCK.................................... 6.0 17.4 17.4
----------- ----------- -----------
NET EARNINGS AVAILABLE TO COMMON
STOCKHOLDERS................................................. $ 438.4 $ 284.1 $ 385.2
=========== =========== ===========
BASIC EARNINGS PER SHARE
From continuing operations before extraordinary items........ $ 2.24 $ 1.80 $ 2.33
Discontinued operations...................................... (.18) (.03) (.04)
Extraordinary items.......................................... - (.43) (.46)
----------- ----------- -----------
NET BASIC EARNINGS PER SHARE................................. $ 2.06 $ 1.34 $ 1.83
=========== =========== ===========
DILUTED EARNINGS PER SHARE
From continuing operations before extraordinary items........ $ 2.21 $ 1.77 $ 2.30
Discontinued operations...................................... (.18) (.03) (.04)
Extraordinary items.......................................... - (.42) (.46)
----------- ----------- -----------
NET DILUTED EARNINGS PER SHARE............................... $ 2.03 $ 1.32 $ 1.80
=========== =========== ===========
</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,
---------------------------
1998 1997
----------- ----------
<S> <C> <C>
ASSETS
- ------
CURRENT ASSETS
Cash and cash equivalents..................................................... $ 106.9 $ 20.5
Receivables, less allowance for doubtful accounts $15.9 million (1998)
and $16.6 million (1997)................................................... 1,142.8 1,538.0
Inventories................................................................... 499.5 684.7
Prepaid expenses and other.................................................... 220.6 252.7
----------- ----------
Total current assets....................................................... 1,969.8 2,495.9
----------- ----------
PROPERTY, PLANT AND EQUIPMENT - AT COST
Natural gas systems........................................................... 6,069.2 5,887.6
Refining, crude oil and chemical facilities................................... 2,424.2 2,254.8
Gas and oil properties - at full-cost......................................... 2,870.8 2,123.4
Other......................................................................... 366.6 395.0
----------- ----------
11,730.8 10,660.8
Accumulated depreciation, depletion and amortization.......................... 3,706.9 3,539.2
----------- ----------
8,023.9 7,121.6
----------- ----------
OTHER ASSETS
Goodwill...................................................................... 470.8 489.8
Investments - equity method .................................................. 970.8 752.6
Other......................................................................... 868.8 779.8
----------- ----------
2,310.4 2,022.2
----------- ----------
$ 12,304.1 $ 11,639.7
=========== ==========
</TABLE>
See Notes to Consolidated Financial Statements.
F-15
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Millions of Dollars)
<TABLE>
<CAPTION>
December 31,
---------------------------
1998 1997
----------- ----------
<S> <C> <C>
LIABILITIES AND STOCKHOLDERS' EQUITY
- ------------------------------------
CURRENT LIABILITIES
Notes payable ................................................................ $ 87.0 $ 114.0
Accounts payable.............................................................. 1,488.0 2,074.0
Accrued expenses.............................................................. 305.0 270.7
Current maturities on long-term debt.......................................... 126.5 42.0
----------- ----------
Total current liabilities.................................................. 2,006.5 2,500.7
----------- ----------
DEBT
Long-term debt, excluding current maturities.................................. 3,999.3 3,663.2
----------- ----------
DEFERRED CREDITS AND OTHER
Deferred income taxes......................................................... 1,717.7 1,579.4
Other deferred credits ....................................................... 704.8 514.0
----------- ----------
2,422.5 2,093.4
----------- ----------
PREFERRED STOCK
Company-obligated mandatory redemption
preferred securities of a consolidated trust............................... 300.0 -
Issued by subsidiaries........................................................ 100.0 100.0
----------- ----------
400.0 100.0
----------- ----------
COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY
Cumulative preferred stock (with aggregate liquidation preference
of $7.7 million) .......................................................... - 2.6
Class A common stock - Issued (1998 - 354,058 shares;
1997 - 366,315 shares)..................................................... .1 .1
Common stock - Issued (1998 - 216,764,580 shares;
1997 - 110,117,191 shares)................................................. 72.2 36.7
Additional paid-in capital.................................................... 1,016.2 1,243.6
Retained earnings............................................................. 2,519.8 2,131.9
----------- ----------
3,608.3 3,414.9
Less common stock in treasury - at cost (1998 - 4,395,654 shares;
1997 - 4,395,867 shares)................................................... 132.5 132.5
----------- ----------
3,475.8 3,282.4
----------- ----------
$ 12,304.1 $ 11,639.7
=========== ==========
</TABLE>
See Notes to Consolidated Financial Statements.
F-16
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CASH FLOWS
(Millions of Dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------------------------
1998 1997 1996
----------- ----------- ----------
<S> <C> <C> <C>
NET CASH FLOW FROM OPERATING ACTIVITIES
Earnings from continuing operations before extraordinary items $ 482.9 $ 398.7 $ 508.0
Add (subtract) items not requiring (providing) cash:
Depreciation, depletion and amortization.................. 449.4 436.6 455.7
Deferred income taxes..................................... 151.7 73.9 60.0
Gain from sale of Utah coal mining operations............. - - (272.3)
Amortization of producer contract reformation costs....... - - 25.6
Undistributed earnings from equity investments............ (41.2) (43.0) (15.2)
Working capital and other changes, excluding changes relating
to cash and non-operating activities:
Accounts receivable....................................... 395.2 248.5 (670.2)
Inventories............................................... 185.1 418.2 (387.2)
Prepaid expenses and other................................ 31.0 12.3 .4
Accounts payable.......................................... (573.4) (350.1) 796.9
Accrued expenses.......................................... 30.9 (56.6) 61.0
Other..................................................... 34.7 (161.6) 11.9
----------- ----------- ----------
1,146.3 976.9 574.6
----------- ----------- ----------
CASH FLOW FROM INVESTING ACTIVITIES
Purchases of property, plant and equipment................... (1,404.0) (996.7) (880.8)
Proceeds from sale of property, plant and equipment.......... 98.5 84.1 79.4
Additions to investments..................................... (255.4) (193.8) (114.2)
Proceeds from investments.................................... 59.9 71.5 25.9
Proceeds from sale of Utah coal mining operations............ - - 610.1
Recovery of gas supply prepayments .......................... - - .3
Net from discontinued operations............................. 9.3 (16.0) (13.2)
----------- ----------- ----------
(1,491.7) (1,050.9) (292.5)
----------- ----------- ----------
CASH FLOW FROM FINANCING ACTIVITIES
Increase (decrease) in short-term notes...................... 123.0 259.0 (318.2)
Redemption of preferred stock................................ (200.0) - (.6)
Proceeds from issuing common stock........................... 5.5 7.3 14.7
Proceeds from issuing stock of subsidiaries.................. - - 105.0
Proceeds from long-term debt issues.......................... 432.2 943.4 590.7
Proceeds from issuing Company-obligated mandatory
redemption preferred securities of a consolidated trust... 300.0 - -
Payments to retire long-term debt............................ (172.4) (1,161.8) (566.2)
Dividends paid............................................... (56.5) (59.7) (59.6)
----------- ----------- ----------
431.8 (11.8) (234.2)
----------- ----------- ----------
NET INCREASE (DECREASE) IN CASH
AND CASH EQUIVALENTS ........................................ 86.4 (85.8) 47.9
Cash and cash equivalents at beginning of year............... 20.5 106.3 58.4
----------- ----------- ----------
Cash and cash equivalents at end of year..................... $ 106.9 $ 20.5 $ 106.3
=========== =========== ==========
</TABLE>
See Notes to Consolidated Financial Statements.
F-17
<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,
----------------------------------------------------------------------
1998 1997 1996
------------------- -------------------- -------------------
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.. 58 $ - 60 $ - 61 $ -
Converted to common................. (2) - (2) - (1) -
-------- -------- ------- -------- ------- --------
Ending balance.................... 56 - 58 - 60 -
======== -------- ======= -------- ======= --------
$1.83, Series B: Beginning balance.. 68 - 74 - 79 .1
Converted to common................. (7) - (6) - (5) (.1)
-------- -------- ------- -------- ------- --------
Ending balance.................... 61 - 68 - 74 -
======== -------- ======= -------- ======= --------
$5.00, Series C: Beginning balance.. 30 - 32 - 33 -
Converted to common................. (2) - (2) - (1) -
-------- -------- ------- -------- ------- --------
Ending balance.................... 28 - 30 - 32 -
======== -------- ======= -------- ======= --------
CUMULATIVE PREFERRED:
$2.125, Series H, liquidation amount of
$25 per share:
Beginning balance................... 8,000 2.6 8,000 2.6 8,000 2.6
Redeemed............................ (8,000) (2.6) - - - -
-------- -------- ------- -------- ------- --------
Ending balance...................... - - 8,000 2.6 8,000 2.6
======== -------- ======= -------- ======= --------
CLASS A COMMON STOCK, PAR VALUE
33-1/3(cent) PER SHARE, AUTHORIZED
2,700,000 SHARES
Beginning balance................... 366 .1 382 .1 404 .1
Converted to common................. (13) - (17) - (35) -
Conversion of preferred stock and
exercise of stock options........... 1 - 1 - 13 -
-------- -------- ------- -------- ------- --------
Ending balance................... 354 .1 366 .1 382 .1
======== -------- ======= -------- ======= --------
COMMON STOCK, PAR VALUE 33-1/3(cent)
PER SHARE, AUTHORIZED 250,000,000
SHARES
Beginning balance................... 110,117 36.7 109,756 36.6 109,168 36.4
Conversion of preferred stock....... 63 - 47 - 34 -
Conversion of Class A common stock.. 13 - 17 - 35 -
Two-for-one stock split............. 106,274 35.4 - - - -
Exercise of stock options .......... 298 .1 297 .1 519 .2
-------- -------- ------- -------- ------- --------
Ending balance.................... 216,765 72.2 110,117 36.7 109,756 36.6
======== -------- ======= -------- ======= --------
ADDITIONAL PAID-IN CAPITAL
Beginning balance..................... 1,243.6 1,239.6 1,225.0
Exercise of stock options............. 5.4 4.0 14.6
Two-for-one stock split............... (35.4) - -
Redemption of Series H preferred stock. (197.4) - -
-------- -------- --------
Ending balance...................... 1,016.2 1,243.6 1,239.6
-------- -------- --------
RETAINED EARNINGS
Beginning balance .................... 2,131.9 1,890.1 1,547.1
Net earnings for period............... 444.4 301.5 402.6
Cash dividends on preferred stock..... (6.0) (17.4) (17.4)
Cash dividends on Class A common
stock, 21.38(cent)(1998),
18(cent)(1997) and 18(cent)(1996)
per share........................... (.1) (.1) (.1)
Cash dividends on common stock,
23.75(cent)(1998), 20(cent)(1997)
and 20(cent)(1996) per share........ (50.4) (42.2) (42.1)
-------- -------- --------
Ending balance.................... 2,519.8 2,131.9 1,890.1
-------- -------- --------
LESS TREASURY STOCK - AT COST .......... 4,396 132.5 4,396 132.5 4,395 132.5
======== -------- ======= -------- ======= --------
TOTAL................................... $3,475.8 $3,282.4 $3,036.5
======== ======== ========
</TABLE>
See Notes to Consolidated Financial Statements.
F-18
<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 $291.6 million, $275.7 million and $386.0 million in 1998, 1997
and 1996, respectively. Cash payments for income taxes amounted to $42.4
million, $63.6 million and $57.2 million for 1998, 1997 and 1996, 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 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. Gains or losses from foreign currency swaps are deferred and are
recognized as payments are made on the related foreign currency denominated
debt. 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 $26.9 million, $15.5
million and $8.0 million in 1998, 1997 and 1996, 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
F-19
<PAGE>
of gas and oil properties plus estimated future development costs by the
estimated proved reserves included therein, as estimated by Company engineers
for 1998 and reviewed by independent engineers. Estimated proved reserves for
1997 were estimated by the Company's independent engineers. The average
amortization rate per equivalent unit of a thousand cubic feet of gas production
for oil and gas operations was $.89 for 1998, $.91 for 1997 and $.88 for 1996.
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.............................. 5.0% - 33.3%
Office and miscellaneous equipment.................... 2.5% - 20.0%
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.
Goodwill. Goodwill, which primarily relates to the acquisitions of American
Natural Resources Company and CIG, amounted to $470.8 million at December 31,
1998, 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
1998, 1997 and 1996, 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 prior years reflect the two-for-one stock
split of the Company's common stock declared on May 7, 1998. See Note 8 of the
Notes to Consolidated Financial Statements.
Statement of Financial Accounting Standards No. 71, "Accounting for the
Effects of Certain Types of Regulation" ("FAS 71"). The interstate natural gas
pipelines and certain storage subsidiaries are subject to the regulations and
accounting procedures of the Federal Energy Regulatory Commission ("FERC").
These subsidiaries historically followed the reporting and accounting
requirements of FAS 71. Effective November 1, 1996, these subsidiaries
discontinued application of FAS 71. This accounting change has no direct effect
on either the subsidiaries' ability to include the previously deferred items in
future rate proceedings or on their ability to collect the rates set thereby.
The Company believes this accounting change results in financial reporting which
better reflects the results of
F-20
<PAGE>
operations in the economic environment in which these subsidiaries operate.
Further, the Company has reexamined the useful lives of certain assets
corresponding to these subsidiaries. During 1997, the depreciation rates
associated with these assets were revised, which had the effect of increasing
"Earnings from continuing operations before extraordinary items" and "Net
earnings" by $19.0 million ($.09 per share) in 1998 and $13.4 million ($.06 per
share) in 1997.
Statement of Financial Accounting Standards No. 130, "Reporting
Comprehensive Income" ("FAS 130"). The Company adopted FAS 130 in 1998. The
application of the new standard did not have a material effect on the Company's
consolidated financial statements as the Company currently does not have any
material items of other comprehensive income.
Statement of Financial Accounting Standards No. 131, "Disclosures about
Segments of an Enterprise and Related Information" ("FAS 131"). The Company
adopted FAS 131 in 1998. The Company's disclosures for 1998 and prior years have
been revised in accordance with this statement.
Statement of Financial Accounting Standards No. 132, "Employers'
Disclosures about Pensions and Other Postretirement Benefits" ("FAS 132"). The
Company adopted FAS 132 in 1998. The Company's disclosures for 1998 and prior
years have been revised in accordance with this statement.
Statement of Position 98-1 ("SOP 98-1"). The Accounting Standards Executive
Committee of the American Institute of Certified Public Accountants ("AICPA")
issued SOP 98-1 on Accounting for the Costs of Computer Software Developed or
Obtained for Internal Use, which was adopted by the Company in 1998. The
application of the new statement did not have a material effect on the Company's
consolidated results of operations, financial position or cash flows.
Statement of Financial Accounting Standards No. 133, "Accounting for
Derivative Instruments and Hedging Activities" ("FAS 133"). The Financial
Accounting Standards Board ("FASB") has issued FAS 133 to be effective for all
fiscal quarters of fiscal years beginning after June 15, 1999. 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.
Emerging Issues Task Force Issue No. 98-10. The FASB Emerging Issues Task
Force Issue No. 98-10, to be effective for years beginning after December 15,
1998, states that energy trading contracts (as defined) should be marked to
market with the gains and losses included in earnings and separately disclosed
in the financial statements or footnotes thereto. The Company does not believe
the application of Issue No. 98-10 will have a material effect on its
consolidated financial statements.
Statement of Position 98-5 ("SOP 98-5"). The AICPA has issued SOP 98-5, to
be effective for periods beginning after December 15, 1998. SOP 98-5 provides
guidance on accounting for costs incurred to open new facilities, conduct
business in new territories or otherwise commence some new operation. The
application of SOP 98-5 is not expected to have a material effect on the
Company's consolidated financial statements.
Euro Conversion. In January 1999, certain countries of the European Union
adopted the Euro as their legal common currency. This conversion to the Euro is
not expected 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. Prior period financial
statements have been restated to report the Company's 50% owned trucking
operation as a discontinued operation. In addition, 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.
F-21
<PAGE>
Note 2. Inventories
Inventories at December 31 were (Millions of Dollars):
<TABLE>
<CAPTION>
1998 1997
----------- ----------
<S> <C> <C>
Refined products, crude oil and chemicals.................................. $ 306.9 $ 492.3
Natural gas in underground storage......................................... 32.0 40.5
Coal, materials and supplies............................................... 160.6 151.9
----------- ----------
$ 499.5 $ 684.7
=========== ==========
</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 natural gas
pipeline; Midland Cogeneration Venture (20.4% 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
$970.8 million and $752.6 million at December 31, 1998 and 1997, respectively.
The Company's equity in income of the investments, included in Other Income-Net,
was $124.3 million, $137.5 million and $118.1 million in 1998, 1997 and 1996,
respectively, while dividends and partnership distributions received amounted to
$83.1 million, $94.5 million and $102.9 million in 1998, 1997 and 1996,
respectively.
Summarized financial information of these entities is as follows (Millions
of Dollars):
<TABLE>
<CAPTION>
December 31,
---------------------------
1998 1997
----------- ----------
<S> <C> <C>
Current assets............................................................. $ 1,388.2 $ 1,430.4
Noncurrent assets.......................................................... 5,948.8 5,365.7
----------- ----------
$ 7,337.0 $ 6,796.1
=========== ==========
Current liabilities........................................................ $ 1,093.1 $ 1,288.0
Noncurrent liabilities..................................................... 3,348.2 3,245.6
Deferred credits........................................................... 225.0 228.0
Equity..................................................................... 2,670.7 2,034.5
----------- ----------
$ 7,337.0 $ 6,796.1
=========== ==========
</TABLE>
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------
1998 1997 1996
----------- ----------- -----------
<S> <C> <C> <C>
Revenues.................................................. $ 7,631.4 $ 5,302.1 $ 2,012.6
Operating income.......................................... 563.2 627.5 616.1
Net income................................................ 306.5 353.4 296.5
</TABLE>
F-22
<PAGE>
Note 4. Debt
Long-Term Debt - Balances at December 31 were (Millions of Dollars):
<TABLE>
<CAPTION>
1998 1997
----------- ----------
<S> <C> <C>
The Coastal Corporation:
Notes payable (revolving credit agreements)................................ $ 125.0 $ 125.0
Senior notes:
10.375%, due 2000....................................................... 121.3 121.3
10%, due 2001........................................................... 84.0 83.9
8.75%, due 1999......................................................... 150.0 150.0
8.125%, due 2002........................................................ 249.7 249.6
Senior debentures:
10.25%, due 2004........................................................ 37.7 37.7
10.75%, due 2010........................................................ 56.4 56.4
9.75%, due 2003......................................................... 102.1 102.1
9.625%, due 2012........................................................ 149.3 149.3
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 -
6.95%, due 2028......................................................... 199.4 -
----------- ----------
2,024.6 1,625.2
----------- ----------
Subsidiary companies:
Notes payable (term credit facilities)..................................... 184.3 244.3
Notes payable (revolving credit agreements)................................ 609.0 682.6
Notes payable (project financings), due 2006-2011.......................... 59.6 51.0
Debentures, 6.85% to 10%, due 2005-2037.................................... 777.5 777.4
Other, due 2000-2028....................................................... 70.8 74.7
----------- ----------
1,701.2 1,830.0
----------- ----------
Amount reclassified from short-term debt................................... 400.0 250.0
----------- ----------
Total long-term debt....................................................... 4,125.8 3,705.2
Less current maturities.................................................... 126.5 42.0
----------- ----------
$ 3,999.3 $ 3,663.2
=========== ==========
</TABLE>
- - At December 31, 1998, amounts available under long-term credit agreements
with banks totaled $1,374.3 million, including $125.0 million available to The
Coastal Corporation. Loans under these agreements bear interest at money
market-related rates (weighted average 5.743% at December 31, 1998). Annual
commitment fees range up to .30% payable on the unused portion of the applicable
facility. At December 31, 1998, $918.3 million was outstanding and $45.1 million
of the unused amount was dedicated to a specific use.
The subsidiary project financing notes bear interest at money
market-related rates.
The Company has $150.0 million of 8.75% Senior Notes which are due May 15,
1999. The financial statements at December 31, 1998 reflect this amount as
long-term, based on the availability of committed credit lines with maturities
in excess of one year and the Company's intent to refinance the debt on a
long-term basis.
In February 1999, the Company completed a public offering of $200.0 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-23
<PAGE>
Various agreements contain restrictive covenants which, among other things,
limit dividends by certain subsidiaries and additional indebtedness of certain
subsidiaries. At December 31, 1998, net assets of consolidated subsidiaries
amounted to approximately $6.8 billion, of which $653.0 million was restricted
by such provisions.
Maturities. The aggregate amounts of long-term debt maturities for the five
years following 1998 are (Millions of Dollars):
1999 $126.5 2002 $387.2
2000 $206.6 2003 $116.3
2001 $686.1
Notes Payable. At December 31, 1998, Coastal and its subsidiaries had
$487.0 million of outstanding indebtedness to banks under short-term lines of
credit, compared to $364.0 million at December 31, 1997. As of December 31,
1998, the Company's financial statements reflected $400.0 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 $250.0 million as of December 31, 1997. The weighted
average interest rates were 6.07% and 6.31% at December 31, 1998 and 1997,
respectively. As of December 31, 1998, $649.0 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 $686.1 million
of retained earnings was available at December 31, 1998, 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, 1998, the Company had guaranteed construction financings of two
partially owned partnerships. The Company's proportionate share of the
outstanding principal balance under these guarantees was $94.5 million at
December 31, 1998. These loans are expected to be refinanced on a non-recourse
basis in 1999. The Company and a partner have issued a number of 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,
1998, the Company's share of such guarantees was $521.3 million; the actual
affiliate liabilities related to these guarantees was $95.2 million. Other
guarantees and indemnities related to obligations of unconsolidated affiliates
amounted to approximately $227.5 million as of December 31, 1998. 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 $303.4
million. Rental expense amounted to approximately $86.0 million, $95.3 million
and $92.7 million in 1998, 1997 and 1996, respectively, excluding leases
covering natural resources. Aggregate minimum lease payments under existing
noncapitalized long-term leases are estimated to be $87.2 million, $87.5
million, $91.7 million, $83.7 million, and $87.1 million for the years
1999-2003, respectively, and $577.9 million thereafter.
Note 6. Preferred Stock 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 proceeds
were used to refinance borrowings incurred to finance the redemption of the
Series H Preferred Stock discussed in Note 8 of the Notes to the Consolidated
Financial Statements and to repay certain outstanding
F-24
<PAGE>
subsidiary indebtedness. 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. Shares and aggregate redemption value of mandatory
redemption preferred stock outstanding, excluding shares redeemable within one
year, were (Thousands of Shares and Millions of Dollars):
<TABLE>
<CAPTION>
Shares Value
----------- ----------
<S> <C> <C>
Balance, December 31, 1995................................................. 6 $ .6
Redemptions................................................................ (6) (.6)
----------- ----------
Balance, December 31, 1996................................................. - -
Redemptions................................................................ - -
----------- ----------
Balance, December 31, 1997................................................. - -
Redemptions................................................................ - -
----------- ----------
Balance, December 31, 1998................................................. - $ -
=========== ==========
</TABLE>
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.
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, 1998, the Company had interest rate swaps with a notional amount
of $22.5 million, and a portfolio of variable rate debt outstanding in the
amount of $1,515.7 million. Under these agreements, Coastal will pay the
counterparties interest at a weighted average fixed rate of 6.7%, and the
counterparties will pay Coastal interest at a variable rate equal to LIBOR. The
weighted average LIBOR rate applicable to these agreements was 5.36% at December
31, 1998. 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
LIBOR fluctuates. 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, 1998, 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, 1998 Dec. 31, 1997
---------------------------- -----------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
---------- --------- ---------- ----------
<S> <C> <C> <C> <C>
Nonderivatives:
Financial assets:
Cash and cash equivalents................... $ 106.9 $ 106.9 $ 20.5 $ 20.5
Notes receivable............................ 248.1 271.3 222.3 241.1
Investments................................. 64.0 64.0 56.8 56.8
Financial liabilities:
Short-term debt................................ 87.0 87.0 114.0 114.0
Long-term debt ................................ 4,125.8 4,423.0 3,705.2 4,024.0
Company-obligated mandatory redemption
preferred securities of a consolidated trust 300.0 295.6 - -
Preferred stock - issued by subsidiaries....... 100.0 100.0 100.0 100.0
Derivatives relating to:
Commodity swaps loss........................... - - - -
Debt:
Interest rate swaps loss ...................... - 1.7 - 0.2
</TABLE>
The estimated value of the Company's notes receivable, long-term debt,
Company-obligated mandatory redemption preferred securities of a consolidated
trust and preferred stock - issued by subsidiaries is based on interest rates at
December 31, 1998 and 1997, respectively, for new issues with similar remaining
maturities. The fair value of investments are based on market prices at December
31, 1998 and 1997. The fair market value of the Company's interest rate swaps is
based on the estimated termination values at December 31, 1998 and 1997,
respectively.
Note 8. Common and Preferred Stock
On May 7, 1998, the Board of Directors of Coastal authorized a two-for-one
stock split of the Coastal common stock. On July 1, 1998, stockholders of record
received one additional share of common stock for each share of common stock
and/or Class A common stock held of record on May 29, 1998. The stock split has
been reflected in the accompanying financial statements, and all applicable
references as to the number of common shares and per share information have been
restated. Appropriate adjustments have been made in the conversion ratios of
shares of convertible preferred stock and in the exercise price and number of
shares subject to stock options. Effective with the stock split, the annual cash
dividend rate on the common stock is $.25 per share.
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 331/3% 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 option transactions for the
three years ended December 31, 1998:
<TABLE>
<CAPTION>
Class A Average
Common Common Option Price
Shares Shares Per Share
----------- ----------- ---------------
<S> <C> <C> <C>
December 31, 1995........................................... 4,329,252 14,780 $ 14.08
Granted.................................................. 1,333,000 - 18.30
Exercised................................................ (1,070,002) (12,500) 13.26
Revoked or expired....................................... (123,200) - 15.44
----------- ----------- --------------
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
=========== =========== ==============
</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 items, 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,
-------------------------------------------
1998 1997 1996
----------- ----------- ----------
<S> <C> <C> <C>
Earnings from continuing operations before
extraordinary items.................................... $ 473.8 $ 394.4 $ 505.8
Net earnings.............................................. 435.3 297.2 400.4
Basic earnings per share
From continuing operations before
extraordinary items.................................. $ 2.20 $ 1.78 $ 2.32
Discontinued operations................................ (.18) (.03) (.04)
Extraordinary items.................................... - (.43) (.46)
----------- ----------- ----------
Net basic earnings per share........................... $ 2.02 $ 1.32 $ 1.82
=========== =========== ==========
Diluted earnings per share
From continuing operations before
extraordinary items.................................. $ 2.17 $ 1.75 $ 2.29
Discontinued operations................................ (.18) (.03) (.04)
Extraordinary items.................................... - (.42) (.46)
----------- ----------- ----------
Net diluted earnings per share......................... $ 1.99 $ 1.30 $ 1.79
=========== =========== ==========
</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 1998, 1997 and 1996:
<TABLE>
<CAPTION>
1998 1997 1996
----------- ----------- ----------
<S> <C> <C> <C>
Risk free interest rate................................... 5.57% 6.90% 6.25%
Expected life (years)..................................... 8 8 8
Expected dividend yield................................... .611% .85% 1.40%
Expected volatility....................................... .2241 .2205 .1925
Weighted average fair value of options granted (per share) $ 12.77 $ 9.75 $ 6.16
</TABLE>
Stock options available for future grants amounted to 6,856,789; 493,642;
and 1,813,542 at December 31, 1998, 1997 and 1996, respectively. Exercisable
stock options amounted to 1,706,453; 1,353,198; and 1,496,708 at December 31,
1998, 1997 and 1996, respectively.
The following table summarizes information about stock options outstanding
and exercisable at December 31, 1998:
<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........................ 3,169,796 5.5 $ 15.84 1,518,416 $ 15.06
20.28 - 29.82........................ 1,436,972 8.1 23.60 188,037 23.66
30.74 - 35.28........................ 1,997,849 9.2 32.75 - -
----------- -----------
6,604,617 1,706,453
=========== ===========
<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;
coal; and power. 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.
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.
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 United States and internationally in Asia and Latin
America.
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, 1998, 1997 and 1996 are shown as
follows (Millions of Dollars):
<TABLE>
<CAPTION>
1998 1997 1996
----------- ----------- -----------
<S> <C> <C> <C>
Operating Revenues From External Customers
Natural gas............................................... $ 1,356.8 $ 2,125.5 $ 3,793.4
Refining, marketing and chemicals......................... 5,200.4 6,870.9 7,360.9
Exploration and production................................ 436.6 383.4 184.7
Coal...................................................... 241.7 226.8 713.6
Power..................................................... 121.1 103.8 92.6
Corporate and other ...................................... 11.6 19.7 21.7
----------- ----------- -----------
Consolidated totals.................................... $ 7,368.2 $ 9,730.1 $ 12,166.9
=========== =========== ===========
Intersegment Revenues
Natural gas............................................... $ 1.6 $ 40.7 $ 196.1
Refining, marketing and chemicals......................... 2.3 6.2 3.9
Exploration and production................................ 26.4 106.8 213.8
Coal...................................................... - - -
Power..................................................... - - -
Corporate and other ...................................... 11.4 9.7 11.0
----------- ----------- -----------
Consolidated totals.................................... $ 41.7 $ 163.4 $ 424.8
=========== =========== ===========
Earnings (Loss) Before Interest and Income Taxes
Natural gas............................................... $ 594.3 $ 583.0 $ 490.8
Refining, marketing and chemicals......................... 243.9 95.6 94.4
Exploration and production................................ 109.8 167.6 135.1
Coal...................................................... 17.4 25.3 356.0
Power..................................................... 67.8 43.4 41.4
Corporate and other....................................... (88.7) (70.4) (74.1)
----------- ----------- -----------
Consolidated totals.................................... $ 944.5 $ 844.5 $ 1,043.6
=========== =========== ===========
Depreciation, Depletion and Amortization (Excluding
Amortization of Goodwill)
Natural gas............................................... $ 118.3 $ 136.5 $ 161.7
Refining, marketing and chemicals......................... 78.3 74.6 73.3
Exploration and production................................ 209.2 185.5 158.2
Coal...................................................... 14.6 14.1 37.3
Power..................................................... 3.2 3.1 2.4
Corporate and other....................................... 7.0 4.1 6.0
----------- ----------- -----------
Consolidated totals.................................... $ 430.6 $ 417.9 $ 438.9
=========== =========== ===========
</TABLE>
F-29
<PAGE>
<TABLE>
<CAPTION>
1998 1997 1996
----------- ----------- -----------
<S> <C> <C> <C>
Equity Income (Loss) from Investments
Natural gas............................................... $ 80.4 $ 92.6 $ 93.0
Refining, marketing and chemicals......................... 1.0 8.7 1.1
Exploration and production................................ - - -
Coal...................................................... - - -
Power..................................................... 43.0 36.2 24.1
Corporate and other....................................... (0.1) - (0.1)
----------- ----------- -----------
Consolidated totals.................................... $ 124.3 $ 137.5 $ 118.1
=========== =========== ===========
Capital Expenditures
Natural gas............................................... $ 192.2 $ 224.7 $ 212.5
Refining, marketing and chemicals......................... 229.1 167.6 215.3
Exploration and production................................ 934.8 574.4 375.2
Coal...................................................... 34.7 18.8 51.5
Power..................................................... 2.0 2.2 3.7
Corporate and other....................................... 11.2 9.0 22.6
----------- ----------- -----------
Consolidated totals.................................... $ 1,404.0 $ 996.7 $ 880.8
=========== =========== ===========
</TABLE>
The Company's assets and amount of investment in equity method investees by
segment as of December 31, 1998, 1997 and 1996 is as follows (Millions of
Dollars):
<TABLE>
<CAPTION>
1998 1997 1996
----------- ----------- -----------
<S> <C> <C> <C>
Assets
Natural gas............................................... $ 5,379.5 $ 5,262.0 $ 5,448.2
Refining, marketing and chemicals......................... 3,351.2 3,795.4 4,061.6
Exploration and production................................ 2,161.6 1,484.0 1,125.3
Coal...................................................... 269.6 252.7 225.3
Power..................................................... 449.8 258.1 211.1
Corporate and other....................................... 692.4 587.5 548.9
----------- ----------- -----------
Consolidated totals.................................... $ 12,304.1 $ 11,639.7 $ 11,620.4
=========== =========== ===========
Equity Method Investments
Natural gas............................................... $ 608.9 $ 521.7 $ 404.0
Refining, marketing and chemicals......................... 68.2 64.6 69.1
Exploration and production................................ - - -
Coal...................................................... .5 .5 .5
Power..................................................... 295.0 167.5 133.2
Corporate and other....................................... (1.8) (1.7) (1.9)
----------- ----------- -----------
Consolidated totals.................................... $ 970.8 $ 752.6 $ 604.9
=========== =========== ===========
</TABLE>
Intersegment sales are accounted for on the basis of contract, current
market or internally established transfer prices.
The Coal revenues and earnings before interest and income taxes for 1996
include a gain before income taxes of $272.3 million from the sale of the Utah
coal mining operations. See Note 10 of the Notes to the Consolidated Financial
Statements.
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
and the year ended December 31, 1996 include the revenues of Coastal's natural
gas marketing operations ($833.5 million and $2,780.5 million, respectively).
Subsequent to the combination, Engage's revenues are not included in Coastal's
F-30
<PAGE>
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.
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>
1998 1997 1996
----------- ----------- -----------
<S> <C> <C> <C>
Revenues.................................................. $ 34.8 $ 26.3 $ 26.1
Impact on earnings........................................ 22.6 17.1 16.9
</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, 1998,
1997 and 1996 and property, plant and equipment as of December 31, 1998, 1997
and 1996, by geographic area, are shown as follows (Millions of Dollars):
<TABLE>
<CAPTION>
1998 1997 1996
----------- ----------- -----------
<S> <C> <C> <C>
Operating Revenues
United States............................................. $ 6,381.7 $ 8,059.6 $ 10,595.8
Foreign, Aruba............................................ 743.4 1,251.4 1,154.8
Foreign, Other............................................ 243.1 419.1 416.3
----------- ----------- -----------
Consolidated totals.................................... $ 7,368.2 $ 9,730.1 $ 12,166.9
=========== =========== ===========
Property, Plant and Equipment
United States............................................. $ 7,344.9 $ 6,551.0 $ 6,109.9
Foreign, Aruba............................................ 564.0 478.8 460.3
Foreign, Other............................................ 115.0 91.8 84.7
----------- ----------- -----------
Consolidated totals.................................... $ 8,023.9 $ 7,121.6 $ 6,654.9
=========== =========== ===========
</TABLE>
Revenues from sales to any single customer during 1998, 1997 or 1996 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.
Note 10. Sale of Utah Coal Mining Operations
On December 20, 1996, the Company completed the sale of its coal mining
operations in Utah for approximately $610.1 million in cash. The Company
retained its coal properties in the eastern United States and is continuing to
operate them. The sale resulted in a gain before income taxes of $272.3 million,
which is included in the operating revenues of the Coal segment. The net
earnings from the sale was a gain of $177.0 million, $.84 per share-basic or
$.83 per share-diluted.
F-31
<PAGE>
Following is a summary of the results of operations of the Utah coal mining
operations (Millions of Dollars):
<TABLE>
<CAPTION>
For the Period
From January 1, 1996
Through December 20, 1996
-------------------------
<S> <C>
Operating revenues.......................................................... $ 200.7
Costs and expenses ......................................................... 145.0
--------
Earnings before income taxes............................................. 55.7
Income taxes................................................................ 16.6
--------
Net earnings............................................................. $ 39.1
========
</TABLE>
Note 11. 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,
1998 and 1997 and a statement of the funded status as of December 31, 1998 and
1997 (Millions of Dollars):
<TABLE>
<CAPTION>
Year Ended
December 31,
----------------------------
1998 1997
----------- -----------
<S> <C> <C>
Change in Benefit Obligation
Benefit obligation at beginning of year................................. $ 729.3 $ 658.2
Service cost............................................................ 19.6 17.2
Interest cost........................................................... 49.0 47.5
Plan amendment.......................................................... 3.8 -
Actuarial (gain) loss................................................... (1.5) (5.8)
Change in discount rate................................................. - 55.0
Benefit payments........................................................ (42.3) (42.8)
----------- -----------
Benefit obligation at end of year....................................... $ 757.9 $ 729.3
=========== ===========
Change in Plan Assets
Fair value of plan assets at beginning of year.......................... $ 1,298.7 $ 1,078.7
Actual return on plan assets............................................ 224.9 262.5
Employer contributions.................................................. .5 .3
Benefit payments........................................................ (42.3) (42.8)
----------- -----------
Fair value of plan assets at end of year................................ $ 1,481.8 $ 1,298.7
=========== ===========
</TABLE>
<TABLE>
<CAPTION>
December 31,
----------------------------
1998 1997
----------- -----------
<S> <C> <C>
Funded Status
Funded status at year end............................................... $ 723.9 $ 569.4
Unrecognized transition obligation (asset).............................. (28.5) (37.1)
Unrecognized prior service cost......................................... 5.9 3.0
Unrecognized net (gain) loss............................................ (293.1) (200.7)
----------- -----------
Prepaid pension cost.................................................... $ 408.2 $ 334.6
=========== ===========
</TABLE>
Plan assets include common stock and Class A common stock of the Company
amounting to a total of 7.2 million shares and 7.5 million shares at December
31, 1998 and 1997, respectively.
F-32
<PAGE>
The following table provides the components of the net periodic pension
benefit for 1998, 1997 and 1996 (Millions of Dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------
1998 1997 1996
----------- ----------- -----------
<S> <C> <C> <C>
Service cost.............................................. $ 19.6 $ 17.2 $ 18.3
Interest cost............................................. 49.0 47.5 45.6
Expected return on assets................................. (126.4) (105.7) (92.0)
Amortization of transition obligation (asset)............. (8.6) (8.6) (8.6)
Amortization of prior service cost........................ .8 .4 .4
Amortization of net (gain) loss........................... (7.6) (3.1) (1.3)
Deferred regulatory amounts............................... - - 16.0
----------- ----------- -----------
Net periodic pension benefit ............................. $ (73.2) $ (52.3) $ (21.6)
=========== =========== ===========
</TABLE>
The discount rate used in determining the actuarial present value of the
projected benefit obligation was 7.00% in 1998 and 1997 and 7.50% in 1996. The
expected increase in future compensation levels was 4% in 1998, 1997 and 1996
and the expected long-term rate of return on assets was 10% in 1998, 1997 and
1996.
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 1998, 1997 or 1996.
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 $19.4 million, $18.9 million and $18.5 million in 1998, 1997 and
1996, 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. Certain costs have been deferred by the rate
regulated subsidiaries and were amortized through October 31, 1996. Effective
November 1, 1996, these costs are no longer being deferred as a result of the
Company's discontinued application of FAS 71.
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, 1998 and 1997, and a statement of the funded status
as of December 31, 1998 and 1997 (Millions of Dollars):
<TABLE>
<CAPTION>
Year Ended
December 31,
----------------------------
1998 1997
----------- -----------
<S> <C> <C>
Change in Benefit Obligation
Benefit obligation at beginning of year................................. $ 108.0 $ 110.5
Service cost............................................................ 2.3 2.3
Interest cost........................................................... 6.9 7.0
Participant contributions............................................... 2.8 3.0
Actuarial (gain) loss................................................... (.8) (1.2)
Benefit payments........................................................ (10.2) (10.2)
Curtailment (gain) loss................................................. (.9) -
Plan amendment.......................................................... - (3.4)
----------- -----------
Benefit obligation at end of year....................................... $ 108.1 $ 108.0
=========== ===========
Change in Plan Assets
Fair value of plan assets at beginning of year.......................... $ 24.1 $ 26.0
Actual return on plan assets............................................ .1 1.4
Employer contributions.................................................. 5.5 1.3
Administrative expenses................................................. (.1) (.2)
Benefit payments........................................................ (5.2) (4.4)
----------- -----------
Fair value of plan assets at end of year................................ $ 24.4 $ 24.1
=========== ===========
</TABLE>
<TABLE>
<CAPTION>
December 31,
----------------------------
1998 1997
----------- -----------
<S> <C> <C>
Funded Status
Funded status at year end............................................... $ (83.7) $ (83.9)
Unrecognized transition obligation...................................... 83.2 89.7
Unrecognized prior service cost......................................... 3.5 3.9
Unrecognized (gain) loss................................................ (34.1) (36.3)
----------- -----------
Accrued postretirement benefit obligation............................... $ (31.1) $ (26.6)
=========== ===========
</TABLE>
The following table provides the components of net periodic postretirement
benefit cost for 1998, 1997 and 1996 (Millions of Dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------
1998 1997 1996
----------- ----------- -----------
<S> <C> <C> <C>
Service cost.............................................. $ 2.3 $ 2.3 $ 2.5
Interest cost............................................. 6.9 7.0 7.6
Expected return on assets................................. (.7) (.8) (.7)
Amortization of transition obligation..................... 6.0 6.0 6.2
Amortization of prior service cost........................ .4 .4 .5
Amortization of net (gain) loss........................... (2.6) (2.6) (1.9)
Deferred regulatory amounts............................... - 3.5 3.6
----------- ----------- -----------
Net periodic postretirement benefit cost.................. $ 12.3 $ 15.8 $ 17.8
=========== =========== ===========
</TABLE>
The assumed health care cost trend rate used in measuring the accumulated
postretirement benefit obligation was 9.0% in 1998, 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 9.7% in 1997 and 10.4% in
1996. 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, 1998 by approximately 4.65% and the net postretirement health
care cost by approximately 4.42%. 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, 1998 by approximately 4.64%
and the net postretirement health care cost by approximately 4.52%. The assumed
discount rate used in determining the accumulated postretirement benefit
obligation was 7.0% in 1998, 7.25% in 1997 and 7.5% in 1996 and the expected
long-term rate of return on assets was 4.3% in 1998, 1997 and 1996.
Note 12. Taxes on Income
Pretax earnings from continuing operations before extraordinary items are
composed of the following (Millions of Dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------
1998 1997 1996
----------- ----------- -----------
<S> <C> <C> <C>
United States............................................. $ 502.8 $ 458.2 $ 591.9
Foreign .................................................. 146.8 78.8 83.4
----------- ----------- -----------
$ 649.6 $ 537.0 $ 675.3
=========== =========== ===========
</TABLE>
Provisions for income taxes from continuing operations before extraordinary
items are composed of the following (Millions of Dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------
1998 1997 1996
----------- ----------- -----------
<S> <C> <C> <C>
Current income taxes:
Federal................................................ $ 5.0 $ 50.7 $ 87.2
Foreign................................................ 5.5 5.3 6.4
State.................................................. 4.5 8.4 13.7
----------- ----------- -----------
15.0 64.4 107.3
----------- ----------- -----------
Deferred income taxes:
Federal................................................ 140.9 69.5 56.4
Foreign................................................ 3.4 3.3 3.0
State ................................................. 7.4 1.1 .6
----------- ----------- -----------
151.7 73.9 60.0
----------- ----------- -----------
Taxes on Income........................................... $ 166.7 $ 138.3 $ 167.3
=========== =========== ===========
</TABLE>
The Company and the Internal Revenue Service ("IRS") Appeals Office have
concluded a final settlement of certain adjustments originally proposed to
federal income tax returns filed for the years 1985 through 1987. The IRS has
proposed additional adjustments to those returns, and the Company is contesting
certain of these adjustments before the IRS Appeals Office. The Company's
federal income tax returns filed for the years 1988 through 1990 have been
examined by the IRS and the Company has received notice of proposed adjustments
to the returns for each of those years. The Company currently is contesting
certain of these adjustments with the IRS Appeals Office. Examination of the
Company's federal income tax returns for 1991, 1992, 1993 and 1994 began in
1997. 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,
--------------------------------------------
1998 1997 1996
----------- ----------- -----------
<S> <C> <C> <C>
Tax expense by applying the U.S. federal income
tax rate of 35%........................................ $ 227.4 $ 187.9 $ 236.3
Increases (reductions) in taxes resulting from:
Tight sands gas credit................................. (7.9) (6.5) (7.3)
State income tax cost ................................. 7.7 6.2 9.2
Goodwill............................................... 6.4 6.4 6.4
Research activities credit............................. - - (11.8)
Exclusion for foreign investments and certain
domestic joint ventures............................ (50.3) (50.6) (59.2)
Depletion and depreciation............................. (1.2) (1.4) (6.3)
Other.................................................. (15.4) (3.7) -
----------- ----------- -----------
Taxes on income .......................................... $ 166.7 $ 138.3 $ 167.3
=========== =========== ===========
</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,
----------------------------
1998 1997
----------- -----------
<S> <C> <C>
Excess of book basis over tax basis of property, plant and equipment ...... $ 1,637.4 $ 1,469.6
Pensions and benefit costs................................................. 109.8 98.6
Purchase gas and other recoverable cost.................................... - 32.7
Other...................................................................... 67.2 20.2
----------- -----------
Deferred tax liabilities................................................... 1,814.4 1,621.1
----------- -----------
Alternative minimum tax credit carryforward................................ (195.4) (181.2)
Purchase gas and other recoverable cost.................................... (14.0) -
----------- -----------
Deferred tax assets........................................................ (209.4) (181.2)
----------- -----------
Deferred income taxes...................................................... $ 1,605.0 $ 1,439.9
=========== ===========
</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 unremitted earnings of $323.2 million are considered to
be indefinitely reinvested outside the U.S. and, accordingly, no U.S. income
taxes have been provided on those earnings.
Note 13. Discontinued Operations
The Company is pursuing the disposition of its 50% ownership of ANR Advance
Transportation Company, Inc. ("ANR Advance"), a trucking operation. The Company
is considering all options, including full liquidation, 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, 1998.
Prior year financial statements have been restated to conform with the current
presentation. The net assets (liabilities) of the discontinued operations
amounted to $(.5) million and $47.3 million at December 31, 1998 and 1997,
respectively.
Operating results of the discontinued operations are shown separately in
the accompanying statement of consolidated operations. Prior year financial
statements have been restated to conform with the current presentation. The loss
from operations shown on the statement of consolidated operations is net of
income tax benefits of $1.9 million, $3.5 million and $4.2 million in 1998, 1997
and 1996, 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 14. Extraordinary Items
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.
In June 1996, the Company retired $400.0 million of 11 3/4% Senior
Debentures due in 2006. Payment of the redemption premium and the recognition of
deferred costs related to the Senior Debentures resulted in an extraordinary
loss of $12.0 million ($.06 per share), net of related income taxes of $6.5
million.
Discontinuation of Regulatory Accounting. Effective November 1, 1996, the
interstate natural gas pipeline and certain storage subsidiaries of the Company
ceased to apply the provisions of FAS 71 to their transactions and balances. The
Company believes this accounting change results in financial reporting which
better reflects the results of operations in the economic environment in which
these subsidiaries now operate. The impact of this change was a charge to
earnings of $85.6 million ($.40 per share), net of related income taxes of $50.0
million.
Note 15. 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, 1998
------------------------------------------------
Income Shares
(Numerator) (Denominator) Per-Share
(Millions) (Thousands) Amount
-------------- ----------- -----------
<S> <C> <C> <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> <C> <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>
<TABLE>
<CAPTION>
For the Year Ended December 31, 1996
------------------------------------------------
Income Shares
(Numerator) (Denominator) Per-Share
(Millions) (Thousands) Amount
-------------- ----------- -----------
<S> <C> <C> <C>
Earnings from continuing operations before
extraordinary items.................................. $ 508.0
Less preferred stock dividends.......................... 17.4
--------------
Basic earnings per share
Income available to common stockholders.............. 490.6 210,987 $ 2.33
===========
Effect of dilutive securities
Options.............................................. - 1,241
Convertible preferred stock.......................... .4 1,458
-------------- -----------
Diluted earnings per share
Income available to common stockholders plus
assumed conversions.............................. $ 491.0 213,686 $ 2.30
============== =========== ===========
</TABLE>
Note 16. Litigation, Environmental and Regulatory Matters
Litigation. In connection with the December 20, 1996 sale of the Company's
western coal operations, the Company assumed control of a pending dispute with
the Intermountain Power Agency ("IPA") involving two coal sales agreements of
Coastal States Energy Company, which contracts were included in the sale, and
for which the Company continued to have certain responsibilities. On July 14,
1997, IPA made a demand for arbitration between the parties, asserting a claim
of a gross inequity under the contracts requiring a reduction in the purchase
price of coal sold before and after the sale of these coal operations. The
Company believed that no gross inequity had occurred and that it would prevail
in the arbitration on the merits. However, in an attempt to resolve this and
several other unrelated issues concerning the Company's continuing
responsibilities under the terms of the December 1996 sale, the Company entered
into negotiation with several interested parties. Pursuant to a January 20, 1999
multi-party agreement, in which virtually all of the Company's indemnification
obligations were terminated, IPA dismissed its "gross inequity" claim. This
favorable resolution of all outstanding claims arising under the original sale
of the western coal operations had no adverse impact on the Company.
In December 1992, certain of CIG's natural gas lessors in the West
Panhandle Field filed a complaint in the U.S. District Court for the 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
F-38
<PAGE>
summary judgment in favor of CIG, holding that the four-year statute of
limitations had not been tolled, that 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 United States District Court, Southern District of Texas. The
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 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
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 1996, Jack Grynberg filed a claim under the False Claims Act on behalf
of the U.S. government in the U.S. District Court, District of Columbia, against
70 defendants, including ANR Pipeline and CIG. The suit sought damages for the
alleged underpayment of royalties due to the purported improper measurement of
gas. The 1996 suit was dismissed without prejudice in March 1997 and the
dismissal was affirmed by the D.C. Court of Appeals in October 1998. In
September 1997, Mr. Grynberg filed 77 separate, similar False Claims Act suits
against natural gas transmission companies and producers, gatherers, and
processors of natural gas, seeking unspecified damages. Coastal and several of
its subsidiaries have been included in two of the September 1997 suits. The
suits were filed in both the U.S. District Court, District of Colorado and the
U.S. District Court, Eastern District of Michigan. The United States Department
of Justice has notified the Company that it is reviewing these lawsuits to
determine whether or not the United States will intervene.
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 $13 million in 1998 on environmental
capital projects and anticipates capital expenditures of approximately $44
million in 1999 in order to comply with such laws and regulations. The majority
of the 1999 expenditures is attributable to projects at the Company's refining,
chemical and terminal facilities. The Company currently anticipates capital
expenditures for environmental compliance for the years 2000 through 2002 of $20
to $40 million per year.
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
F-39
<PAGE>
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
several "Superfund" waste disposal sites. At the 11 sites for which there is
sufficient information, total cleanup costs are estimated to be approximately
$620 million, and the Company estimates its pro-rata exposure, to be paid over a
period of several years, is approximately $7.5 million and has made appropriate
provisions. At nine other sites, the Environmental Protection Agency ("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 two
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 the second state site, the Florida Department of
Environmental Protection has demanded reimbursement of its costs, which total
$100,000, and suitable remediation. There is not sufficient information to
estimate the remedial costs or the Company's pro-rata exposure at this site.
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 financial position or results of operations.
Regulatory Matters. On January 31, 1996, the FERC issued a "Statement of
Policy and Request for Comments" ("Policy"). Under this Policy, (i) a pipeline
and a customer are allowed to negotiate a contract which provides for rates and
charges that exceed the pipeline's posted maximum tariff rates, provided that
the customer agreeing to such negotiated rates has the ability to elect to
receive service at the pipeline's posted maximum rate (known as a "recourse
rate"), and (ii) a pipeline must also make subsequent tariff filings each time
the pipeline negotiates a rate for service which is outside of the minimum and
maximum range for the pipeline's cost-based recourse rates. To implement this
Policy, a pipeline must make an initial tariff filing with the FERC to indicate
that it intends to contract for services under this Policy. CIG has received
FERC authority to enter into negotiated rate transactions. Separately, the FERC
has determined that pipelines who seek to include negotiated rate transactions
in the discount adjustment used to calculate their rates must file tariff sheets
demonstrating that existing customers who purchase service under the pipeline's
cost-of-service rates will not be harmed by negotiated rate discounts.
On July 29, 1998, the FERC issued a "Notice of Proposed Rulemaking," in
which the FERC has proposed a number of further 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. The due date for comments on both of these
matters has been rescheduled twice and is currently scheduled for April 22,
1999. The FERC has indicated that it may consider both proposals together
inasmuch as they raise several common issues.
On May 30, 1997, Wyoming Interstate Company, Ltd. ("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. After the filing of testimony by WIC and other parties on July 2, 1998,
WIC filed a settlement offer which, if approved, would have resolved all of the
issues in the case. The settlement, however, was remanded to the Administrative
Law Judge ("ALJ") because of opposition to the settlement by certain parties. In
response to the remand, WIC and the parties have resubmitted a settlement offer
which contains the same substantive provisions, but provides for the FERC to
approve the settlement for some, if not all, parties, with the "severed" parties
being able to litigate their issues in the case. The ALJ has certified the new
settlement to the FERC, and dates for filing briefs on the new settlement have
been established.
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
F-40
<PAGE>
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 17. Quarterly Results of Operations (Unaudited)
Results of operations by quarter for the years ended December 31, 1998 and
1997 were (Millions of Dollars Except per Share):
<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>
<TABLE>
<CAPTION>
Quarter Ended
----------------------------------------------------------------------
March 31, 1997 June 30, 1997 Sept. 30, 1997 Dec. 31, 1997
-------------- ------------- -------------- -------------
<S> <C> <C> <C> <C>
Operating revenues......................... $ 3,205.8 $ 2,156.6 $ 2,143.0 $ 2,224.7
Less purchases............................. 2,465.4 1,473.2 1,427.9 1,497.0
---------- ----------- ---------- ----------
740.4 683.4 715.1 727.7
Other income and expenses.................. 637.6 602.7 633.3 594.3
---------- ----------- ---------- ----------
Earnings from continuing operations
before extraordinary items.............. 102.8 80.7 81.8 133.4
Discontinued operations.................... (1.6) (1.4) (1.4) (2.2)
---------- ----------- ---------- ----------
Earnings before extraordinary items........ 101.2 79.3 80.4 131.2
Extraordinary items........................ (90.6) - - -
---------- ----------- ---------- ----------
Net earnings .............................. $ 10.6 $ 79.3 $ 80.4 $ 131.2
========== =========== ========== ==========
Basic earnings per share:
From continuing operations
before extraordinary items............ $ .47 $ .36 $ .36 $ .61
Discontinued operations................. (.01) (.01) - (.01)
Extraordinary items..................... (.43) - - -
---------- ----------- ---------- ----------
Net basic earnings per share............ $ .03 $ .35 $ .36 $ .60
========== =========== ========== ==========
Diluted earnings per share:
From continuing operations before
extraordinary items................... $ .46 $ .36 $ .35 $ .60
Discontinued operations................. (.01) (.01) - (.01)
Extraordinary items..................... (.42) - - -
---------- ----------- ---------- ----------
Net diluted earnings per share.......... $ .03 $ .35 $ .35 $ .59
========== =========== ========== ==========
</TABLE>
F-41
<PAGE>
Operating revenues, purchases and operating expenses for 1997 include
activity for only two months 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.
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 operations. All of the Company's producing properties
are located in the United States.
Estimated Quantities of Proved Reserves
<TABLE>
<CAPTION>
Natural Exploration
Gas and
Systems Production
--------- --------------------------
Developed Developed Undeveloped Total
Natural Gas (MMcf): --------- --------- ----------- ---------
------------------
<S> <C> <C> <C> <C>
1998.................................................. 211,761 1,287,207 1,028,167 2,527,135
1997.................................................. 248,248 953,235 551,031 1,752,514
1996.................................................. 267,927 757,117 431,488 1,456,532
Oil, Condensate and Natural Gas Liquids (000 barrels):
-----------------------------------------------------
1998.................................................. 237 31,894 20,153 52,284
1997.................................................. 349 27,016 12,778 40,143
1996.................................................. 391 30,328 13,743 44,462
</TABLE>
Changes in proved reserves since the end of 1995 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 1995.............................. 302,420 851,064 126 36,164
-------- ---------- ------- ---------
Production during 1996.......................... (39,405) (129,149) (23) (5,062)
Extensions and discoveries...................... 264 418,410 265 7,083
Acquisitions.................................... - 56,729 - 5,239
Sales of reserves in-place...................... - (30,412) - (1,076)
Revisions of previous quantity estimates and
other..................................... 4,648 21,963 23 1,723
-------- ---------- ------- ---------
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
======== ========== ======= =========
</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 225,853,
213,571 and 153,276 MMcf and storage liquids volumes are approximately 232,000,
209,000 and 192,000 barrels at December 31, 1998, 1997 and 1996, respectively.
Total proved reserves for natural gas includes approximately 162,000, 32,000 and
90,000 MMcf associated with volumetric production payments sold by the Company
for the years 1998, 1997 and 1996, respectively.
All of the Company's proved reserves are located in the United States.
International activities are connected with the evaluation of various
concessions. Therefore, the tables setting forth statistical data on reserves
and cash flows are for properties located in the United States while the tables
on costs contain certain capitalized transactions attributable to start-up
activities connected with international operations. These capitalized
international transactions are not material in nature.
Capitalized Costs Relating to Exploration and Production Activities
(Millions of Dollars)
<TABLE>
<CAPTION>
December 31,
--------------------
1998 1997
-------- --------
Proved and Unproved Properties:
- ------------------------------
<S> <C> <C>
Proved properties....................................................................... $ 2,667 $ 2,006
Unproved properties..................................................................... 153 108
-------- --------
2,820 2,114
Accumulated depreciation, depletion and amortization.................................... (765) (757)
-------- --------
$ 2,055 $ 1,357
======== ========
<FN>
The Company follows the full-cost method of accounting for oil and gas
properties.
</FN>
</TABLE>
Costs Excluded from Amortization
(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, 1998. 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 1998 1997 1996 1996
--------- --------- -------- -------- ---------
<S> <C> <C> <C> <C> <C>
Property acquisition............................. $ 159 $ 132 $ 23 $ 2 $ 2
Exploration...................................... 75 66 4 3 2
Development...................................... 39 32 6 1 -
Capitalized interest............................. 7 7 - - -
--------- --------- -------- -------- ---------
$ 280 $ 237 $ 33 $ 6 $ 4
========= ========= ======== ======== =========
</TABLE>
F-44
<PAGE>
Costs Incurred in Oil and Gas Acquisition, Exploration and Development
Activities (Millions of Dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------
1998 1997 1996
-------- -------- --------
<S> <C> <C> <C>
Property acquisition costs:
Proved................................................................. $ 129 $ 48 $ 42
Unproved............................................................... 133 49 27
Exploration costs............................................................ 123 83 48
Development costs............................................................ 540 388 255
</TABLE>
Results of Operations for Domestic Exploration and Production Activities
(Millions of Dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------
1998 1997 1996
-------- -------- --------
<S> <C> <C> <C>
Revenues:
Sales..................................................................... $ 333 $ 227 $ 113
Transfers................................................................. 111 240 282
-------- -------- --------
Total.................................................................. 444 467 395
-------- -------- --------
Production costs............................................................. (89) (92) (73)
Operating expenses........................................................... (44) (34) (32)
Depreciation, depletion and amortization..................................... (195) (171) (141)
-------- -------- --------
116 170 149
Income tax expense........................................................... (33) (52) (45)
-------- -------- --------
Results of operations for producing activities (excluding corporate
overhead and interest costs).............................................. $ 83 $ 118 $ 104
======== ======== ========
</TABLE>
The average domestic amortization rate per equivalent Mcf was $0.89 in
1998, $0.91 in 1997 and $0.88 in 1996. Depreciation, depletion and amortization
excludes provisions for the impairment of international projects of $9.1 million
in 1998, $10.7 million in 1997 and $14.6 million in 1996.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved
Oil and Gas Reserve Quantities. Future cash inflows for the year ended December
31, 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 amounts for
1997 and 1996 were 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 recent
declines in both natural gas and crude oil prices, may be subject to material
future revisions (Millions of Dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------------------------------------------------
1998 1997 1996
------------------------- ------------------------- -------------------------
Natural Exploration Natural Exploration Natural Exploration
Gas and Gas and Gas and
Systems Production Systems Production Systems Production
----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Future cash inflows.......... $ 256 $ 4,939 $ 291 $ 4,190 $ 430 $ 5,384
Future production and
development costs........... (79) (1,909) (87) (1,479) (85) (1,432)
Future income tax expenses... (57) (584) (67) (635) (117) (1,141)
----------- ----------- ----------- ----------- ----------- -----------
Future net cash flows........ 120 2,446 137 2,076 228 2,811
10% annual discount for
estimated timing of
cash flows.................. (51) (865) (57) (651) (88) (851)
----------- ----------- ----------- ----------- ----------- -----------
Standardized measure of
discounted future net
cash flows.................. $ 69 $ 1,581 $ 80 $ 1,425 $ 140 $ 1,960
=========== =========== =========== =========== =========== ===========
</TABLE>
Future cash inflows include $187 million for 1998, $50 million for 1997 and
$245 million for 1996 related to volumes dedicated to volumetric production
payments sold 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,
---------------------------------------------------------------------------------
1998 1997 1996
------------------------- ------------------------- -------------------------
Natural Exploration Natural Exploration Natural Exploration
Gas and Gas and Gas and
Systems Production Systems Production Systems Production
----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Sales and transfers, net of
production costs............ $ (34) $ (338) $ (34) $ (373) $ (45) $ (304)
Net changes in prices and
production costs............ 3 (334) (53) (906) 95 874
Extensions and discoveries... - 430 10 322 4 941
Acquisitions................. - 317 - 289 - 188
Sales of reserves in-place... - (21) - (117) - (27)
Development costs incurred
during the period that
reduced estimated future
development costs........... - 115 - 11 - 36
Revisions of previous
quantity estimates, timing
and other................... 6 (322) (34) (392) 39 26
Accretion of discount........ 8 141 17 233 7 57
Net change in income taxes... 6 168 34 398 (35) (550)
----------- ----------- ----------- ----------- ----------- -----------
Net change................... $ (11) $ 156 $ (60) $ (535) $ 65 $ 1,241
=========== =========== =========== =========== =========== ===========
</TABLE>
None of the amounts include any value for natural gas systems storage gas
and liquids volumes, which was approximately 41 Bcf for CIG, 132 Bcf for ANR
Pipeline, 53 Bcf for Mid Michigan Gas Storage Company and 232,000 barrels of
liquids for CIG at the end of 1998.
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,
------------------------
1998 1997
--------- ---------
<S> <C> <C>
ASSETS
- ------
CURRENT ASSETS:
Cash and cash equivalents......................................................... $ 79.6 $ .5
Receivables....................................................................... 6.1 8.9
Receivables from subsidiaries..................................................... 1,516.6 1,150.6
Prepaid expenses and other........................................................ 4.6 3.4
--------- ---------
Total Current Assets........................................................... 1,606.9 1,163.4
--------- ---------
PROPERTY, PLANT AND EQUIPMENT - at cost, net......................................... .5 .9
--------- ---------
INVESTMENTS IN SUBSIDIARIES AND OTHER ASSETS:
Investment in subsidiaries at cost plus equity in undistributed earnings since
acquisition.................................................................... 4,361.7 3,992.4
Due from subsidiaries............................................................. 128.1 -
Deferred federal income taxes..................................................... 120.5 86.4
Other assets...................................................................... 392.3 324.9
--------- ---------
5,002.6 4,403.7
--------- ---------
$ 6,610.0 $ 5,568.0
========= =========
</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,
------------------------
1998 1997
--------- ---------
<S> <C> <C>
LIABILITIES AND STOCKHOLDERS' EQUITY
- ------------------------------------
CURRENT LIABILITIES:
Notes payable..................................................................... $ 87.0 $ 114.0
Accounts payable and accrued expenses............................................. 70.0 124.4
Payable to subsidiaries........................................................... 242.4 171.7
Current maturities on long-term debt.............................................. 50.0 30.0
--------- ---------
Total Current Liabilities...................................................... 449.4 440.1
--------- ---------
DUE TO SUBSIDIARIES.................................................................. 309.8 -
--------- ---------
DEBT:
Long-term debt.................................................................... 2,374.6 1,845.2
--------- ---------
DEFERRED CREDITS AND OTHER........................................................... .4 .3
--------- ---------
COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY.......................................... 3,475.8 3,282.4
--------- ---------
$ 6,610.0 $ 5,568.0
========= =========
</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,
---------------------------------------
1998 1997 1996
--------- --------- ---------
<S> <C> <C> <C>
OPERATING REVENUES..................................................... $ - $ - $ -
OPERATING COSTS AND EXPENSES........................................... - - -
--------- --------- ---------
OPERATING PROFIT....................................................... - - -
--------- --------- ---------
OTHER INCOME:
Equity in net earnings of subsidiaries.............................. 455.6 424.8 465.5
Interest income from subsidiaries - net............................. 54.4 63.0 119.2
Other income - net.................................................. 70.4 62.0 28.3
--------- --------- ---------
580.4 549.8 613.0
--------- --------- ---------
OTHER EXPENSES (BENEFITS):
General and administrative.......................................... 10.0 11.7 6.6
Interest and debt expense........................................... 179.9 166.9 245.4
Taxes on income..................................................... (66.4) (20.9) (53.6)
--------- --------- ---------
123.5 157.7 198.4
--------- --------- ---------
EARNINGS FROM CONTINUING OPERATIONS
BEFORE EXTRAORDINARY ITEMS.......................................... 456.9 392.1 414.6
DISCONTINUED OPERATIONS, NET OF INCOME TAXES:
Estimated loss on disposal.......................................... (12.5) - -
--------- --------- ---------
EARNINGS BEFORE EXTRAORDINARY ITEM..................................... 444.4 392.1 414.6
--------- --------- ---------
EXTRAORDINARY ITEM, NET OF INCOME TAXES:
Loss on early extinguishment of debt................................ - (90.6) (12.0)
--------- --------- ---------
NET EARNINGS........................................................... $ 444.4 $ 301.5 $ 402.6
========= ========= =========
</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,
---------------------------------------
1998 1997 1996
--------- --------- ---------
<S> <C> <C> <C>
Net Cash Flow From Operating Activities:
Earnings from continuing operations before extraordinary item....... $ 456.9 $ 392.1 $ 414.6
Items not requiring (providing) cash:
Depreciation, depletion and amortization......................... .1 .1 .1
Deferred income taxes............................................ (35.2) (25.1) 44.8
Undistributed subsidiary earnings................................ (248.5) (363.7) (340.9)
Working capital and other changes, excluding changes relating to cash and
non-operating activities:
Receivables................................................... 2.8 1.8 30.1
Prepaid expenses and other.................................... (1.2) (.5) (.3)
Accounts payable and accrued expenses......................... (54.4) 82.6 (76.2)
Other......................................................... (75.6) (39.9) (24.2)
--------- --------- ---------
44.9 47.4 48.0
--------- --------- ---------
Cash Flow from Investing Activities:
Purchases of property, plant and equipment.......................... (.2) (.1) (.1)
Net change in accounts with subsidiaries............................ (113.6) 143.2 903.8
Investments in subsidiaries......................................... (120.3) (2.5) (77.2)
--------- --------- ---------
(234.1) 140.6 826.5
--------- --------- ---------
Cash Flow from Financing Activities:
Increase (decrease) in short-term notes............................. 123.0 259.0 (268.2)
Proceeds from issuing common stock.................................. 5.5 7.3 14.7
Proceeds from long-term debt issues................................. 406.9 523.4 -
Redemption of preferred stock....................................... (200.0) - -
Payments to retire long-term debt................................... (10.6) (933.1) (549.1)
Dividends paid...................................................... (56.5) (59.7) (59.6)
--------- ---------- ---------
268.3 (203.1) (862.2)
--------- --------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents................... 79.1 (15.1) 12.3
Cash and Cash Equivalents at Beginning of Year......................... .5 15.6 3.3
--------- --------- ---------
Cash and Cash Equivalents at End of Year............................... $ 79.6 $ .5 $ 15.6
========= ========= =========
</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 $173.6 million, $178.5 million and $279.0
million in 1998, 1997 and 1996, respectively. Cash payments (refunds - primarily
from subsidiaries) for income taxes amounted to $8.5 million, $(97.9) million
and $(41.9) million for 1998, 1997 and 1996, 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 $241.7 million of guaranteed
long-term debt of subsidiaries was outstanding at December 31, 1998, 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 1998 are (Millions of Dollars):
1999...................... $ 50.0 2002................ $ 250.0
2000...................... 196.3 2003................ 102.3
2001...................... 84.1
Note 4. Dividends Received
Cash dividends received from consolidated subsidiaries were as follows:
1998 - $207.1 million, 1997 - $61.1 million and 1996 - $124.6 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, 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
===== ===== ====== =======
Year Ended December 31, 1996
Allowance for doubtful accounts.................... $21.4 $ 6.0 $(4.0)(A) $ 23.4
===== ===== ===== =======
<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+ 1984 Stock Option Plan (Appendix B to Coastal's Proxy Statement
for the 1984 Annual Meeting of Stockholders, dated May 14, 1984).
10.2+ 1985 Stock Option Plan (Appendix A to Coastal's Proxy Statement
for the 1986 Annual Meeting of Stockholders, dated March 27, 1986).
10.3+ 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).
10.4+ 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).
10.5+ 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).
10.6+ The Coastal Corporation Stock Purchase Plan, as restated on
January 1, 1994 (Appendix B to Coastal's Proxy Statement for the
1994 Annual Meeting of Stockholders dated March 29, 1994).
10.7+ 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.)
10.8+ 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.)
10.9+ 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).
10.10+ 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.)
10.11+ 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).
10.12+ 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).
10.13+ 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.
* Indicates documents filed herewith.
<PAGE>
EXHIBIT INDEX
Exhibit
Number Document
- ------- --------------------------------------------------------------------
10.14+ 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).
10.15+ 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).
10.16+ 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).
10.17+ 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.)
10.18+ 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.)
10.19+ 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.)
10.20+ 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).
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.
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,
---------------------------------------
1998 1997 1996
--------- --------- ---------
<S> <C> <C> <C>
BASIC EARNINGS PER SHARE
- ------------------------
Net earnings....................................................... $ 444.4 $ 301.5 $ 402.6
Dividends on preferred stock....................................... 6.0 17.4 17.4
--------- --------- ---------
Net earnings available to common stockholders...................... $ 438.4 $ 284.1 $ 385.2
========= ========= =========
Average number of common shares outstanding............................ 212,184 211,518 210,597
Average number of Class A common shares outstanding.................... 359 374 390
--------- --------- ---------
212,543 211,892 210,987
========= ========= =========
Basic earnings per share:
From continuing operations before extraordinary items.............. $ 2.24 $ 1.80 $ 2.33
Discontinued operations............................................ (.18) (.03) (.04)
Extraordinary items................................................ - (.43) (.46)
--------- --------- ---------
Net basic earnings per share....................................... $ 2.06 $ 1.34 $ 1.83
========= ========= =========
DILUTED EARNINGS PER SHARE
- --------------------------
Net earnings used in calculating basic earnings per share.......... $ 438.4 $ 284.1 $ 385.2
Dividends applicable to dilutive preferred stock:
Series A........................................................ .1 .1 .1
Series B........................................................ .1 .1 .1
Series C........................................................ .1 .2 .2
--------- --------- ---------
Income available to common shareholders plus
assumed conversions............................................. $ 438.7 $ 284.5 $ 385.6
========= --------- =========
Average number of shares used in calculating basic earnings
per share.......................................................... 212,543 211,892 210,987
Effect of dilutive securities:
Options............................................................ 2,248 1,798 1,241
Series A, B and C preferred stock.................................. 1,317 1,412 1,458
--------- --------- ---------
216,108 215,102 213,686
========= ========= =========
Diluted earnings per share:
From continuing operations before extraordinary items.............. $ 2.21 $ 1.77 $ 2.30
Discontinued operations............................................ (.18) (.03) (.04)
Extraordinary items................................................ - (.42) (.46)
--------- --------- ---------
Net diluted earnings per share..................................... $ 2.03 $ 1.32 $ 1.80
========= ========= =========
<FN>
- --------------------
Convertible securities and options are not considered in the calculations if
the effect of the conversion is anti-dilutive.
</FN>
</TABLE>
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
Coastal Capital Corporation .......................................................... Delaware
Coastal Finance Corporation................................................... Delaware
Coastal Coal, Inc..................................................................... Delaware
Coastal Credit, Inc........................................................... Delaware
Coastal Finance I..................................................................... Delaware
Coastal Gas Services Company.......................................................... Delaware
ANR Gas Supply Company........................................................ Delaware
ANR Transportation Services Company........................................... Delaware
Coastal Electric Services Company............................................. Delaware
Coastal Field Services Company................................................ Delaware
CIG Merchant Company.................................................. Delaware
Coastal Gas Gathering and Processing Company.......................... Delaware
Coastal Aux Sable Products Company........................... Delaware
Coastal Dauphin Island Company, L.L.C...................... Delaware
Blacks Fork Gas Processing Company (50%)**................... Wyoming*
Coastal States Gas Transmission Company....................................... Delaware
Starr-Zapata Pipe Line (50%)**........................................ Texas*
Coastal Gas Marketing Company................................................. Delaware
CGM, Inc.............................................................. Delaware
Engage Energy US, L.P. (50%)**............................... Delaware*
Coastal Multi-Fuels, Inc...................................................... Delaware
Coastal Pan American Corporation.............................................. Delaware
Coastal Southern Pipeline Company............................................. Delaware
Coastal Gas International Company..................................................... Delaware
Coastal Gas & Power India I Ltd............................................... Cayman Islands
Coastal Gas Australia Proprietary Ltd......................................... Australia
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 Halcon Pipeline I Ltd................................................. Cayman Islands
Coastal Halcon Pipeline II Ltd................................................ Cayman Islands
Coastal Gas de Mexico S. de R. L. de C.V.............................. Mexico
Coastal Horsham Pipeline I Ltd................................................ Cayman Islands
Coastal Horsham Pipeline II Ltd............................................... Cayman Islands
Coastal Gas Pipelines Victoria, L.L.C................................. Delaware
Coastal Health Management Corporation (94%)........................................... Delaware
Coastal Holding Corporation........................................................... Delaware
CIC Industries, Inc........................................................... Delaware
Coastal Chem, Inc..................................................... Delaware
Coastal Pipeline Company.............................................. Delaware
Coastal Refining & Marketing, Inc..................................... Delaware
Coastal Petroleum (Bahamas) Limited.......................... The Bahamas
Coastal Refined Products Corporation......................... Delaware
Coastal Liquids Transportation, L.P.................... Delaware
</TABLE>
1
<PAGE>
SUBSIDIARIES OF THE COASTAL CORPORATION
<TABLE>
<CAPTION>
State or Other Jurisdiction of
Incorporation or Organization
------------------------------
<S> <C>
Coastal Liquids Partners, L.P (32%) **........ Delaware*
Coastal States Crude Gathering Company........................ Texas
Distribuidora Coastal, S.A. de C.V............................ El Salvador
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 West Ventures, Inc.................................................... Delaware
Coastal Limited Ventures, Inc......................................................... 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 Natural Gas Company........................................................... Delaware
American Natural Resources Company............................................ Delaware
ANRFS Holdings, Inc................................................... Delaware
ANR Advance Holdings, Inc. (50%)**........................... Delaware
ANR Advance Transportation Company, Inc............... Delaware
Transport USA, Inc.................................... Pennsylvania
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 Finance B.V....................................................... The Netherlands
Coastal Financial B.V......................................... The Netherlands
Coastal Financial Antilles N.V........................ Netherlands Antilles
Coastal Netherlands Financial B.V............................. The Netherlands
ANR Independence Pipeline Company..................................... Delaware
ANR Intrastate Gas Company, Inc....................................... Delaware
ANR Pipeline Company.................................................. Delaware
ANR Alliance Pipeline Company Canada, Inc..................... Canada
ANR Alliance Pipeline Company U.S., Inc....................... Delaware
ANR Atlantic Pipeline Company................................. Delaware
ANR Capital Corporation....................................... Delaware
ANR Energy Conversion Company................................. Michigan
ANR Iroquois, Inc............................................. Delaware
ANR New England Pipeline Company....................... Delaware
ANR Mayflower Company........................................ Delaware
ANR Southern Pipeline Company................................ Delaware
American Natural Offshore Company............................ Delaware
Texas Offshore Pipeline System, Inc.................... Delaware
</TABLE>
2
<PAGE>
SUBSIDIARIES OF THE COASTAL CORPORATION
<TABLE>
<CAPTION>
State or Other Jurisdiction of
Incorporation or Organization
------------------------------
<S> <C>
Unitex Offshore Transmission Company................... Delaware
ANR Production Company................................................ Delaware
ANRPC Holdings, Inc.......................................... Delaware
ANR Storage Company................................................... Michigan
ANR Blue Lake Company........................................ Delaware
Blue Lake Gas Storage Company (75%)**.................. Michigan*
ANR Cold Springs Company..................................... Delaware
ANR Eaton Company............................................ Michigan
Eaton Rapids Gas Storage System (50%)**................ Michigan*
ANR Jackson Company.......................................... Delaware
ANR Northeastern Gas Storage Company......................... Delaware
Steuben Gas Storage Company (50%)**.................... New York*
ANR Western Storage Company.................................. Delaware
ANR Venture Eagle Point Company....................................... Delaware
ANR Venture Management Company........................................ Delaware
Capitol District Energy Center Cogeneration
Associates (50%)**......................................... Connecticut*
ANR Western Coal Development Company.................................. Delaware
Coastal Coal Company, LLC............................................. Delaware
Coastal Coal - West Virginia, LLC............................ Delaware
Coastal International Finance Ltd..................................... Honduras
Coastal Offshore Finance Ltd................................. Cayman Islands
Coastal Offshore Insurance Ltd......................... Bermuda
Coastal Great Lakes, Inc.............................................. Delaware
Great Lakes Gas Transmission Limited Partnership (36%)**..... 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
CIG Resources Company................................................. Delaware
Johnstown Cogeneration Company, LLC (50%)**................... Colorado
Keyes Helium Company, LLC (51%)............................... Colorado
CIG-Canyon Compression Company................................................ Delaware
CIG Gas Supply Company........................................................ Delaware
Wyoming Interstate Company, Ltd....................................... Colorado*
CIG Overthrust, Inc........................................................... Delaware
CIG Trailblazer Gas Company................................................... Delaware
Colorado Interstate Gas Company............................................... Delaware
CIG Exploration, Inc.................................................. Delaware
CIG Field Services Company............................................ Delaware
Great Divide Gas Services, LLC (73%)**........................ Colorado
Colorado Water Supply Company......................................... Delaware
Colorado Interstate Production Company........................ Delaware
Great Lakes Gas Transmission Company (50%)**.................................. Delaware
Wyoming Gas Supply, Inc....................................................... Delaware
Coastal Oil Chelsea, Inc.............................................................. Texas
Coastal Oil & Gas Corporation......................................................... Delaware
COGC Resale Company........................................................... Delaware
Coastal Australia AC 96-3 Ltd................................................. Cayman Islands
</TABLE>
3
<PAGE>
SUBSIDIARIES OF THE COASTAL CORPORATION
<TABLE>
<CAPTION>
State or Other Jurisdiction of
Incorporation or Organization
------------------------------
<S> <C>
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
Coastal China Ltd............................................................. Cayman Islands
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 Development III Ltd................................................... Cayman Islands
Coastal Development IV Ltd.................................................... Cayman Islands
CoastalDril, Inc.............................................................. Delaware
Coastal Javelina, Inc......................................................... Delaware
Coastal Indonesia Bangko Ltd.................................................. Cayman Islands
Coastal Indonesia Sampang Ltd................................................. Cayman Islands
Coastal Hungary Ltd........................................................... Hungary
Coastal Oil & Gas Holdings, Inc............................................... 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 (50%)**.................. 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 Power Nicaragua 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 Colorado, LLC (51%)............................................. Delaware
Coastal Power Distribution Ltd................................................ Cayman Islands
</TABLE>
4
<PAGE>
SUBSIDIARIES OF THE COASTAL CORPORATION
<TABLE>
<CAPTION>
State or Other Jurisdiction of
Incorporation or Organization
------------------------------
<S> <C>
Coastal Power Dominicana Generation Ltd....................................... Cayman Islands
Coastal Power Guatemala Ltd................................................... Cayman Islands
San Jose Power Holding Company, Ltd. (46%)**.......................... 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 Ltd...................................................... Cayman Islands
Khulna Power Company Ltd. (73.9%)**................................... Bangladesh
Coastal Power Lanka Ltd....................................................... Cayman Islands
Coastal Power Noapara Ltd.....................................................
Cayman Islands
Coastal Power Panama Generation Ltd........................................... Cayman Islands
Coastal Power Panama Investor, S.A.................................... 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
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
Coastal States Management Corporation................................................. Colorado
ABCO Aviation, Inc............................................................ Delaware
ABCO Leasing, Inc............................................................. Delaware
ANR Media Company............................................................. Michigan
</TABLE>
5
<PAGE>
SUBSIDIARIES OF THE COASTAL CORPORATION
<TABLE>
<CAPTION>
State or Other Jurisdiction of
Incorporation or Organization
------------------------------
<S> <C>
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
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 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
Cosbel Petroleum Corporation.......................................................... Delaware
Coastal Canada Petroleum, Inc................................................. New Brunswick, 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 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
Coastal Coker Corporation Aruba N.V........................................... Aruba
Coastal India Petroleum Ltd................................................... Cayman Islands
Coastal Securities Company Limited............................................ Bermuda
Coastal Aruba Holding Company N.V..................................... 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
Subic Bay Distribution, Inc. (50%)**.......................... Philippines
Subic Bay Energy Company Ltd. (50%)**......................... Cayman Islands
Subic Bay Fuels Company, Inc. (50%)**......................... Philippines
</TABLE>
6
<PAGE>
SUBSIDIARIES OF THE COASTAL CORPORATION
<TABLE>
<CAPTION>
State or Other Jurisdiction of
Incorporation or Organization
------------------------------
<S> <C>
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 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
Golden Carriers Corporation................................................... Liberia
Texas Tank Ship Agency, Inc................................................... Delaware
<FN>
The above subsidiaries, with the exception of those indicated with a double
asterisk (**) are included in the Consolidated Financial Statements of The
Coastal Corporation. Great Lakes Gas Transmission Company has a 28.06% limited
partnership interest in Great Lakes Gas Transmission Limited Partnership. 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
</FN>
</TABLE>
7
Exhibit 23
CONSENT OF DELOITTE & TOUCHE LLP
We consent to the incorporation by reference in Registration Statements No.
33-21095, 33-40263, 33-53952, 33-5214, 2-97766, 33-5218, 33-42696 and 333-70285
of The Coastal Corporation on Forms S-8 and Registration Statements No.
33-48435, 333-10995, 333-44527, 333-50075 and 333-58981 of The Coastal
Corporation on Forms S-3 of our report dated February 4, 1999, appearing in this
Annual Report on Form 10-K of The Coastal Corporation for the year ended
December 31, 1998.
DELOITTE & TOUCHE LLP
Houston, Texas
March 24, 1999
<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, 1998 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-31-1998
<PERIOD-END> DEC-31-1998
<CASH> 107
<SECURITIES> 0
<RECEIVABLES> 1,143
<ALLOWANCES> 0
<INVENTORY> 500
<CURRENT-ASSETS> 1,970
<PP&E> 11,731
<DEPRECIATION> 3,707
<TOTAL-ASSETS> 12,304
<CURRENT-LIABILITIES> 2,007
<BONDS> 3,999
<COMMON> 72
400
0
<OTHER-SE> 3,404
<TOTAL-LIABILITY-AND-EQUITY> 12,304
<SALES> 7,368
<TOTAL-REVENUES> 7,440
<CGS> 4,377
<TOTAL-COSTS> 6,495
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 295
<INCOME-PRETAX> 650
<INCOME-TAX> 167
<INCOME-CONTINUING> 483
<DISCONTINUED> (39)
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 444
<EPS-PRIMARY> 2.06
<EPS-DILUTED> 2.03
</TABLE>
