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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, 1997 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
------------------- -----------------------
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)
$2.125 Cumulative Preferred Stock, Series H
($.33 1/3 par value)
10-1/4% Senior Debentures 8-3/4% Senior Notes New York Stock Exchange
10-3/8% Senior Notes 9-5/8% Senior Debentures
10-3/4% Senior Debentures 8-1/8% Senior Notes
10% Senior Notes 7-3/4% Senior Debentures
9-3/4% Senior Debentures 7.42% Senior Debentures
6.70% 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 11, 1998, there were outstanding 105,779,387 shares of common
stock, 364,284 shares of Class A common stock, 57,537 shares of $1.19 Cumulative
Convertible Preferred Stock, Series A, 66,744 shares of $1.83 Cumulative
Convertible Preferred Stock, Series B, 29,204 shares of $5.00 Cumulative
Convertible Preferred Stock, Series C and 8,000,000 shares of $2.125 Cumulative
Preferred Stock Series H, of the Registrant. The aggregate market value on such
date of the voting stock of the Registrant held by non-affiliates was an
estimated $5.98 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 1998 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.......................................... 3
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...... 6
Unregulated Gas Operations............................ 6
Regulations Affecting Gas Systems..................... 6
Refining, Marketing and Distribution, and Chemicals....... 9
Exploration and Production................................ 12
Coal...................................................... 17
Power..................................................... 18
Other Operations.......................................... 20
Competition............................................... 20
Environmental............................................. 20
2. Properties.................................................... 22
3. Legal Proceedings............................................. 22
4. Submission of Matters to a Vote of Security Holders........... 23
PART II
5. Market for the Registrant's Common Equity and Related
Stockholder Matters .................................... 24
6. Selected Financial Data....................................... 25
7. Management's Discussion and Analysis of Financial Condition
and Results of Operations............................... 25
7A. Quantitative and Qualitative Disclosures About Market Risk.... 25
8. Financial Statements and Supplementary Data................... 25
9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure................................ 25
PART III
10. Directors and Executive Officers of the Registrant............ 26
11. Executive Compensation........................................ 27
12. Security Ownership of Certain Beneficial Owners and
Management.............................................. 27
13. Certain Relationships and Related Transactions................ 27
PART IV
14. Exhibits, Financial Statement Schedules, and Reports on
Form 8-K................................................ 28
(i)
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 reflecting the
Company's expectations and objectives in the near future; however, many factors
which may affect the actual results, including commodity prices, market and
economic conditions, industry competition and changing regulations, are
difficult to predict. Accordingly, there is no assurance that the Company's
expectations and objectives will be realized.
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)
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 13,200 persons as
of December 31, 1997.
Annual Reports on Form 10-K for the year ended December 31, 1997 are also
filed by Coastal's subsidiaries, ANR Pipeline and Colorado. Such reports contain
additional details concerning the reporting organizations.
The operating revenues and operating profit of the Company by industry
segment for the years ended December 31, 1997, 1996 and 1995, and the related
identifiable assets as of December 31, 1997, 1996 and 1995, are 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 and U-T Offshore System, general
partnerships composed of ANR Pipeline subsidiaries and subsidiaries of other
companies. 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 increasingly to the Northeast from (a)
the Hugoton Field and other fields in the Anadarko Basin in Texas and Oklahoma,
(b) the Louisiana onshore and 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, 1997
consisted of 10,611 miles of pipeline and 75 compressor stations with 1,030,069
installed horsepower. At December 31, 1997, 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 throughout the production areas adjacent to its
transmission system. Most of Colorado's gathering facilities connect
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directly to its transmission system, but some gathering systems are connected to
other pipelines. Colorado also has minor gathering facilities located in New
Mexico. 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, 1997 consisted of 4,160 miles of pipeline and 59
compressor stations with approximately 302,000 installed horsepower. At December
31, 1997, the design peak day gas delivery capacity of the transmission system
was approximately 2.0 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 2,327 miles of gathering lines and
approximately 50,700 horsepower of compression. Colorado owned and operated five
gas processing plants in 1997. 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.
The Company has formed certain subsidiaries to conduct its unregulated
natural gas business. Additional information is set forth in "Unregulated Gas
Operations," presented below.
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 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 in the
transportation and storage of natural gas. ANR Pipeline also faces competition
in the Northeast markets from other interstate pipelines in serving 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.
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ANR PIPELINE
Transportation Services
ANR Pipeline offers an array of "unbundled" transportation, storage and
balancing service options under Order 636. Additional information concerning
Order 636, including transportation and storage, is set forth in "Regulations
Affecting Gas Systems" and "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 and exchange
arrangements with other companies, including distributors, intrastate and
interstate pipelines, producers, brokers, marketers and end users.
Transportation service revenues amounted to $497 million for 1997 compared to
$510 million for 1996 and $572 million for 1995. During 1997, approximately 28%
of ANR Pipeline's transportation service revenues were from its three largest
customers: Wisconsin Gas Company, Wisconsin Electric Power Company Inc. and
Michigan Consolidated Gas Company. Wisconsin Gas Company serves the Milwaukee
metropolitan area and numerous other communities in Wisconsin. Wisconsin
Electric Power Company Inc. serves the cities of Racine, Kenosha, Appleton and
their surrounding areas in Wisconsin. Michigan Consolidated Gas Company serves
the city of Detroit and certain surrounding areas, the cities of Grand Rapids
and Muskegon, the communities of Ann Arbor and Ypsilanti and numerous other
communities in Michigan. In 1997, ANR Pipeline provided approximately 70% and
30% of the total gas requirements of Wisconsin and Michigan, respectively.
ANR Pipeline's system deliveries for the years 1997, 1996 and 1995 were as
follows:
Total System Daily Average
Year Deliveries System Deliveries
---- ---------- -----------------
(Bcf) (MMcf)
1997 1,424 3,901
1996 1,517 4,145
1995 1,404 3,847
Gas Storage
ANR Pipeline has approximately 208 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 133 Bcf is
available from seven owned and eight 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 $146 million for 1997 as compared to $131 million for both 1996 and
1995.
COLORADO
Gas Sales, Storage and Transportation
Colorado's unincorporated Merchant Division conducts most of Colorado's
sales activity. The gas sales volumes reported include those sales which
continue to be made by Colorado together with those of its Merchant Division.
Additionally, Colorado has engaged 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. When fully
developed in the 1998-99 heating season, the field will have 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.
3
Colorado's deliveries for the years 1997, 1996 and 1995 were as follows:
Total System Daily Average
Year Deliveries System Deliveries
---- ---------- -----------------
(Bcf) (MMcf)
1997 486 1,333
1996 475 1,298
1995 456 1,248
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 two regulated
processing facilities. The gathering that Colorado provides in the Panhandle
Field continues to be regulated by the FERC, and Colorado is limited to charging
rates between minimum and maximum levels approved by the FERC. The gathering
(and processing) that Colorado's subsidiary, CIG Field Services Company,
provides is not regulated by the FERC.
The gas processing plants recovered approximately 55 million gallons of
liquid hydrocarbons in 1997 compared to 66 million gallons in 1996, and 81
million gallons in 1995, as well as 500 long tons of sulfur in 1997, compared
to` 3,100 long tons in 1996 and 4,600 long tons in 1995. Additionally, Colorado
processed approximately 24 million gallons of liquid hydrocarbons owned by
others in 1997 compared to approximately 6 million gallons in both 1996 and
1995.
Colorado operates two helium processing facilities, one located in eastern
Colorado and the other in the western Oklahoma panhandle area. These helium
facilities are joint venture/partnership arrangements which are partially owned
by affiliates of Colorado. Colorado also operates two gas processing plants for
affiliates.
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.
GAS SYSTEM RESERVES
ANR Pipeline
With the termination of its merchant service, ANR Pipeline no longer
reports on gas system reserves and, therefore, this report has been replaced by
a general discussion set forth in "Producing Area Deliverability," presented
below.
Producing Area Deliverability
Shippers on ANR Pipeline have direct access to the two most prolific gas
producing areas in the United States, the Gulf Coast and Midcontinent.
Statistics published by the Energy Information Agency, Office of Oil and Gas,
U.S. Department of Energy, indicate that approximately 80% 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
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approximately 14% 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 interconnections with Great Lakes and Viking Gas
Transmission Company.
Gas deliverability available to shippers on ANR Pipeline's system from the
Midcontinent and Gulf Coast producing areas through direct connections and
interconnecting pipelines and gatherers is approximately 4,200 MMcf per day. An
additional 203 MMcf per day of deliverability is accessible to shippers on ANR
Pipeline-owned or partially owned pipeline segments not directly connected to an
ANR Pipeline mainline.
ANR Pipeline remains active in locating and connecting new sources of
natural gas to facilitate transportation arrangements made by third-party
shippers. During 1997, field development, newly connected gas wells, gas
production facilities and pipeline interconnections contributed over 1,400 MMcf
per day to total deliverability accessible to shippers on ANR Pipeline's
pipeline system.
Colorado
Colorado has reported in its Form 10-K for the year ended December 31,
1997, its gas system reserves based on information prepared by Huddleston, the
Company's independent engineers. 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"), formerly Mesa Operating Company, 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
In September 1997, Coastal acquired both an 11% equity and capacity
position in the corporations and partnerships comprising the Alliance Pipeline
project ("Alliance"), and subsequently increased its equity participation to
14.4% in February, 1998. Alliance is expected to connect major Canadian natural
reserves in Alberta and British Columbia via a $3.0 billion (US), 1,900 mile
large diameter high pressure pipeline to Chicago, Illinois. The project has been
fully subscribed for the firm capacity of 1.325 Bcf per day under 15 year
contracts. The Alliance partnerships are currently in the process of securing
all necessary environmental permits and regulatory approvals from the National
Energy Board and the FERC. With timely approvals, the project is estimated to be
placed in service as early as the year 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. It currently
has a throughput capacity of approximately 700 MMcf of gas daily. 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 in 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 demand volumes totaling 685 MMcf daily. In 1997, the WIC line
transported an average of 546 MMcf daily, compared to 486 MMcf daily and 455
MMcf daily in 1996 and 1995, respectively. In 1997, WIC completed an expansion
project which increased its capacity by 40% to approximately 700 MMcf per day.
In December 1997, WIC filed with the FERC to undertake further expansion of
facilities which will result in an increase of WIC's capacity to approximately
750 MMcf. The announced expansion will be accomplished by adding 7,380
horsepower of compression at WIC's Laramie and Cheyenne, Wyoming compressor
stations, which, in turn, will create additional capacity of 52 MMcf per day on
the Powder River Basin Lateral owned and operated by Colorado. The
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in-service date for WIC's proposed expansion, subject to receipt of regulatory
approvals, is expected to be November 1998.
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
Coastal and TransCanada, a non-affiliated company, each own 50% of Great
Lakes which owns a 2,000-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 921 Bcf in 1997 as compared to
933 Bcf in 1996 and 953 Bcf in 1995. Great Lakes has long-term contract
commitments to transport a total of 1.4 Bcf per day for TransCanada and
affiliates. It also transports up to 800 MMcf per day primarily for United
States markets, including 150 MMcf per day to Coastal affiliates. Great Lakes
exchanges gas with ANR Pipeline by delivering gas in the upper peninsula of
Michigan and receiving an equal amount of gas in the lower peninsula of
Michigan.
UNREGULATED GAS OPERATIONS
Coastal, primarily through two subsidiaries, Coastal Field Services
Company ("CFSC") and Coastal Gas International Company ("CGI"), operates the
Company's unregulated natural gas business, including certain of Coastal's
natural gas gathering and processing, gas supply and marketing activities.
CFSC owns or operates for various affiliates domestic gathering and
processing assets in Alabama, Colorado, Kansas, Louisiana, New Mexico, Oklahoma,
Texas, Utah and Wyoming. CFSC gathered approximately 1 Bcf per day of gas in
both 1997 and 1996. CFSC and its affiliates have an ownership interest in 10 gas
processing plants, 7 of which are operated by CFSC. CFSC's equity share of
liquid hydrocarbons production was more than 25,000 barrels per day in 1997
compared with almost 23,000 barrels per day in 1996.
In December of 1997, Coastal Dauphin Island Company, L.L.C., an affiliate
of CFSC, exercised its option to acquire an approximate 13.6% interest in a 600
MMcf per day cryogenic gas processing plant and an associated 40 megawatt power
generation plant, both to be constructed in Mobile County, Alabama.
CGI conducts the international unregulated natural gas operations of the
Company. Coastal Gas Pipelines Victoria Pty Ltd., an affiliate of CGI, is
constructing a 104 mile transmission pipeline in Victoria, Australia.
Construction began in late 1997 and is scheduled to be completed in 1998. CGI
and its affiliates are pursuing additional gas projects in Australia and various
other parts of the world.
In February 1997, Coastal and Westcoast Energy Inc. ("Westcoast") jointly
formed one of North America's largest marketers of natural gas and electricity
through the combination of the two companies' related marketing and services
businesses. The combination created new entities, Engage Energy US, L.P. in the
United States and Engage Energy Canada, L.P. in Canada, in which Coastal and
Westcoast each indirectly own 50%.
REGULATIONS AFFECTING GAS SYSTEMS
General
Under the NGA, the FERC has jurisdiction over ANR Pipeline, Colorado, WIC,
ANR Storage and Great Lakes as to sales, transportation, storage, balancing of
gas, rates and charges, construction of new facilities, 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.
6
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.
On July 31, 1996, the FERC also issued a "Notice of Proposed Rulemaking"
requesting comments on various aspects of secondary market transactions on
interstate natural gas pipelines, including the comparability of pipeline
capacity with released capacity. The matter is pending review, following rounds
of extensive public comments.
In late 1997, the FERC initiated a public conference in order to solicit
comments from interested parties addressing the financial health of the pipeline
industry in the new competitive environment created by Order 636. Among other
things, the FERC is reviewing its current policies for setting the rates of
return on pipeline investment for possible improvements.
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" (the "Policy") with respect to a pipeline's ability to negotiate
and charge rates for individual customers' services which would not be limited
to the "cost-based" rates established by the FERC in traditional rate making.
Under this Policy, a pipeline and a customer will be allowed to negotiate a
contract which provides for rates and charges that exceed the pipeline's posted
maximum tariff rates, provided that the shipper 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"). 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. Colorado has made such filing and the
FERC has accepted that tariff filing. Under this Policy, 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. Some parties have sought judicial review of the
FERC's acceptance of Colorado's tariff filing to implement negotiated rates, but
Colorado's tariff sheet remains in effect pending review. Colorado has filed for
judicial review of FERC's holding that pipelines which have entered into
"negotiated rate" contracts will not be allowed discount adjustments in
connection with such contracts. The FERC is also considering comments on whether
this "negotiated rate" program should be extended to other terms and conditions
of pipeline transportation services.
In July 1996, the United States Court of Appeals for the D.C. Circuit
upheld the basic structure of the FERC's Order 636 (issued in April 1992), but
remanded to the FERC, for further consideration, certain limited aspects of the
Order. In its order responding to the remand (Order 636-C, issued February 27,
1997) the FERC: (1) reaffirmed the right of pipelines to recover 100% of their
prudently incurred transition costs, but required pipelines to file within 180
days a proposal for the level of costs to be allocated to interruptible
transportation customers; and (2) reduced from 20 years to five years, the term
"cap" to be applied to evaluation of bids for renewal of contracts on existing
volumes. ANR Pipeline and Colorado have sought rehearing and clarification of
these holdings as they relate to past and future periods, and have also made the
appropriate compliance filings with the FERC. ANR Pipeline's proposal to retain
its current transition cost allocation level to interruptible service was
accepted by the FERC as part of an uncontested settlement following further
proceedings before the FERC.
ANR Pipeline. From November 1, 1992 to November 1, 1993, gas inventory
demand charges were collected from ANR Pipeline's former resale customers. This
method of gas cost recovery required refunds for any over-collections. In April
1994, ANR Pipeline filed with the FERC a refund report showing over-collections
and proposing refunds totaling $45.1 million. Certain customers disputed the
level of those refunds. The FERC approved ANR Pipeline's refund allocation
methodology and ANR Pipeline, in March 1995, paid undisputed refunds of $45.1
million, together with applicable interest, subject to further investigation of
customers' claims. The FERC's approval of ANR Pipeline's refund allocation
methodology was upheld by the United States Court of Appeals for the D.C.
Circuit in April 1996. Disputed issues related to the refunds are the subject of
further proceedings before the FERC. In March 1997, an Initial Decision
7
was issued, which adopted most of ANR Pipeline's positions. On March 12, 1998,
the FERC affirmed the Initial Decision in almost all aspects. Parties may seek
rehearing in 30 days.
ANR Pipeline filed a general rate increase on November 1, 1993. Issues
related to the general rate increase are the subject of continuing FERC and
judicial proceedings. Under a March 1994 order, certain costs were reduced or
eliminated, resulting in revised rates that reflect a $182.8 million increase
over the cost of service underlying ANR Pipeline's approved rates for its Order
636 restructured services. In September 1994, the FERC accepted ANR Pipeline's
filing to place the new rates into effect May 1, 1994, subject to further
modifications. ANR Pipeline submitted revised rates in compliance with this
order in October 1994. In January 1997, an Initial Decision was issued on the
issues set for hearing by the March 1994 order. That Initial Decision, which
accepted some but not all of ANR Pipeline's rate change proposals, does not take
effect until reviewed by the FERC. ANR Pipeline and other parties have filed
exceptions regarding some of the findings in the Initial Decision. On October
17, 1997, ANR Pipeline filed a comprehensive settlement that will resolve all
issues in the proceeding, as well as result in the voluntary dismissal of
pending court appeals. Under the settlement, ANR Pipeline agreed to place the
settlement rates in effect on November 1, 1997, subject to the prospective
restoration of ANR Pipeline's currently filed rates (subject to refund) if the
settlement is not approved. By order issued October 31, 1997, the FERC
authorized ANR Pipeline to proceed on that basis. The settlement includes
provisions for lower rates, refunds, procedures to resolve certain reserved
matters, as well as a proposal for a new short-term firm service that will
enable ANR Pipeline to charge higher rates for shippers electing to purchase
such service. The settlement is either supported by or not opposed by all active
parties in the proceeding. By order issued February 13, 1998, the FERC approved
the settlement in all respects, other than the proposed new short-term firm
service. The FERC also addressed two of the three reserved matters that the
parties had requested it decide on the merits. On March 16, 1998, ANR Pipeline
filed written notification with the FERC that the order on the settlement was
acceptable to ANR Pipeline and all parties, and the settlement became effective
as of such date. The approved settlement includes a stipulation that ANR
Pipeline will refund $66.6 million, which includes interest, for rates collected
during the period its proposed rates were in effect. Pursuant to the settlement,
all refunds must be remitted within thirty days of the effective date. During
the period the proposed rates were in effect, ANR Pipeline estimated and
recorded provisions for potential rate refunds, which exceed the final refund
requirements.
The FERC has also issued a series of orders in ANR Pipeline's rate
proceeding that apply a new policy governing the order of attribution of
revenues received by ANR Pipeline related to transition costs under Order 636.
Under that new policy, ANR Pipeline is required to first attribute the revenues
it receives for its services to the recovery of its transition costs under Order
636 rather than to the recovery of its base cost of service. The FERC's change
in its revenue attribution policy has the effect of understating ANR Pipeline's
currently effective maximum rates and accelerating its amortization of
transition costs for regulatory accounting purposes. In light of the FERC's
policy, ANR Pipeline filed with the FERC to increase its discount recovery
adjustment in its rate proceeding. ANR Pipeline also sought judicial review of
these orders before the United States Court of Appeals for the D.C. Circuit,
which appeals were dismissed as premature in light of the pending general rate
increase proceeding discussed above. As a result of the rate case settlement
described above, ANR Pipeline can no longer pursue such judicial review of the
specific orders involved.
In May 1997, certain of ANR Pipeline's customers filed a motion with the
FERC for immediate refund of approximately $77 million, which is related to ANR
Pipeline's settlement with Dakota Gasification Company. ANR Pipeline responded
to the FERC, demonstrating that the customers' claim is grossly overstated by
identifying the appropriate amounts to be refunded to its customers. On June 30,
1997, ANR Pipeline paid such refunds (totaling $21.1 million) to its customers.
On December 2, 1997, the FERC issued an order rejecting the customers' claims,
and found that ANR Pipeline had properly calculated the level of refunds due to
the customers. The FERC's decision on this matter is now final because the
customers did not seek rehearing.
Colorado. On March 29, 1996, Colorado filed with the FERC under Docket No.
RP96-190 to increase its rates by approximately $30 million annually, to realign
certain transportation services and to add tariff language that would allow
Colorado to enter into "negotiated rates" (rates which could exceed Colorado's
"cost-based" rates) in certain circumstances, subject to FERC policies. On April
25, 1996, the FERC accepted the rate change filing and the transportation
service realignment to become effective October 1, 1996, subject to refund, and
also accepted the "negotiated rate" tariff provision to become effective May 1,
1996. Certain parties sought judicial review of the acceptance of the
"negotiated rate" tariff provisions. On October 16, 1997, the FERC approved an
unopposed settlement filed by Colorado that resolves all issues in this general
rate case except the issues that are on appeal relating to the
8
"negotiated rate" tariff provisions. The final settlement modifies the services
provided by Colorado, and the charges for those services. The final settlement
became effective on November 17, 1997, and is no longer subject to review by the
FERC or subject to any judicial review. Colorado has now made refunds of amounts
collected which were in excess of the final settlement rates. The appeal of the
"negotiated rate" provision has been consolidated with other appeals involving
the same issues, and is being held in abeyance by the United States Court of
Appeals for the D. C. Circuit. Pending completion of judicial review, the
"negotiated rate" tariff provisions are fully effective, although during 1997
Colorado did not enter into any "negotiated rate" transactions.
WIC. On May 30, 1997, WIC filed at the FERC to increase its rates by
approximately $5.7 million annually. On June 27, 1997, the FERC accepted the
filing to become effective December 1, 1997, subject to refund. In the event the
case cannot be settled, a hearing before a FERC Administrative Law Judge is
currently scheduled for May 5, 1998.
Certain of the above regulatory matters and other regulatory issues remain
unresolved among Colorado, ANR Pipeline, ANR Storage and WIC, subsidiaries of
the Company, 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.
Refining
Subsidiaries of the Company operated their refineries at 89% of average
combined capacity in 1997 compared to 97% in 1996 and at 88% in 1995. The
aggregate sales volumes (millions of barrels) of Coastal's wholly owned
refineries for the three years ended December 31, 1997 were 160.7 (1997), 160.4
(1996) and 142.3 (1995). Of the total refinery sales in 1997, 27% was gasoline,
48% was middle distillates, such as jet fuel, diesel fuel and home heating oil,
and 25% was heavy industrial fuels and other products.
At December 31, 1997, average daily throughput and storage capacity at the
Company's wholly owned refineries are set forth below:
Refinery Location Average Daily
- -------- -------- Daily Throughput (Barrels) Storage
Capacity -------------------------- Capacity
(Barrels) 1997 1996 (Barrels)
--------- ----------- ----------- ---------
Aruba Aruba 210,000 180,600 188,200 15,300,000
Corpus Christi Corpus Christi, Texas 100,000 87,100 91,300 7,100,000
Eagle Point Westville, New Jersey 140,000 133,400 133,600 10,700,000
Mobile Mobile, Alabama 18,000 12,900 14,000 600,000
------- ------- ------- ----------
Total 468,000 414,000 427,100 33,700,000
In 1997, the Company sold its idled Hercules, California refinery.
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.
9
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 1997, the products emphasized included premium gasolines and
products for specialty markets such as petrochemical feedstocks, aviation fuels
and asphalt.
In October 1997, the Company entered into a memorandum of understanding
with Maraven S.A., a subsidiary of Venezuela's state-owned oil company,
Petroleos de Venezuela S.A., to form a joint venture to produce, refine and
market extra heavy crude from the Zuata region of Venezuela's Orinoco belt. The
joint venture would install a facility for upgrading the extra heavy crude to
synthetic crude (syncrude) in Venezuela. After conversion, the syncrude would be
shipped to Coastal's refinery in Corpus Christi. It is anticipated that such
joint venture, which must be approved by the Venezuelan Congress as well as
Coastal, would acquire the Corpus Christi facility from Coastal.
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 with a production capacity of 4,200 barrels per day. MTBE is a
gasoline additive which adds oxygen and boosts octane of the blended mixture.
Coastal's St. Helens chemical plant, located in St. Helens, Oregon, has
the capacity to produce 300 tons per day of anhydrous ammonia, 370 tons per day
of urea and 185 tons per day of urea/ammonium nitrate solutions. Approximately
55% of the plant's production is sold as industrial products and 45% as
agricultural products.
Sales volumes for the three years ended December 31, 1997, are set forth
below (thousands of tons):
1997 1996 1995
-------- -------- --------
Agricultural Sales................................................... 340 276 242
Industrial Sales..................................................... 566 608 445
MTBE................................................................. 223 204 203
----- ----- -----
Total .......................................................... 1,129 1,088 890
===== ===== =====
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. Reduced rail
rates on long hauls has encouraged competition from Canadian and eastern U.S.
producers.
The Company's petrochemical facility in Montreal East, Quebec, Canada, has
the capacity to produce 330,000 tons per year of paraxylene, a component used in
the manufacturing of polyester fibers and containers. The Montreal East plant
holds a competitive position due to the size of the facility, the Company's low
initial investment, long-term contracts, and a readily available feedstock base
provided by the Company's New Jersey refinery. Production (tons) shipped and
sold from the plant for the three years ended December 31, 1997 was 338,400
(1997), 289,100 (1996) and 246,200 (1995).
The Company's 650 tons per day anhydrous ammonia facility located in
Oyster Creek, Texas began operation in the first quarter of 1998. This plant is
located adjacent to and will supply a number of major chemical facilities.
10
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, 1997, are set forth
below (thousands of barrels):
Type of Sale 1997 1996 1995
- ------------ -------- --------- ---------
Company Produced Refined Products........................................ 160,703 160,383 142,301
Refined Products Purchased from Others................................... 101,495 130,240 143,913
Natural Gas Liquids...................................................... 16,593 16,205 14,551
------- ------- -------
Total............................... 278,791 306,828 300,765
======= ======= =======
Subsidiaries of the Company market refined products and liquefied
petroleum gas at wholesale in 36 states plus Canada and Panama through 272
terminals. Coastal Refining & Marketing, Inc. serves customers primarily in the
Midwest, Mississippi Valley and the Southwest through 216 product and liquefied
petroleum gas terminals in 25 states. On the Gulf and East Coasts, Coastal Fuels
Marketing, Inc., Coastal Oil New York, Inc. and Coastal Oil New England, Inc.
serve home, industry, utility, defense and marine energy needs. In 1997, these
subsidiaries' sales volumes were 71.4 million barrels, which accounted for
approximately 26% 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, Bermuda, London and Singapore.
During 1997, the Company continued selling, exchanging or disposing of
marketing operations that cannot be integrated with core refining assets. In
1997, Coastal improved its wholesale and retail marketing by concentrating more
on the products made at its core refineries. Additionally, in 1997, the Company
sold its Revere, Massachusetts terminal and associated business as well as the
Company's marketing operations based in Flushing, New York.
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 totalling 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. During 1997,
the petroleum products pipeline between the Subic Bay Freeport Zone and the
Clark Special Economic Zone (formerly Clark Air Force Base) has been
rehabilitated, by a joint venture between a Coastal subsidiary and the Petroleum
Authority of Thailand, along with a petroleum storage facility in the Clark
Special Economic Zone. Both facilities will be used to support the joint
venture's marketing activities in the Philippines.
Coastal Baltica Holding Company Ltd., a joint venture in which a Coastal
subsidiary is a 50% partner, commenced operations at its terminal and new port
facilities near Tallinn, Estonia on the Baltic Sea in 1996. The terminal
operation imports and exports almost 2.5 million metric tons (16 million
barrels) of petroleum products annually, 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 36 states and Aruba through approximately 1,731 Coastal branded
outlets, with 511 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 12 foreign countries.
Transportation. The Company's transportation facilities include petroleum
liquids pipelines, tank cars, tankers, tank trucks and barges. Coastal operates
approximately 1,700 miles of pipeline for gathering and transporting an average
of 229,321 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 and in which the Company has a 35%
ownership interest. Coastal has a 50% ownership in
11
13 miles of refined products pipelines located in New Jersey and New York and
has a 33.3% interest in an additional 80 miles of refined products pipelines in
New Jersey. In 1997, throughput of crude oil pipelines averaged 13,117 barrels
per day, compared to 14,323 barrels per day in 1996. In 1997, throughput of
refined products and natural gas liquid pipelines averaged 216,204 barrels per
day, compared to 215,897 barrels per day in 1996.
The marine transportation fleet at December 31, 1997 consisted of 15 tug
boats, 19 oil barges, 4 owned tankers and 12 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 Alabama, Arkansas, California,
Colorado, Kansas, Louisiana, Michigan, Mississippi, Missouri, 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 Australia, Colombia, Hungary, Indonesia and Peru.
In 1997, the Company's domestic exploration and production operations sold
approximately 46% of all the gas it produced to certain of Coastal's wholly
owned natural gas system subsidiaries. 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.
12
Acreage held under gas and oil mineral leases as of December 31, 1997 is
summarized as follows:
Undeveloped Developed
---------------- ----------------
Area Gross Net Gross Net
------------------------------------------------------------ ----- ----- ----- -----
(Thousands of Acres)
Exploration and Production
--------------------------
United States (Domestic)
Onshore.......................................... 494 352 870 376
Offshore......................................... 283 148 243 148
--------- -------- --------- ---------
Total Domestic................................... 777 500 1,113 524
--------- -------- --------- ---------
International
Australia........................................ 730 328 - -
Colombia......................................... 104 52 - -
Hungary.......................................... 568 568 - -
Indonesia........................................ 950 237 - -
Peru............................................. 2,974 1,487 - -
--------- -------- --------- ---------
Total International.............................. 5,326 2,672 - -
--------- -------- --------- ---------
Total Exploration and Production................. 6,103 3,172 1,113 524
--------- -------- --------- ---------
Natural Gas Systems
-------------------
Domestic Onshore....................................... - - 264 261
--------- -------- --------- ---------
Total Acreage.......................................... 6,103 3,172 1,377 785
========= ======== ========= =========
The domestic net developed acreage is concentrated principally in Texas
(36%), Utah (26%), offshore Gulf of Mexico (19%), Kansas (6%) and Wyoming (6%).
Approximately 10%, 14% and 11% of the Company's total domestic net undeveloped
acreage is under leases that have minimum remaining primary terms expiring in
1998, 1999 and 2000, respectively.
Productive wells as of December 31, 1997 are as follows (domestic):
Type of Well Gross Net
--------------------------------------------------------------- --------- ---------
Exploration and Production
--------------------------
Oil....................................................... 1,167 727
Gas....................................................... 1,890 952
--------- ---------
Total Exploration and Production.......................... 3,057 1,679
--------- ---------
Natural Gas Systems
-------------------
Oil....................................................... 9 8
Gas....................................................... 717 713
--------- ---------
Total Natural Gas Systems................................. 726 721
--------- ---------
Total............................................... 3,783 2,400
========= =========
13
Exploration and Drilling
During 1997, Coastal's domestic subsidiaries participated in drilling 150
gross wells, 109.8 net wells, to the Company's interest. Coastal's participation
in wells drilled in the three years ended December 31, 1997, is summarized as
follows:
Exploration and Production 1997 1996 1995
-------------------------- ------------------- ------------------- --------------------
Exploratory Wells Gross Net Gross Net Gross Net
----------------- -------- -------- --------- -------- --------- ---------
Oil...................... - - - - 1 0.3
Gas...................... 8 3.3 7 2.3 6 2.5
Dry Holes................ 5 2.9 4 1.9 4 2.3
-------- -------- --------- -------- --------- ---------
13 6.2 11 4.2 11 5.1
======== ======== ========= ======== ========= =========
Development Wells
-----------------
Oil...................... 2 1.7 5 1.6 22 9.8
Gas...................... 128 96.7 80 56.8 59 25.6
Dry Holes................ 4 2.2 3 1.4 1 0.1
-------- -------- --------- -------- --------- ---------
134 100.6 88 59.8 82 35.5
======== ======== ========= ======== ========= =========
Natural Gas Systems
-------------------
Development Wells
-----------------
Oil...................... - - 2 2.0 - -
Gas...................... 3 3.0 8 8.0 1 1.0
Dry Holes................ - - - - - -
-------- -------- --------- -------- --------- ---------
3 3.0 10 10.0 1 1.0
======== ======== ========= ======== ========= =========
Total.......................... 150 109.8 109 74.0 94 41.6
======== ======== ========= ======== ========= =========
Wells in progress as of December 31, 1997 are as follows (domestic):
Type of Well Gross Net
-------------------------------------------------------- ------- -----
Exploration and Production
--------------------------
Exploratory.......................................... 3 1.7
Development.......................................... 24 19.7
------- -----
Total Exploration and Production..................... 27 21.4
------- -----
Natural Gas Systems
-------------------
Exploratory.......................................... - -
Development.......................................... - -
------- -----
Total Natural Gas Systems............................ - -
------- -----
Total................................................ 27 21.4
======= =====
At the end of 1997, Coastal held interests in 110 blocks and 49 platforms
in the Gulf of Mexico, with net natural gas production of 173 MMcf per day and
4,156 barrels per day of oil and condensate. The Company operates 36 of the
platforms.
14
In 1997, Coastal successfully completed 26 wells in the Jeffress Field in
Hidalgo County, 15 miles northeast of McAllen, Texas. These Jeffress wells
contributed to bringing net gas production in South Texas core areas to an
average of 221 MMcf per day in 1997 as compared to 162 MMcf per day for the
prior year, a 36% increase.
Coastal continued its international exploration program in 1997. Coastal
subsidiaries were awarded permits to explore two areas in the Timor Sea off the
northern coast of Australia, with Coastal having a 50% working interest in a
355,000 acre area and a 40% working interest in a 375,000 acre area. The Company
continues to participate in a joint venture to evaluate a block in South Central
Sumatra, Indonesia. Another Coastal subsidiary, holding a 40% working interest,
participated in a successful bid to explore for oil and gas in the Sampang block
in Indonesia. During the course of 1997, exploration activities in Peru, Hungary
and Colombia did not result in the discovery of commercial hydrocarbons. Further
exploration opportunities are being pursued in Peru and Hungary.
Gas and Oil Production
Natural gas production during 1997 averaged 540 MMcf daily, compared to
461 MMcf daily in 1996. Production from non-pipeline-owned wells averaged 436
MMcf daily in 1997, compared to 353 MMcf daily in 1996. Crude oil, condensate
and natural gas liquids production averaged 13,736 barrels daily in 1997,
compared to 13,893 barrels daily in 1996.
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, 1997:
Natural Gas
Oil Condensate Liquids
Gas (Thousands (Thousands (Thousands
Year (MMcf) of Barrels) of Barrels) of Barrels)
---- ------ ----------- ----------- -----------
Exploration and Production
--------------------------
1997 159,127 3,425 1,224 308
1996 129,149 3,885 853 324
1995 85,415 4,064 436 329
Natural Gas Systems
-------------------
1997 38,135 57 - -
1996 39,405 23 - -
1995 41,638 15 1 -
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.
15
The following table summarizes sales price and production cost information
for domestic exploration and production operations during the three years ended
December 31, 1997:
1997 1996 1995
-------- -------- --------
Average sales price:
Gas - per Mcf................................................. $ 2.40 $ 2.19 $ 1.57
Oil - per barrel.............................................. 18.01 20.28 17.43
Condensate - per barrel....................................... 18.37 20.76 16.63
Natural Gas Liquids - per barrel.............................. 28.41 21.74 15.02
Average production cost per unit (equivalent Mcf)................ 0.49 0.46 0.66
Natural Gas Processing
The Company's domestic subsidiaries in Exploration and Production and
Natural Gas Systems are also engaged in the processing of natural gas for the
extraction and sale of natural gas liquids. In 1997, these subsidiaries
extracted and sold 446 million gallons of ethane, propane, iso-butane, normal
butane and natural gasoline from natural gas processing plants. Sales prices of
natural gas liquids fluctuate widely as a result of market conditions and
changes in the prices of other fuels and chemical feedstocks.
Company-Owned Reserves
Coastal's domestic proved reserves of crude oil, condensate and natural
gas liquids at December 31, 1997, as estimated by Huddleston, its independent
engineers, were 40.1 million barrels, compared to 44.5 million barrels at the
end of 1996. Proved gas reserves as of December 31, 1997, net to Coastal's
interest, were estimated by the engineers to be 1,752.5 Bcf compared to 1,456.5
Bcf as of December 31, 1996. In 1997, reserve additions 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.
16
COAL
Through the operations of ANR Coal Company, LLC and its affiliates
(collectively "ANR 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, ANR 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 Corp. Information concerning a pending dispute related to the western
coal operations is set forth in Item 3 and Note 15 of the Notes to Consolidated
Financial Statements included herein.
At December 31, 1997, coal properties consisted of the following:
Coal Holdings (Acres)
---------------------------------------------------------- Clean,
Owned Leased Recoverable
------------------------------- Exchanged Total Tons
Fee Mineral Surface (Net) Acres (Millions)
------- ------- ------- --------- ----- -------------
Kentucky......................... 14,271 76,614 2,275 19,861 113,021 198
Virginia......................... 24,362 36,925 2,090 12,362 75,739 157
West Virginia.................... 334 56,028 6,966 90,663 153,991 185
-------- --------- -------- -------- -------- ------
Total...................... 38,967 169,567 11,331 122,886 342,751 540
======== ========= ======== ======== ======== ======
- ------------------------
Based on a 65% recovery rate.
At December 31, 1997, the Company controlled approximately 540 million
recoverable tons of bituminous coal reserves and resources. Production in 1997
from ANR Coal's reserves totaled 10.5 million tons, of which 6.2 million tons
were produced from captive operations and 4.3 million tons were produced by
lessees under royalty agreements. In its eastern captive operations, ANR 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 eight company mines operated by ANR
Coal in Virginia, Kentucky and West Virginia. Captive production and clean coal
processed from these mines totaled 2.0 million tons in 1997.
Captive sales by ANR Coal were 7.2 million tons in 1997. Brokerage sales
in which the Company receives a commission totaled 0.8 million tons for the same
period.
In 1997, approximately 72% of the captive sales were to domestic
utilities, 10% of the sales were to domestic industrial customers and 18% of the
sales were to export markets in Europe, Canada and South America. Additionally,
0.6 million tons of ANR Coal's production were sold to domestic and foreign
metallurgical markets. Of the total 1997 tonnage sold, 5.4 million tons (75%)
were sold under long-term contracts. At December 31, 1997, the weighted average
remaining life of these contracts was 37 months.
The Company had approximately 10.6 million tons of annual production
capacity at December 31, 1997 from five coal preparation plants and eight
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 435 million tons of lignite
reserves in North Dakota. Production from these reserves in 1997 totalled 13.0
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
17
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.
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 four domestic cogeneration projects and five
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 leases a cogeneration facility with a
capacity of approximately 47 megawatts, located in Fulton, New York. This
partnership is 100% owned by Coastal Power and another Coastal subsidiary.
Electricity from this project is sold to a New York utility under a long-term
contract. Thermal energy is sold to a local confections manufacturer adjacent to
the project, also under a long-term contract. Approximately one-half of the gas
supply requirements for the project are supplied by an affiliate of Coastal
Power. CTI is the operator of the cogeneration plant.
Coastal, through a wholly owned subsidiary, has a 10.9% equity interest in
the Midland Cogeneration Venture Limited Partnership, a 1,370 megawatt capacity
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.
Compania de Electricidad de Puerto Plata, S.A. ("CEPP") owns an
independent power project in Puerto Plata, Dominican Republic. Coastal Power
International Ltd. and other affiliates of Coastal Power together with two other
unrelated parties purchased 100% of the shares of CEPP in 1995. The project has
a total capacity of 66.5 megawatts of which 50 megawatts are barge mounted and
16.5 megawatts are land based. Coastal Power International Ltd. owns a 48.3%
equity interest in CEPP. An affiliate of Coastal Power is involved in arranging
the fuel for the project and another affiliate operates the project pursuant to
a contract with CEPP. The electrical energy is sold to the national electric
utility of the Dominican Republic under a long-term contract.
Coastal Nejapa Ltd. and other affiliates lease an independent power project
near Apopa, El Salvador. The heavy-fuel-oil plant has a capacity of
approximately 144 megawatts. Coastal Power, through its affiliates, currently
receives approximately 86.6% of the distributable cash flow and an unrelated
investor receives the remainder. Coastal affiliates
18
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 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.
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.
Coastal Gusu Heat & Power Ltd., an affiliate of Coastal Power, together
with a Chinese partner, 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. This project is under construction and
is expected to be operational in 1998.
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 of 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 capacity natural gas-fired power
plant 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 the end of 1998.
In early 1997, a subsidiary of Coastal Power completed negotiations to
build and operate a 125 megawatt capacity heavy-fuel oil project in Farouqabad,
Pakistan. The Coastal Power subsidiary will hold approximately 90% of the equity
interest in the project. The power from the project will be sold to a national
utility under a long-term contract, with operations expected to commence in
early 1999.
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 national utility under a long-term contract.
In late 1997, a subsidiary of Coastal Power won the bid to develop and
operate a 50 megawatt heavy fuel oil project in Tipitapa, Nicaragua. The Coastal
Power subsidiary is expected to own a 60% equity interest in the project, with
Nicaraguan partners expected to hold the remaining 40% interest. The power from
the project will be sold to the national utility company under a long-term
contract, with operations expected to commence in 1999.
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
19
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.
OTHER OPERATIONS
In November 1995, Advance Transportation Company ("Advance") merged into
the Company's trucking subsidiary, ANR Freight System, Inc. Under the terms of
the merger, the surviving company changed its name to ANR Advance Transportation
Company, Inc. and is owned by a holding company, ANR Advance Holdings, Inc.,
which is in turn owned 50% by a subsidiary of Coastal and 50% by certain former
owners of Advance.
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. The Company spent
approximately $23 million in 1997 on environmental capital projects and
anticipates capital expenditures of approximately $35 million in 1998 in order
to comply with such laws and regulations. The majority of the 1998 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 1999 through 2001 of $20 million to $40
million per year. Additionally, appropriate governmental authorities may enforce
the laws and regulations with a variety of civil and criminal enforcement
measures, including monetary penalties and remediation requirements.
The Comprehensive Environmental Response, Compensation and Liability Act,
also known as "Superfund," as reauthorized, imposes liability, without regard to
fault or the legality of the original act, for disposal of a "hazardous
substance." Certain subsidiaries of the Company and a company in which Coastal
owns a 50% interest have been named as a potentially responsible party ("PRP")
in several "Superfund" waste disposal sites. At the 16 sites for which there is
sufficient information, total clean-up costs are estimated to be approximately
$313 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 7 other sites, the Environmental Protection Agency ("EPA") is
currently unable to provide the Company with an estimate of total clean-up costs
and, accordingly, the Company is unable to calculate its share of those costs.
Finally at 10 other sites, the Company has paid amounts to other PRPs or to the
EPA as its proportional share of associated clean-up costs. As to these latter
sites, the Company believes that its activities were de minimis. 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 clean-up costs to be approximately $50
million, but the Company believes that the subsidiary's activities at this site
were de minimis. At the other 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.
20
On December 17, 1997, the California Regional Water Quality Control Board
issued an Administrative Compliance Order (the "Order") to Pacific Refining
Company ("Pacific"), a subsidiary of the Company, for approximately 28
violations of its Hercules Refinery's NPDES permit occurring between May 6, 1995
and September 10, 1997, when the refinery was sold to Hercules L.L.C. The Order
requires Pacific to pay $360,000 in penalties and reimburse the agency $12,000
for its staff costs. Pacific is considering whether to appeal this Order.
On September 15, 1997, Javelina Company, a partnership in which Coastal
Javelina, Inc., a subsidiary of the Company, is a partner and the operator of
the facility, received a Notice of Violation ("NOV") from the EPA for alleged
violations of limits in its Clean Water Act discharge permit. Javelina Company
submitted a report detailing the measures it has implemented to abate the
alleged violations and met with the EPA to discuss why an enforcement action
should not be taken for the alleged violations. In December 1997, the EPA issued
an administrative penalty of $137,000. The EPA has agreed to settle this matter
for less than $100,000, and the settlement agreement is currently being drafted.
On August 27, 1997, the EPA issued a NOV to Coastal Refining & Marketing,
Inc. ("CR&M"), a subsidiary of the Company. The NOV alleged that six violations
of the Clean Air Act were observed during inspections of the subsidiary's
refinery in Corpus Christi, Texas, conducted during March and April of 1996.
CR&M has accepted the EPA's offer of settlement and has agreed to pay a $136,000
penalty as a complete resolution of these alleged violations. The settlement
agreement is currently being drafted.
By letter dated April 8, 1997, the United States Department of Justice
(the "Department") notified ANR Coal Company LLC ("ANR Coal"), a subsidiary of
Coastal, that the EPA has requested the Department to bring an action against
ANR Coal for alleged violations of the Clean Water Act resulting from discharges
from a mine in which ANR Coal had a leasehold interest in the minerals. The
letter offers to settle the matter prior to litigation for $900,000 and
agreement to implement certain injunctive relief which includes the necessary
improvements to the existing water treatment system. ANR Coal does not believe
that it has any responsibility for these discharges, but is currently reviewing
the matter. The Company believes that this threatened action, if an action is
brought and the allegations substantiated, could result in monetary sanctions
which, while not material to the Company and its subsidiaries, could exceed
$100,000.
In April 1996, Coastal Oil & Gas Corporation ("COG"), a subsidiary of
Coastal, received a letter from the EPA Region VIII notifying it that the EPA
believes that COG's facility located in Patrick Draw, Wyoming is in violation of
certain PCB regulations promulgated pursuant to the Toxic Substances Control
Act. The EPA has offered COG an opportunity to resolve this matter without
litigation. The Company is currently having discussions with the EPA regarding
resolution of the matter. If the EPA were to initiate an action, the Company
believes that the EPA could seek penalties which, although not material, could
exceed $100,000.
In January 1996, the EPA issued a NOV to CEPOC and Eagle Point
Cogeneration Partnership ("EPCP"), in which Company subsidiaries hold a 50%
interest. The Notice alleged violations of the Clean Air Act for the failure to
obtain a Prevention of Significant Deterioration ("PSD") permit when the EPCP
was constructing the facility and for alleged violations of the facility's
operating permits. On June 25, 1997, the Department of Justice sent the
companies a letter on behalf of the EPA demanding $3 million in penalties for
the violations of the operating permits. The PSD allegation was not included in
the demand. The companies are currently discussing the matter with the EPA. If
the EPA were to initiate an action, the Company believes the EPA would seek
penalties which, while not material to the Company, could exceed $100,000.
In January 1993, the State of Texas filed suit against the Corpus Christi,
Texas refinery of CR&M, alleging failure to comply in 1992 with certain
administrative orders relating to groundwater contamination and failure to
comply with various solid and hazardous waste regulations. Following
negotiations, an agreed judgment has been reached between the parties but not
entered by the court. Once this judgment is entered, CR&M will pay $500,000 and
also spend certain amounts on supplemental environmental projects.
Future information and 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.
21
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 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 has assumed control of a pending dispute with
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 continues to have certain responsibilities. The dispute
involves a claim by IPA to expanded audit rights under the contracts. The
Company vigorously disputes IPA's claim and filed a counterclaim for certain
contractual payments wrongfully withheld by IPA. 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 believes
that no gross inequity has occurred and that it should prevail in the
arbitration on the merits. The Company has also asserted that the pending
lawsuit, which presents several common legal issues between the two proceedings,
should be resolved before any related arbitration proceeding is allowed to
proceed. A motion to this effect is pending in the U.S. District Court for Utah.
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, 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 have 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.
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 and seeks
damages in the amount of at least $100 million and punitive damages of at least
three times that amount. Plaintiffs' counsel are seeking to have the suit
certified as a class action. Coastal vigorously denies these allegations and has
filed responsive pleadings. 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 will file responsive pleadings denying these allegations.
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.
22
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 of the above 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.
23
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 11, 1998, the approximate number of holders of
record of Common Stock was 9,800 and of the Class A Common Stock was 2,950.
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.
1997 1996
----------------------------------- ------------------------------------
Quarters High Low Dividends High Low Dividends
- -------------------- -------- ----- --------- -------- ----- ---------
First Quarter $51.13 $44.63 $.10 $40.75 $34.88 $.10
Second Quarter 53.88 43.88 .10 43.75 36.25 .10
Third Quarter 63.50 52.75 .10 43.88 37.00 .10
Fourth Quarter 65.06 56.25 .10 51.50 40.81 .10
Coastal expects to continue paying dividends in the future. Dividends of
$.09 per share were paid on the Class A Common Stock for each quarterly period
in 1997 and 1996. At December 31, 1997, 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 $648.2 million.
24
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, 1996, as adjusted for minor reclassifications. The Notes
to Consolidated Financial Statements included herein contain other information
relating to this data.
Year Ended December 31,
------------------------------------------------------------------------
1997 1996**** 1995 1994 1993
----------- ----------- ------------ ------------ ----------
Operating revenues* $ 9,653.1 $ 12,166.9** $ 10,457.6 $ 10,226.2 $ 10,147.2
Earnings before extraordinary items 392.1 500.2** 270.4 232.6 118.3
Net earnings 301.5 402.6** 270.4 232.6 115.8
Basic earnings per share before
extraordinary items 3.53 4.57** 2.41 2.06 1.02
Diluted earnings per share before
extraordinary items 3.49 4.52** 2.39 2.04 1.02
Cash dividends per common share*** .40 .40 .40 .40 .40
Total assets 11,625.2 11,613.1 10,658.8 10,534.6 10,227.1
Debt, excluding current maturities 3,663.2 3,526.1 3,661.7 3,720.2 3,812.5
Preferred stock of subsidiaries,
excluding current maturities 100.0 100.0 .6 .6 26.6
* Amounts for 1997 include revenues for two months while other years
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 $1.67 per share-basic, $1.65 per share-diluted), related
to the sale of the Utah coal mining operations. Excluding the gain,
earnings before extraordinary items for 1996 amounted to $323.2 million
($2.90 per share-basic, $2.87 per share-diluted).
*** In addition, cash dividends of $.36 per share were paid on the Company's
Class A Common Stock in 1997, 1996, 1995, 1994, and 1993.
**** 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 13 of the Notes to Consolidated Financial Statements.
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-10 hereof.
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 page F-4.
Item 8. Financial Statements and Supplementary Data.
The Financial Statements and Supplementary Data required hereunder are
included in this Annual Report as set forth in Item 14(a) hereof.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
None.
25
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 7, 1998 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 11, 1998, were as
follows:
Name (Age), Year First Positions and Offices
Elected An Officer with the Registrant
--------------------------------- ------------------------------------
David A. Arledge (53), 1982 Chairman of the Board, President and
Chief Executive Officer
Coby C. Hesse (50), 1986 Executive Vice President
James A. King (58), 1992 Executive Vice President
Jeffrey A. Connelly (51), 1988 Senior Vice President
Carl A. Corrallo (54), 1993 Senior Vice President and General
Counsel
Rodney D. Erskine (53), 1997 Senior Vice President
Donald H. Gullquist (54), 1994 Senior Vice President
Dan J. Hill (57), 1978 Senior Vice President
Kenneth O. Johnson (77), 1978 Senior Vice President and Director
Austin M. O'Toole (62), 1974 Senior Vice President and Secretary
Jack C. Pester (63), 1987 Senior Vice President
James L. Van Lanen (53), 1985 Senior Vice President
M. Truman Arnold (69), 1993 Vice President
Daniel F. Collins (56), 1989 Vice President
Robert C. Hart (53), 1994 Vice President
Thomas E. Jackson (58), 1997 Vice President
Jeffrey B. Levos (37), 1997 Vice President and Controller
John J. Lipinski (47), 1995 Vice President
Edward A. More (49), 1995 Vice President
M. Frank Powell (47), 1993 Vice President
Keith O. Rattie (43), 1996 Vice President
Thomas M. Wade (45), 1995 Vice President
Ronald D. Matthews (50), 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. Hart was elected Vice President of Coastal in March 1994. From 1989
through 1994, he was president of Hart Associates, Inc., an energy development
firm.
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
26
Auditor since July 1994. Prior thereto, he was a Certified Public Accountant
with the Houston office of Deloitte & Touche LLP since January 1986.
Mr. Powell was elected Vice President of Coastal and Senior Vice President
of Coastal States Management Corporation in August 1993. From 1984 to 1993 he
was in private law practice with the law firms of Powell, Popp & Ikard and
Powell & Associates representing Coastal and other corporations. Prior thereto
he was employed at Coastal since 1978.
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 7, 1998 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 7, 1998
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 7, 1998 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 7, 1998 Annual Meeting of Stockholders filed pursuant to
Regulation 14A under the Securities Exchange Act of 1934, and is incorporated
herein by reference.
27
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-11
Statement of Consolidated Operations for the years ended
December 31, 1997, 1996 and 1995........................... F-12
Consolidated Balance Sheet at December 31, 1997 and 1996....... F-13
Statement of Consolidated Cash Flows for the years ended
December 31, 1997, 1996 and 1995........................... F-15
Statement of Consolidated Common Stock and Other Stockholders'
Equity for the years ended December 31, 1997, 1996 and
1995....................................................... F-16
Notes to Consolidated Financial Statements..................... F-17
Supplemental Information on Oil and Gas Producing Activities
(Unaudited)................................................ F-41
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.
28
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.
10.8* The Coastal Corporation Amended and Restated Deferred
Compensation Plan for Directors, effective October 9, 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.
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.
29
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.
10.19* Agreement for Consulting Services between The Coastal
Corporation and Oscar S. Wyatt, Jr. dated August 1, 1997.
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,
1997.
30
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, 1998
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, 1998
By: COBY C. HESSE
---------------------------------------
Coby C. Hesse
Principal Accounting Officer
March 26, 1998
By: JOHN M. BISSELL
---------------------------------------
John M. Bissell
Director
March 26, 1998
* * *
31
By: GEORGE L. BRUNDRETT, JR.
---------------------------------------
George L. Brundrett, Jr.
Director
March 26, 1998
By: HAROLD BURROW
---------------------------------------
Harold Burrow
Director
March 26, 1998
By: ROY D. CHAPIN, JR.
---------------------------------------
Roy D. Chapin, Jr.
Director
March 26, 1998
By: JAMES F. CORDES
---------------------------------------
James F. Cordes
Director
March 26, 1998
By: ROY L. GATES
---------------------------------------
Roy L. Gates
Director
March 26, 1998
By: KENNETH O. JOHNSON
---------------------------------------
Kenneth O. Johnson
Director
March 26, 1998
By: JEROME S. KATZIN
---------------------------------------
Jerome S. Katzin
Director
March 26, 1998
By: J. CARLETON MACNEIL, JR.
---------------------------------------
J. Carleton MacNeil, Jr.
Director
March 26, 1998
By: THOMAS R. McDADE
---------------------------------------
Thomas R. McDade
Director
March 26, 1998
By: L. D. WOODDY, JR.
---------------------------------------
L. D. Wooddy, Jr.
Director
March 26, 1998
By: O. S. WYATT, JR.
---------------------------------------
O. S. Wyatt, Jr.
Director
March 26, 1998
32
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Management's Discussion and Analysis of Financial Condition and Results of
Operations includes certain forward-looking statements reflecting the Company's
expectations and objectives in the near future; however, many factors which may
affect the actual results, including commodity prices, market and economic
conditions, industry competition and changing regulations, are difficult to
predict. Accordingly, there is no assurance that the Company's expectations and
objectives will be realized. The forward-looking statements contained herein are
intended to qualify for the safe harbor provisions of Section 21E of the
Securities Exchange Act of 1934.
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.
1997 1996 1995
-------- -------- --------
Return on average common stockholders' equity................................ 12.9% 18.5% 10.8%
Cash flow from operating activities to long-term debt........................ 26.2% 15.9% 17.7%
Total debt to total capitalization........................................... 53.0% 53.7% 59.4%
Times interest earned (before tax)........................................... 2.7 2.8 1.8
The above ratios reflect increased stockholders' equity in both 1997 and
1996 and effects of the gain from sale of the Utah coal operations in 1996. The
1997 increase and 1996 decrease 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 $960.9 million in 1997,
$561.4 million in 1996 and $649.1 million in 1995. The 1997 increase can be
primarily attributed to decreases for working capital requirements. The 1996
decrease was due to increased working capital requirements and an increase in
undistributed earnings from equity investments partially offset by increased
earnings.
Capital expenditures amounted to $996.7 million, $880.8 million and $626.8
million in 1997, 1996 and 1995, respectively. The increased 1997 capital
expenditures are primarily due to continued expansion in the Exploration and
Production segment as successful exploration programs resulted in reserve
additions which were more than three times 1997 production. The Natural Gas
Segment expenditures increased 8% 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 1996
increase was primarily due to expansion in the Exploration and Production
segment as successful exploration programs resulted in reserve additions which
were also more than three times production. Property additions also increased in
the Natural Gas segment due to the acquisition of additional storage facilities
and increased expenditures for the interstate pipelines. Expenditures increased
by 13% in the Refining, Marketing and Chemicals segment, primarily due to the
sulfur recovery facilities and coker expansion at the Corpus Christi refinery.
Proceeds from the sale of property, plant and equipment in 1997, of which
37% is from the Refining, Marketing and Chemicals segment, were comparable to
the 1996 amount. The proceeds from the Refining, Marketing and Chemicals segment
partially result from its strategy of eliminating marginal activities. Proceeds
decreased by $30.2 million in 1996 as increased proceeds from the sales of
certain oil and gas properties and natural gas gathering facilities were more
than offset by the 1995 proceeds, which included the sale of certain Refining,
Marketing and Chemicals liquid pipelines to a limited partnership. Additions to
investments in 1997 included a $50 million investment in marketable securities,
as well as increases for gas pipeline ventures. The increase in 1996 resulted
from investments in power projects and gas pipeline ventures. Proceeds from
investments increased in 1997 as a result of additional amounts
F-1
received from gas pipeline ventures. The Company received proceeds of $610.1
million in December 1996 from the sale of its Utah coal mining operations.
The Company increased total debt by $180.1 million in 1997 and reduced
total debt by $274.3 million in 1996. The 1997 increase was used for capital
expenditures and additions to investments. The 1996 reduction is primarily due
to the use of proceeds from the sale of the Utah coal mining operations. In
1996, Coastal Securities Company Limited, a subsidiary, sold $100.0 million of
preferred stock to a non-affiliate. See Note 6 of the Notes to Consolidated
Financial Statements.
Capital expenditures for 1998, including the Company's equity investments
in partnerships and joint ventures, are currently projected at approximately
$1.2 billion; however, future expenditures are dependent on conditions in the
energy industry. These expenditures are primarily for completion of projects in
process, operational necessities, environmental requirements, expansion projects
and increased efficiency. Other expansion opportunities will continue to be
evaluated.
Financing for budgeted expenditures and mandatory debt retirements in 1998
will be accomplished by the use of internally generated funds, existing credit
lines, proceeds from the selective sale of non-core assets and new financings.
Funding for certain proposed projects is anticipated to be provided
through non-recourse project financings in which the projects' assets and
contracts will be pledged as collateral. Equity participation by other entities
will also be considered. To the extent required, cash for equity contributions
to projects will be from general corporate funds.
Unused lines of credit at December 31, 1997 were as follows (Millions of
Dollars):
Short-term..........................................$ 970.3
Long-term*.......................................... 387.2
--------
$1,357.5
========
*$45.1 million of unused long-term credit lines is dedicated
to a specific use.
In February 1997, the Company purchased and retired $798 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 in the first
quarter of 1997 of $90.6 million in connection with the repurchase of these debt
securities.
In February 1997, the Company issued $200.0 million of 6.70% senior
debentures due in 2027 and $200.0 million of 7.42% senior debentures due in
2037. The net proceeds from the sale of the debentures were used to refinance a
portion of the bank borrowings incurred in connection with the retirement of the
debt securities referred to above. The 6.70% senior debentures are not
redeemable at the option of the Company prior to maturity; but each holder of
such senior debentures has the right to require the Company to redeem such
debentures, in whole or in part, on February 15, 2007, at a redemption price
equal to 100% of the aggregate principal amount thereof plus accrued and unpaid
interest. The 7.42% senior debentures are not redeemable prior to maturity.
In June 1997, Colorado Interstate Gas Company ("CIG") completed a public
offering of $100.0 million of 6.85% senior debentures due in 2037. The 6.85%
senior debentures are not redeemable at the option of CIG prior to maturity; but
each holder of such senior debentures has the right to require CIG to redeem
such debentures, in whole or in part, on June 15, 2007, at a redemption price
equal to 100% of the aggregate principal amount thereof plus accrued and unpaid
interest. The net proceeds from the offering were used to retire a $50.0 million
senior term loan and for general corporate purposes.
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, 1997, net assets of
consolidated subsidiaries amounted to approximately $6.0 billion, of which
approximately $632.3 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.
F-2
The Company has called for redemption on April 15, 1998 of all outstanding
shares of its $2.125 Cumulative Preferred Stock, Series H. There are 8,000,000
shares of the series currently outstanding. Redemption price for the Series H
stock is $25 per share plus accrued dividends of $.182986 to April 15, 1998.
The Financial Accounting Standards Board ("FASB") has issued Statement of
Financial Accounting Standards No. 130, "Reporting Comprehensive Income" ("FAS
130") to be effective for fiscal years beginning after December 15, 1997. FAS
130 establishes standards for reporting and display of comprehensive income and
its components (revenues, expenses, gains and losses) in a full set of general
purpose financial statements. The Company does not believe that the application
of the new standard will have a material effect on its consolidated financial
statements.
The FASB has issued Statement of Financial Accounting Standards No. 131,
"Disclosure about Segments of an Enterprise and Related Information" ("FAS 131")
to be effective for fiscal years beginning after December 15, 1997. FAS 131
establishes standards for the way that public business enterprises report
information about operating segments in annual financial statements and requires
that those enterprises report selected information about operating segments in
interim financial reports. Its also establishes standards for related
disclosures about products and services, geographic areas, and major customers.
The Company does not believe that the application of the new standard will have
a material effect on its consolidated financial statements.
Coastal, like most other companies, is faced with the Year 2000 Issue. The
Year 2000 Issue is the result of computer programs written with two digits
rather than four to define the applicable year. Any of the Company's computer
programs that have date-sensitive software 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 has determined that it will
be necessary to modify or replace portions of its software so that its computer
systems will properly utilize dates beyond December 31, 1999. The Company
believes that with modifications and conversions to new software, the Year 2000
Issue can be mitigated. However, if such modifications and conversions are not
made, or are not completed timely, the Year 2000 Issue could have a material
impact on the operations of the Company. There can also be no assurance that the
systems of other companies on which the Company's systems rely will be timely
converted, or that any such failure to convert by another company would not have
an adverse effect on the Company's systems.
The Company has been using both external and internal resources to
reprogram or replace its software for the Year 2000 Issue. To date, the amounts
incurred and expensed for developing and carrying out the plan have not had a
material effect on the Company's operations. The Company plans to complete the
Year 2000 modifications, including testing, by early 1999. The total remaining
cost for addressing the Year 2000 Issue of approximately $14 million, which is
based on management's current estimates, is not expected to be material to the
Company's operations. All remaining Year 2000 Issue costs will be funded through
operating cash flows.
The Company's operations are subject to extensive and evolving federal,
state and local environmental laws and regulations. The Company spent
approximately $23 million in 1997 on environmental capital projects and
anticipates capital expenditures of approximately $35 million in 1998 in order
to comply with such laws and regulations. The majority of the 1998 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 1999 through 2001 of $20 million to $40
million per year. Additionally, appropriate governmental authorities may enforce
these laws and regulations with a variety of civil and criminal enforcement
measures, including monetary penalties and remediation requirements.
The Comprehensive Environmental Response, Compensation and Liability Act,
also known as "Superfund," as reauthorized, imposes liability, without regard to
fault or the legality of the original act, for disposal of a "hazardous
substance." Certain subsidiaries of the Company and a company in which Coastal
owns a 50% interest have been named as a potentially responsible party ("PRP")
in several "Superfund" waste disposal sites. At the 16 sites for which there is
sufficient information, total clean-up costs are estimated to be approximately
$313 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 seven other sites, the Environmental Protection Agency ("EPA") is
currently unable to provide the Company with an estimate of total clean-up costs
and, accordingly, the Company is unable to calculate its share of those
F-3
costs. Finally, at 10 other sites, the Company has paid amounts to other PRPs or
to the EPA as its proportional share of associated clean-up costs. As to these
latter sites, the Company believes that its activities were de minimis.
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 clean-up costs to be approximately
$50 million, but the Company believes that the subsidiary's activities at this
site were de minimis. At the other 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 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 derivative 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, 1997. The modeling technique used measures the change in fair
values arising from selected potential changes in interest rates. Market changes
reflect immediate hypothetical changes in interest rates at December 31, 1997.
Fair values are calculated as the net present value of the expected cash flows
of the financial instrument.
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)
- -------------------------------------- --------- ----------- ---------- ----------- ----------
Assets
Notes receivable and marketable
debt securities.................. $ 279.4 $ 271.1 $ (8.3) $ 288.6 $ 9.2
Liabilities
Long-term debt subject to fixed
interest rates................... 2,619.5 2,513.2 (106.3) 2,733.6 114.1
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 $1,781.3 million at December
31, 1997. 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, 1997 levels and continue through 1998 assuming no changes in debt levels,
interest expense, including the effects of interest rate swaps, would increase
by approximately $10.7 million with a corresponding decrease in earnings before
taxes.
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, continuing through 1998, assuming no
change in outstanding shares, would decrease earnings before taxes by
approximately $0.6 million.
F-4
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 $18.5 million at December 31, 1997. An immediate
decrease in the market prices of these securities of 10% would result in a fair
value of approximately $16.7 million, or a decrease in earnings before taxes of
approximately $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, 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, 1997, and the results of such trading were not material to the
financial results of the Company for 1997.
Millions of Dollars No Change 10% Increase 10% Decrease
------------ ------------------------ --------------------------
Impact of changes in Fair Fair Increase Fair Increase
commodity prices on: Value Value (Decrease) Value (Decrease)
- -------------------------------------- ------------ ----------- ----------- ----------- ----------
Commodity futures..................... $ (15.3) $ (20.3) $ (5.0) $ (10.3) $ 5.0
In addition, the repayment terms of certain long-term variable rate debt
with a fair value of $189.3 million at December 31, 1997, 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, 1997 would result in an increase of $18.9 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 Company's utilization of derivative financial and commodity
instruments in managing market risk exposures described above is consistent with
the prior year.
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, marketing 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.
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.
F-5
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.
Millions of Dollars
-------------------------------------------
1997 1996 1995
----------- ----------- ----------
Operating revenues.............................................. $ 2,095.0 $ 3,914.9 $ 2,898.6
Depreciation, depletion and amortization........................ 135.3 160.7 152.3
Operating profit................................................ 487.3 378.3 403.5
Total pipeline throughput (Bcf)................................. 2,190 2,246 2,102
1997 Versus 1996. The decrease in operating revenues of $1,820 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. 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 $1,879 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 $59 million in 1997.
The operating profit increase of $109 million results 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 $48 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 $11 million. The reduction in depreciation,
depletion and amortization is 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 are
primarily due to reduced revenue related to the sale of property, plant and
equipment.
The Company's regulated pipelines will meet the growing demand for natural
gas by continuing with their strategy of accessing major supply sources in the
Rockies, the Midcontinent, and the Gulf of Mexico and moving the gas to core and
other growth markets. The Company will also participate in proposed export
pipelines from Canada and large projects within domestic markets.
1996 Versus 1995. The increase in operating revenues of $1,016 million can
be attributed to increased prices and volumes for the unregulated gas marketing
companies. Transportation and storage revenues decreased from 1995, reflecting
the continued, intensified competition across the United States natural gas
industry. Total throughput volumes for the pipelines increased in 1996 by
approximately 7%, and sales for the gas marketing companies were up 17%.
Purchases increased by $1,056 million in 1996 due to increased prices and
volumes for the gas marketing companies, resulting in a gross profit decrease of
$40 million.
The operating profit decrease of $25 million resulted from decreased sales
margins of $28 million, decreased storage and transportation revenue of $45
million, and increased depreciation, depletion and amortization of $8 million
partially offset by increased sales volumes of $17 million, a $29 million gain
related to the sale of a portion of ANR Pipeline Company's ("ANR Pipeline")
gathering facilities, reduced operating and general expenses of $8 million and
other increases of $2 million. The transportation and storage revenue decrease
was primarily due to decreases of $46 million for revenue received in 1995
related to storage and contract settlements and increases in provisions for
F-6
rate-related contingencies. Operating expenses were down in 1996 due to lower
salaries and benefits as a result of an early retirement incentive program in
1995.
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.
Millions of Dollars
-------------------------------------------
1997 1996 1995
----------- ----------- ----------
Operating revenues.............................................. $ 6,877.1 $ 7,364.8 $ 6,851.3
Depreciation, depletion and amortization........................ 74.6 73.3 61.8
Operating profit ............................................... 86.9 93.3 208.8
Refined product sales (MM Bbls)................................. 279 307 301
1997 Versus 1996. Operating revenues decreased by $488 million due to
reduced sales volumes and prices. The volume decrease is partially due to mild
weather in the northeastern United States as well as the ongoing refocusing 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 are 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 operating profit decrease of $6 million results from increased
operating expenses of $14 million and higher depreciation, depletion and
amortization of $1 million partially offset by the increased gross profit of $9
million. The increased operating expenses can be attributed to increases for
maintenance, catalyst and other expenses at the Company's refineries.
Past investments in Refining, Marketing and Chemical assets are allowing
Coastal to capitalize on improving industry fundamentals and refining margins.
These investments enable the Company's refineries to produce lighter,
higher-value products from the less expensive heavy and sour crudes that are
becoming increasingly more available.
1996 Versus 1995. Operating revenues increased by $514 million as a result
of increased prices and sales volumes. The volume increase was primarily a
result of increased throughput at the Company's refineries of 53,000 barrels per
day.
Purchases for the segment increased by $569 million, resulting in a gross
profit decrease of $55 million. Decreased margins of $164 million; a
non-recurring gain of $17 million from the sale of certain liquid pipeline
assets in 1995 and other decreases of $2 million were partially offset by higher
sales volumes of $104 million and increased gross profit from the sale, trading
and exchanging of third-party products of $24 million. Margins were down in 1996
due to the industrywide high crude oil prices relative to the sales prices for
refined products and substantially lower paraxylene prices compared to 1995.
The operating profit decrease of $116 million resulted from decreased
gross profit of $55 million, increased operating expenses of $49 million and
increased depreciation, depletion and amortization of $12 million. The increased
operating expenses resulted primarily from higher fuel and other costs at the
refineries due to the increased throughput, expanded retail operations and the
acquisition of a chemical plant in the first quarter of 1996. The expanded
retail, chemical and refining operations, as well as a $4 million writedown of a
tanker, resulted in the depreciation, depletion and amortization increase.
F-7
Exploration and Production. Exploration and production operations involve
the exploration, development and production of natural gas, crude oil,
condensate and natural gas liquids. The segment also includes related intrastate
natural gas marketing activities and gas processing plant operations.
Millions of Dollars
-------------------------------------------
1997 1996 1995
----------- ----------- ----------
Operating revenues.............................................. $ 561.4 $ 473.1 $ 278.6
Depreciation, depletion and amortization........................ 186.7 159.2 105.5
Operating profit................................................ 185.6 154.9 24.9
Natural gas production (MMcf/d)................................. 436 353 234
Oil, condensate and natural gas liquids production (bpd)........ 13,580 13,831 13,231
Average sales price (dollars):
- -----------------------------
Gas (per Mcf)................................................ $ 2.40 $ 2.19 $ 1.57
Oil, condensate and natural gas liquids (per bbl)............ 18.75 20.46 17.20
1997 Versus 1996. Operating revenues increased by $88 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 $1 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 results from
Coastal's ongoing successful programs in the Gulf of Mexico, South Texas and
Utah's Natural Buttes area.
The operating profit increase of $31 million results from increased
volumes of $60 million and higher prices of $23 million offset by increased
operating expenses of $22 million; higher depreciation, depletion and
amortization of $28 million; and other decreases of $2 million. The increased
operating expenses result primarily from increased levels of offshore activity
and increased production. Increased production volumes and a higher rate account
for the depreciation, depletion and amortization increase.
For the third year in a row, Coastal added reserves in 1997 that were more
than triple production due to its successful exploration and exploitation
programs.
1996 Versus 1995. The increase in operating revenues of $195 million can
be attributed to increased prices and volumes for all products. Natural gas
revenue increases of $146 million; oil, condensate and natural gas liquids
increases of $21 million; and processing plant increases of $35 million were
offset by other revenue decreases of $7 million.
The operating profit increase of $130 million resulted from higher prices
of $110 million; increased volumes sold for $94 million and other increases of
$3 million offset by increased operating expenses of $23 million and higher
depreciation, depletion and amortization of $54 million. The increased operating
expenses result primarily from increases for processing plant operations.
Depreciation, depletion and amortization was higher due to the increased volumes
and provisions for the impairment of international projects.
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.
Millions of Dollars
-------------------------------------------
1997 1996 1995
----------- ----------- ----------
Operating revenues.............................................. $ 226.8 $ 713.6 $ 459.6
Depreciation, depletion and amortization........................ 14.1 37.3 31.3
Operating profit................................................ 25.3 356.0 98.7
Captive and brokered sales (millions of tons)................... 8.0 17.9 18.0
F-8
1997 Versus 1996. The decrease in coal revenues results primarily from the
sale of the Utah coal mining operations in December 1996 (See Notes 10 and 15 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 operating profit decrease of $331 million results 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 result 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.
Coastal continues to operate mines and processing plants and market coal
from reserves in West Virginia, Virginia and Kentucky.
1996 Versus 1995. The increase in coal revenues is primarily the result of
the $272 million gain noted above partially offset by decreased volumes and
lower prices. The segment experienced a 1% decrease in volumes sold and brokered
and a 5% reduction in the average sales price per ton as compared to 1995.
The operating profit increase of $257 million resulted from the $272
million gain noted above and other increases of $17 million partially offset by
decreased volumes of $10 million and reduced prices of $22 million. The other
increase resulted primarily from sales in 1996 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.
Millions of Dollars
-------------------------------------------
1997 1996 1995
----------- ----------- ----------
Operating revenues.............................................. $ 103.8 $ 92.6 $ 48.4
Depreciation, depletion and amortization........................ 3.1 2.4 2.0
Operating profit................................................ 7.2 17.3 7.8
1997 Versus 1996. The increase in operating revenue of $11 million results
primarily from increased revenues related to the El Salvador operations
partially offset by a development fee received in 1996. The operating profit
reduction of $10 million results from the $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.
Most of the plants in which Power has investments are partially owned,
thus the equity earnings from the plants are classified as Other income-net
rather than operating profit. In 1997, equity income from the partially owned
plants amounted to $36 million. The equity income increased by $12 million over
1996 due primarily to improved results from both domestic and foreign plants,
some of which operated only a partial year in 1996.
The Company has power plants operating in the United States, China,
Central America and in the Caribbean; under construction in Guatemala, China and
Pakistan; and in various stages of development in the United States, Nicaragua,
China and other countries.
1996 Versus 1995. The operating revenue increase of $44 million resulted
primarily from the power plant in El Salvador, which began operations late in
the third quarter of 1995. Operating profit increased by $10 million, also
primarily a result of the El Salvador operations. In 1996, equity income from
partially-owned plants amounted to $24 million.
F-9
Other. Other operations involve trucking, real estate and other
activities.
Millions of Dollars
-------------------------------------------
1997 1996 1995
----------- ----------- ----------
Operating revenues.............................................. $ 29.4 $ 32.7 $ 148.3
Depreciation, depletion and amortization........................ 1.0 2.0 5.7
Operating profit................................................ 6.2 11.7 7.3
1997 Versus 1996. The $3 million decrease in operating revenues results
primarily from the sale of certain real estate properties in 1997. Operating
profit decreased by $5 million due primarily to provisions for certain
environmental exposures.
1996 Versus 1995. The $116 million decrease in operating revenues was due
to the trucking operations, which were merged, in November 1995, into a new
company in which Coastal has a 50% interest. Operating profit increased by $4
million due primarily to 1995 losses from the trucking operations not recurring.
The equity earnings (loss) from the trucking operations is included in Other
income-net.
Other Income-Net
1997 Versus 1996. Other income-net increased by $17 million in 1997 due to
increased equity income from unconsolidated subsidiaries.
1996 Versus 1995. Other income-net increased by $33 million due to
increased equity income from unconsolidated subsidiaries.
Interest and Debt Expense
1997 Versus 1996. Interest and debt expense decreased by $61 million in
1997 due to lower average debt and a lower average interest rate.
1996 Versus 1995. Interest and debt expense decreased by $47 million in
1996 due to 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.
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 13 of the Notes to Consolidated Financial
Statements.
F-10
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, 1997 and 1996, 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, 1997. 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, 1997 and 1996, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 1997, 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 3, 1998
(February 13, 1998 as to Note 15)
F-11
THE COASTAL CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED OPERATIONS
(Millions of Dollars Except Per Share)
Year Ended December 31,
--------------------------------------------
1997 1996 1995
----------- ----------- -----------
OPERATING REVENUES.............................................. $ 9,653.1 $ 12,166.9 $ 10,457.6
----------- ----------- -----------
OPERATING COSTS AND EXPENSES
Purchases.................................................... 6,786.5 8,979.8 7,554.2
Operating expenses........................................... 1,634.6 1,722.0 1,773.9
Depreciation, depletion and amortization..................... 433.5 453.6 378.5
----------- ----------- -----------
8,854.6 11,155.4 9,706.6
----------- ----------- -----------
OPERATING PROFIT................................................ 798.5 1,011.5 751.0
----------- ----------- -----------
OTHER INCOME-NET................................................ 101.7 85.0 51.6
----------- ----------- -----------
OTHER EXPENSES
General and administrative................................... 65.8 64.9 64.7
Interest and debt expense.................................... 307.5 368.3 415.4
Taxes on income.............................................. 134.8 163.1 52.1
----------- ----------- -----------
508.1 596.3 532.2
----------- ----------- -----------
EARNINGS BEFORE EXTRAORDINARY ITEMS............................. 392.1 500.2 270.4
EXTRAORDINARY ITEMS - NET OF INCOME TAXES
Loss on early extinguishment of debt......................... (90.6) (12.0) -
Discontinuation of regulatory accounting .................... - (85.6) -
----------- ----------- -----------
NET EARNINGS.................................................... 301.5 402.6 270.4
DIVIDENDS ON PREFERRED STOCK.................................... 17.4 17.4 17.4
----------- ----------- -----------
NET EARNINGS AVAILABLE TO
COMMON STOCKHOLDERS.......................................... $ 284.1 $ 385.2 $ 253.0
=========== =========== ===========
BASIC EARNINGS PER SHARE
Before extraordinary items................................... $ 3.53 $ 4.57 $ 2.41
Extraordinary items.......................................... (.85) (.92) -
----------- ----------- -----------
NET BASIC EARNINGS PER SHARE................................. $ 2.68 $ 3.65 $ 2.41
=========== =========== ===========
DILUTED EARNINGS PER SHARE
Before extraordinary items................................... $ 3.49 $ 4.52 $ 2.39
Extraordinary items.......................................... (.84) (.91) -
----------- ----------- -----------
NET DILUTED EARNINGS PER SHARE............................... $ 2.65 $ 3.61 $ 2.39
=========== =========== ===========
See Notes to Consolidated Financial Statements.
F-12
THE COASTAL CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Millions of Dollars)
December 31,
---------------------------
1997 1996
----------- ----------
ASSETS
- ------
CURRENT ASSETS
Cash and cash equivalents..................................................... $ 20.5 $ 106.3
Receivables, less allowance for doubtful accounts $16.6 million (1997)
and $23.4 million (1996)................................................... 1,570.8 1,801.0
Inventories................................................................... 684.7 1,143.9
Prepaid expenses and other.................................................... 252.7 145.2
----------- ----------
Total Current Assets....................................................... 2,528.7 3,196.4
----------- ----------
PROPERTY, PLANT AND EQUIPMENT - AT COST
Natural gas systems........................................................... 5,859.0 5,691.5
Refining, crude oil and chemical facilities................................... 2,254.8 2,213.9
Gas and oil properties - at full-cost......................................... 2,152.0 1,669.4
Other......................................................................... 395.0 386.7
----------- ----------
10,660.8 9,961.5
Accumulated depreciation, depletion and amortization.......................... 3,539.2 3,306.6
----------- ----------
7,121.6 6,654.9
----------- ----------
OTHER ASSETS
Goodwill...................................................................... 489.8 508.9
Investments - equity method .................................................. 722.8 589.1
Other......................................................................... 762.3 663.8
----------- ----------
1,974.9 1,761.8
----------- ----------
$ 11,625.2 $ 11,613.1
=========== ==========
See Notes to Consolidated Financial Statements.
F-13
THE COASTAL CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Millions of Dollars)
December 31,
---------------------------
1997 1996
----------- ----------
LIABILITIES AND STOCKHOLDERS' EQUITY
- ------------------------------------
CURRENT LIABILITIES
Notes payable ................................................................ $ 114.0 $ 105.0
Accounts payable.............................................................. 2,074.0 2,425.9
Accrued expenses.............................................................. 270.7 408.3
Current maturities on long-term debt.......................................... 42.0 8.0
----------- ----------
Total Current Liabilities.................................................. 2,500.7 2,947.2
----------- ----------
DEBT
Long-term debt, excluding current maturities.................................. 3,663.2 3,526.1
----------- ----------
DEFERRED CREDITS AND OTHER
Deferred income taxes......................................................... 1,564.9 1,404.8
Other deferred credits ....................................................... 514.0 598.5
----------- ----------
2,078.9 2,003.3
----------- ----------
PREFERRED STOCK
Issued by subsidiaries........................................................ 100.0 100.0
----------- ----------
COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY
Cumulative preferred stock (with aggregate liquidation preference
of $208.1 million) ........................................................ 2.6 2.6
Class A common stock - Issued (1997 - 366,315 shares;
1996 - 382,449 shares)..................................................... .1 .1
Common stock - Issued (1997 - 110,117,191 shares;
1996 - 109,756,251 shares)................................................. 36.7 36.6
Additional paid-in capital.................................................... 1,243.6 1,239.6
Retained earnings............................................................. 2,131.9 1,890.1
----------- ----------
3,414.9 3,169.0
Less common stock in treasury - at cost (1997 - 4,395,867 shares;
1996 - 4,395,405 shares)................................................... 132.5 132.5
----------- ----------
3,282.4 3,036.5
----------- ----------
$ 11,625.2 $ 11,613.1
=========== ==========
See Notes to Consolidated Financial Statements.
F-14
THE COASTAL CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CASH FLOWS
(Millions of Dollars)
Year Ended December 31,
-------------------------------------------
1997 1996 1995
----------- ----------- ----------
NET CASH FLOW FROM OPERATING ACTIVITIES
Earnings before extraordinary items.......................... $ 392.1 $ 500.2 $ 270.4
Add (subtract) items not requiring (providing) cash:
Depreciation, depletion and amortization ................. 436.6 455.7 382.0
Deferred income taxes..................................... 69.1 55.0 32.7
Gain from sale of Utah coal mining operations............. - (272.3) -
Amortization of producer contract reformation costs....... - 25.6 29.0
Distributed (undistributed) earnings from equity
investments............................................ (29.1) (.8) 28.6
Working capital and other changes, excluding changes
relating to cash and non-operating activities:
Accounts receivable....................................... 229.9 (684.4) (8.6)
Inventories............................................... 418.2 (387.2) 36.4
Prepaid expenses and other................................ 12.3 .4 19.8
Accounts payable.......................................... (350.1) 796.9 (132.3)
Accrued expenses.......................................... (56.6) 61.0 (2.6)
Other..................................................... (161.5) 11.3 (6.3)
----------- ----------- ----------
960.9 561.4 649.1
----------- ----------- ----------
CASH FLOW FROM INVESTING ACTIVITIES
Purchases of property, plant and equipment................... (996.7) (880.8) (626.8)
Proceeds from sale of property, plant and equipment.......... 84.1 79.4 109.6
Additions to investments..................................... (193.8) (114.2) (75.2)
Proceeds from investments.................................... 71.5 25.9 27.5
Proceeds from sale of Utah coal mining operations............ - 610.1 -
Recovery of gas supply prepayments........................... - .3 .5
----------- ----------- ----------
(1,034.9) (279.3) (564.4)
----------- ----------- ----------
CASH FLOW FROM FINANCING ACTIVITIES
Increase (decrease) in short-term notes...................... 259.0 (318.2) 366.0
Redemption of mandatory redemption
preferred stock........................................... - (.6) -
Proceeds from issuing common stock........................... 7.3 14.7 10.5
Proceeds from issuing stock of subsidiaries.................. - 105.0 -
Proceeds from long-term debt issues.......................... 943.4 590.7 323.9
Payments to retire long-term debt............................ (1,161.8) (566.2) (740.9)
Dividends paid............................................... (59.7) (59.6) (59.3)
----------- ----------- ----------
(11.8) (234.2) (99.8)
----------- ----------- ----------
NET INCREASE (DECREASE) IN CASH
AND CASH EQUIVALENTS......................................... (85.8) 47.9 (15.1)
Cash and cash equivalents at beginning of year............... 106.3 58.4 73.5
----------- ----------- ----------
Cash and cash equivalents at end of year..................... $ 20.5 $ 106.3 $ 58.4
=========== =========== ==========
See Notes to Consolidated Financial Statements.
F-15
THE COASTAL CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED COMMON STOCK AND
OTHER STOCKHOLDERS' EQUITY
(Thousands of Shares and Millions of Dollars)
Year Ended December 31,
----------------------------------------------------------------------
1997 1996 1995
------------------- -------------------- -------------------
Shares Amount Shares Amount Shares Amount
-------- -------- -------- -------- -------- --------
PREFERRED STOCK, PAR VALUE 33-1/3(cent)
PER SHARE, AUTHORIZED 50,000,000
SHARES CUMULATIVE CONVERTIBLE
PREFERRED:
$1.19, Series A: beginning balance. 60 $ - 61 $ - 63 $ -
Converted to common................ (2) - (1) - (2) -
-------- -------- ------- -------- ------- --------
Ending balance................... 58 - 60 - 61 -
======== -------- ======= -------- ======= --------
$1.83, Series B: beginning balance. 74 - 79 .1 84 .1
Converted to common................ (6) - (5) (.1) (5) -
-------- -------- ------- -------- ------- --------
Ending balance................... 68 - 74 - 79 .1
======== -------- ======= -------- ======= --------
$5.00, Series C: beginning balance. 32 - 33 - 34 -
Converted to common................ (2) - (1) - (1) -
-------- -------- ------- -------- ------- --------
Ending balance................... 30 - 32 - 33 -
======== -------- ======= -------- ======= --------
CUMULATIVE PREFERRED:
$2.125, Series H, liquidation amount
of $25 per share:
Beginning and ending balance......... 8,000 2.6 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.................. 382 .1 404 .1 416 .1
Converted to common................ (17) - (35) - (20) -
Conversion of preferred stock and
exercise of stock options.......... 1 - 13 - 8 -
-------- -------- ------- -------- ------- --------
Ending balance................... 366 .1 382 .1 404 .1
======== -------- ======= -------- ======= --------
COMMON STOCK, PAR VALUE 33-1/3(cent)
PER SHARE, AUTHORIZED 250,000,000
SHARES
Beginning balance.................. 109,756 36.6 109,168 36.4 108,726 36.2
Conversion of preferred stock...... 47 - 34 - 34 -
Conversion of Class A common stock. 17 - 35 - 20 -
Exercise of stock options.......... 297 .1 519 .2 388 .2
-------- -------- ------- -------- ------- --------
Ending balance................... 110,117 36.7 109,756 36.6 109,168 36.4
======== -------- ======= -------- ======= --------
ADDITIONAL PAID-IN CAPITAL
Beginning balance.................... 1,239.6 1,225.0 1,214.7
Exercise of stock options............ 4.0 14.6 10.3
-------- -------- --------
Ending balance................... 1,243.6 1,239.6 1,225.0
-------- -------- --------
RETAINED EARNINGS
Beginning balance ................... 1,890.1 1,547.1 1,336.0
Net earnings for period.............. 301.5 402.6 270.4
Cash dividends on preferred stock.... (17.4) (17.4) (17.4)
Cash dividends on Class A common
stock, 36(cent)(1997), 36(cent)(1996)
and 36(cent)(1995) per share....... (.1) (.1) (.1)
Cash dividends on common stock,
40(cent)(1997), 40(cent)(1996) and
40(cent)(1995) per share........... (42.2) (42.1) (41.8)
-------- -------- --------
Ending balance................... 2,131.9 1,890.1 1,547.1
-------- -------- --------
LESS TREASURY STOCK - AT COST........... 4,396 132.5 4,395 132.5 4,395 132.5
======== -------- ======= -------- ======= --------
TOTAL................................... $3,282.4 $3,036.5 $2,678.8
======== ======== ========
See Notes to Consolidated Financial Statements.
F-16
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 $275.7 million, $386.0 million and $443.6 million in 1997, 1996
and 1995, respectively. Cash payments for income taxes amounted to $63.6
million, $57.2 million and $33.3 million for 1997, 1996 and 1995, 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 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 do not
meet the requirements of a hedge are 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 is 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 $15.5 million, $8.0
million and $5.9 million in 1997, 1996 and 1995, 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-17
of gas and oil properties (excluding costs related to unevaluated properties and
major development projects) plus estimated future development costs by the
estimated proved reserves included therein, as estimated by an independent
engineer. The average amortization rate per equivalent unit of a thousand cubic
feet of gas production for oil and gas operations was $.91 for 1997, $.88 for
1996 and $.89 for 1995. 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%. 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............................................... 1.7% - 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 ("ANR") and Colorado Interstate Gas Company
("CIG"), amounted to $489.8 million at December 31, 1997, 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 1997, 1996 and 1995,
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. The earnings per share data for prior years has been restated
following the standards in Statement of Financial Accounting Standards No. 128.
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 operations in the economic environment in which
these subsidiaries operate. Further, the Company has reexamined the useful lives
of assets corresponding to these subsidiaries. During 1997, the depreciation
rates associated with certain of these assets were revised, which had the effect
of increasing "Earnings before extraordinary items" and "Net earnings" by $13.4
million ($.13 per share).
F-18
Statement of Financial Accounting Standards No. 125, "Accounting for
Transfers and Servicing of Financial Assets and Extinguishments of Liabilities"
("FAS 125"). The Company adopted FAS 125 in 1997. The application of the new
standard did not have a material effect on the Company's consolidated results of
operations, financial position or cash flows.
Statement of Position 96-1 ("SOP 96-1"). The Company adopted SOP 96-1 on
Environmental Remediation Liabilities in 1997. The application of the 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. 130, "Reporting
Comprehensive Income" ("FAS 130"). The Financial Accounting Standards Board
("FASB") has issued FAS 130 to be effective for fiscal years beginning after
December 15, 1997. FAS 130 establishes standards for reporting and display of
comprehensive income and its components (revenues, expenses, gains and losses)
in a full set of general purpose financial statements. The application of the
new standard is not expected to have a material effect on the Company's
consolidated financial statements.
Statement of Financial Accounting Standards No. 131, "Disclosures about
Segments of an Enterprise and Related Information" ("FAS 131"). The FASB has
issued FAS 131 to be effective for fiscal years beginning after December 15,
1997. FAS 131 establishes standards for the way that public business enterprises
report information about operating segments in annual financial statements and
requires that those enterprises report selected information about operating
segments in interim financial reports. It also establishes standards for related
disclosures about products and services, geographic areas, and major customers.
The Company does not believe that the application of the new standard will have
a material effect on its consolidated financial statements.
Reclassification of Prior Period Statements. Certain minor
reclassifications have been made to conform with current reporting practices.
The effect of the reclassifications was not material to the Company's
consolidated results of operations, financial position or cash flows.
Note 2. Inventories
Inventories at December 31 were (Millions of Dollars):
1997 1996
----------- ----------
Refined products, crude oil and chemicals... $ 492.3 $ 920.3
Natural gas in underground storage.......... 40.5 77.7
Coal, materials and supplies................ 151.9 145.9
----------- ----------
$ 684.7 $ 1,143.9
=========== ==========
Elements included in inventory cost are material, labor and manufacturing
expenses.
Note 3. Investments
The Company has interests in corporations, partnerships and joint ventures
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; and
several pipeline, power and other ventures. The Company's investment in these
entities, including advances, amounted to $722.8 million and $589.1 million at
December 31, 1997 and 1996, respectively. The Company's equity in income of the
investments, included in Other income-net, was $123.7 million, $103.7 million
and $60.6 million in 1997, 1996 and 1995, respectively, while dividends and
partnership distributions received amounted to $94.6 million, $102.9 million and
$89.2 million in 1997, 1996 and 1995, respectively.
F-19
Summarized financial information of these entities is as follows (Millions
of Dollars):
December 31,
---------------------------
1997 1996
----------- ----------
Current assets............................................................. $ 1,477.7 $ 800.4
Noncurrent assets.......................................................... 5,411.2 5,268.5
----------- ----------
$ 6,888.9 $ 6,068.9
=========== ==========
Current liabilities........................................................ $ 1,385.2 $ 863.6
Noncurrent liabilities..................................................... 3,274.3 3,412.8
Deferred credits........................................................... 246.6 230.4
Equity..................................................................... 1,982.8 1,562.1
----------- ----------
$ 6,888.9 $ 6,068.9
=========== ==========
Year Ended December 31,
--------------------------------------------
1997 1996 1995
----------- ----------- -----------
Revenues.................................................. $ 5,511.0 $ 2,229.0 $ 1,924.5
Operating income.......................................... 608.8 591.1 558.9
Net income................................................ 325.5 266.9 153.2
F-20
Note 4. Debt
Long-Term Debt - Balances at December 31 were (Millions of Dollars):
1997 1996
----------- ----------
The Coastal Corporation:
Notes payable (revolving credit agreements).... $ 125.0 $ -
Senior notes:
10.375%, due 2000........................... 121.3 249.9
10%, due 2001............................... 83.9 299.4
8.75%, due 1999............................. 150.0 150.0
8.125%, due 2002............................ 249.6 249.5
Senior debentures:
10.25%, due 2004............................ 37.7 199.9
10.75%, due 2010............................ 56.4 149.6
9.75%, due 2003............................. 102.1 299.1
9.625%, due 2012............................ 149.3 149.2
7.75%, due 2035............................. 149.9 149.9
7.42%, due 2037............................. 200.0 -
6.7%, due 2027.............................. 200.0 -
Other.......................................... - .1
----------- ----------
1,625.2 1,896.6
Subsidiary companies:
Notes payable (term credit facilities)......... 244.3 378.1
Notes payable (revolving credit agreements).... 682.6 510.0
Notes payable (project financing), due 2006.... 51.0 18.2
Debentures, 6.85% to 10%, due 2005-2037........ 777.4 677.2
Other, due 2003-2028........................... 74.7 54.0
----------- ----------
1,830.0 1,637.5
----------- ----------
Amount reclassified from short-term debt....... 250.0 -
----------- ----------
Total long-term debt........................... 3,705.2 3,534.1
Less current maturities........................ 42.0 8.0
----------- ----------
$ 3,663.2 $ 3,526.1
=========== ==========
At December 31, 1997, amounts available under long-term credit agreements
with banks totaled $1,439.1 million, including $125.0 million available to The
Coastal Corporation. Loans under these agreements bear interest at money
market-related rates (weighted average 6.04% at December 31, 1997). Annual
commitment fees range up to .30% payable on the unused portion of the applicable
facility. At December 31, 1997, $1,051.9 million was outstanding and $45.1
million of the unused amount was dedicated to a specific use.
The subsidiary project financing note bears interest at money
market-related rates.
Various agreements contain restrictive covenants which, among other
things, limit dividends by certain subsidiaries and additional indebtedness of
certain subsidiaries. At December 31, 1997, net assets of consolidated
subsidiaries amounted to approximately $6.0 billion, of which $632.3 million was
restricted by such provisions.
Maturities. The aggregate amounts of long-term debt maturities for the
five years following 1997 are (Millions of Dollars):
1998 $ 42.0 2001 $798.8
1999 304.5 2002 420.3
2000 131.0
F-21
Notes Payable. At December 31, 1997, Coastal had $364.0 million of
outstanding indebtedness to banks under short-term lines of credit, compared to
$105.0 million at December 31, 1996. As of December 31, 1997, the Company's
financial statements reflected $250.0 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 not a similar reclassification
as of December 31, 1996. The weighted average interest rates were 6.31% and
5.94% at December 31, 1997 and 1996, respectively. As of December 31, 1997,
$970.3 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 $648.2 million
of retained earnings was available at December 31, 1997, 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, 1997, 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 $61.3 million at
December 31, 1997. These loans are expected to be refinanced on a non-recourse
basis in 1998. 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,
1997, the Company's share of such guarantees was $488.3 million; the actual
affiliate liabilities related to these guarantees was $87.9 million. Other
guarantees and indemnities related to obligations of unconsolidated affiliates
amounted to approximately $137.4 million as of December 31, 1997. 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.
Coastal and certain subsidiaries have guaranteed approximately $6.5
million of obligations of third parties under leases and borrowing arrangements.
Where possible, the Company has obtained security interests and guarantees by
the principals. Cash requirements and losses under these guarantees are expected
to be nominal.
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 $217.5
million. Rental expense amounted to approximately $95.3 million, $92.7 million
and $79.4 million in 1997, 1996 and 1995, respectively, excluding leases
covering natural resources. Aggregate minimum lease payments under existing
noncapitalized long-term leases are estimated to be $91.7 million, $90.8
million, $77.6 million, $77.9 million, and $72.0 million for the years
1998-2002, respectively, and $686.7 million thereafter.
Note 6. Preferred Stock of Subsidiaries
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):
Shares Value
----------- ----------
Balance, December 31, 1994............ 6 $ .6
Redemptions........................... - -
----------- ----------
Balance, December 31, 1995............ 6 .6
Redemptions........................... (6) (.6)
----------- ----------
Balance, December 31, 1996............ - -
Redemptions........................... - -
----------- ----------
Balance, December 31, 1997............ - $ -
=========== ==========
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
F-22
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, 1997, the Company had interest rate swaps with a notional amount
of $22.1 million, and a portfolio of variable rate debt outstanding in the
amount of $1,518 million. Under these agreements, Coastal will pay the
counterparties interest at a weighted average fixed rate of 6.68%, and the
counterparties will pay Coastal interest at a variable rate equal to LIBOR. The
weighted average LIBOR rate applicable to these agreements was 6.11% at December
31, 1997. 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 2000.
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, 1997, 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-23
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.
(Millions of Dollars)
-----------------------------------------------------------
Dec. 31, 1997 Dec. 31, 1996
---------------------------- ----------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
---------- --------- ---------- ---------
Nonderivatives:
Financial assets:
Cash and cash equivalents................... $ 20.5 $ 20.5 $ 106.3 $ 106.3
Notes receivable............................ 222.3 241.1 206.5 219.7
Investments................................. 56.8 56.8 - -
Financial liabilities:
Short-term debt............................. 114.0 114.0 105.0 105.0
Long-term debt ............................. 3,705.2 4,024.0 3,534.1 3,879.8
Preferred stock - issued by subsidiaries.... 100.0 100.0 100.0 101.3
Derivatives relating to:
Commodity swaps loss........................ - - - (44.3)
Debt:
Interest rate swaps loss.................... - 0.2 - 0.4
The estimated value of the Company's notes receivable, long-term debt and
preferred stock - issued by subsidiaries is based on interest rates at December
31, 1997 and 1996, respectively, for new issues with similar remaining
maturities. The fair value of investments are based on market prices at December
31, 1997. The fair value of the derivatives relating to commodity swaps reflects
the estimated amount to terminate the contracts at December 31, 1996, taking
into account unrealized gains or losses. Dealer quotes are available for these
derivatives. The fair market value of the Company's interest rate swaps is based
on the estimated termination values at December 31, 1997 and 1996, respectively.
Note 8. Common and Preferred Stock
Executives, directors and other key employees have been granted options to
purchase common shares under stock option plans adopted in 1990, 1994, 1996 and
1997. Under each plan, the option price equals the fair market value of the
common shares on the date of grant. Options vest cumulatively at rates ranging
from 15% to 33 1/3% of the option shares on each anniversary date of the date of
grant beginning with the first or second anniversary. The options, which expire
either five years or ten years from the grant date, do not carry any stock
appreciation rights.
F-24
The following table presents a summary of stock option transactions for
the three years ended December 31, 1997:
Class A Average
Common Common Option Price
Shares Shares Per Share
------------ ----------- --------------
December 31, 1994........................................... 2,176,657 22,591 $ 26.99
Granted.................................................. 515,250 - 28.51
Exercised................................................ (415,971) (7,811) 22.14
Revoked or expired....................................... (118,700) - 29.68
----------- ----------- --------------
December 31, 1995........................................... 2,157,236 14,780 28.15
Granted.................................................. 666,500 - 36.59
Exercised................................................ (528,751) (12,500) 26.52
Revoked or expired....................................... (61,600) - 30.87
----------- ----------- --------------
December 31, 1996........................................... 2,233,385 2,280 30.98
Granted.................................................. 783,556 - 47.19
Exercised................................................ (294,965) - 27.44
Revoked or expired....................................... (117,601) - 32.52
----------- ----------- --------------
December 31, 1997........................................... 2,604,375 2,280 $ 36.24
=========== =========== --------------
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. 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 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):
Year Ended December 31,
-------------------------------------------
1997 1996 1995
----------- ----------- ----------
Earnings before extraordinary items....................... $ 387.8 $ 498.0 $ 269.5
Net earnings.............................................. 297.2 400.4 269.5
Basic earnings per share
Before extraordinary items............................. $ 3.49 $ 4.55 $ 2.40
Extraordinary items.................................... (.85) (.92) -
----------- ----------- ----------
Net basic earnings per share........................... $ 2.64 $ 3.63 $ 2.40
=========== =========== ==========
Diluted earnings per share
Before extraordinary items............................. $ 3.45 $ 4.50 $ 2.38
Extraordinary items.................................... (.84) (.91) -
----------- ----------- ----------
Net diluted earnings per share......................... $ 2.61 $ 3.59 $ 2.38
=========== =========== ==========
The effects of applying FAS 123 in this pro forma disclosure are not
indicative of future amounts.
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 1997: risk free interest of 6.90%; expected dividend yield of
.85%; expected life of eight years; and expected volatility of .2205. The
weighted average fair value of options granted during 1997 is $19.49 per share.
Stock options available for future grants amounted to 246,821; 906,771;
and 1,530,830 at December 31, 1997, 1996 and 1995, respectively. Exercisable
stock options amounted to 676,599; 748,354; and 1,096,479 at December 31, 1997,
1996 and 1995, respectively.
F-25
The following tables summarize information about stock options outstanding
and exercisable at December 31, 1997:
Outstanding Exercisable
-------------------------------------- ------------------------
Average Average
Exercise Average Exercise Exercise
Price Range Shares Life (*) Price Shares Price
----------- ------------ -------- ----------- ---------- -----------
$20.91 - $29.13........................ 829,379 5.8 $ 27.60 394,419 $ 27.10
30.31 - 40.56........................ 1,005,720 6.7 34.95 282,180 33.02
47.06 - 59.63........................ 771,556 9.1 47.18 - -
--------- ----------
2,606,655 676,599
========= ==========
*Average life remaining in years.
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. 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.
The segment also includes related intrastate natural gas marketing activities
and gas plant processing operations. 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.
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 China, El
Salvador and the Dominican Republic.
Other operations include regional trucking operations involving activities
as common carriers in interstate and intrastate commerce and activities in other
projects. Effective November 1995, the trucking operations were merged into a
new company in which Coastal has a 50% interest.
Operating revenues by segment include both sales to unaffiliated
customers, as reported in the Company's Statement of Consolidated Operations,
and intersegment sales, which are accounted for on the basis of contract,
current market or internally established transfer prices. The intersegment sales
are primarily sales from the exploration and production segment to the natural
gas and refining, marketing and chemicals segments and from the natural gas
segment to the refining, marketing and chemicals segment.
Operating profit is total revenues less interest income from affiliates
and operating costs and expenses. Operating expenses exclude income taxes,
corporate general and administrative expenses and interest.
F-26
Earnings before interest, taxes, and extraordinary items is operating
profit and Other income-net, including equity income from investments, reduced
by corporate general and administrative expenses.
Identifiable assets by segment are those assets that are used in the
Company's operations in each segment. Corporate assets are those assets which
are not specifically identifiable with a segment.
The Company's operating revenues; operating profit; earnings before
interest, taxes and extraordinary items; capital expenditures; and depreciation,
depletion and amortization expense for the years ended December 31, 1997, 1996
and 1995, and identifiable assets as of December 31, 1997, 1996 and 1995, by
segment, are shown as follows (Millions of Dollars):
1997 1996 1995
----------- ----------- -----------
Operating Revenues
Natural gas............................................... $ 2,095.0 $ 3,914.9 $ 2,898.6
Refining, marketing and chemicals ........................ 6,877.1 7,364.8 6,851.3
Exploration and production................................ 561.4 473.1 278.6
Coal...................................................... 226.8 713.6 459.6
Power..................................................... 103.8 92.6 48.4
Other..................................................... 29.4 32.7 148.3
Adjustments and eliminations.............................. (240.4) (424.8) (227.2)
----------- ----------- -----------
Consolidated totals.................................... $ 9,653.1 $ 12,166.9 $ 10,457.6
=========== =========== ===========
Operating Profit
Natural gas............................................... $ 487.3 $ 378.3 $ 403.5
Refining, marketing and chemicals......................... 86.9 93.3 208.8
Exploration and production................................ 185.6 154.9 24.9
Coal...................................................... 25.3 356.0 98.7
Power..................................................... 7.2 17.3 7.8
Other .................................................... 6.2 11.7 7.3
----------- ----------- -----------
Consolidated totals.................................... $ 798.5 $ 1,011.5 $ 751.0
=========== =========== ===========
Earnings Before Interest, Taxes and Extraordinary Items
Natural gas............................................... $ 578.9 $ 469.7 $ 473.9
Refining, marketing and chemicals ........................ 95.6 94.4 184.3
Exploration and production................................ 186.7 156.2 24.9
Coal...................................................... 25.3 356.0 98.7
Power..................................................... 43.4 41.4 27.8
Other..................................................... (7.6) (2.5) 6.7
----------- ----------- -----------
Segment totals......................................... 922.3 1,115.2 816.3
Corporate ................................................ (87.9) (83.6) (78.4)
----------- ----------- -----------
Consolidated totals.................................... $ 834.4 $ 1,031.6 $ 737.9
=========== =========== ===========
Capital Expenditures
Natural gas............................................... $ 223.9 $ 206.5 $ 128.6
Refining, marketing and chemicals......................... 167.6 215.3 190.3
Exploration and production................................ 575.2 381.2 230.3
Coal...................................................... 18.8 51.5 54.0
Power..................................................... 2.2 3.7 12.1
Other..................................................... 1.1 14.4 5.0
----------- ----------- -----------
Segment totals......................................... 988.8 872.6 620.3
Corporate ................................................ 7.9 8.2 6.5
----------- ----------- -----------
Consolidated totals.................................... $ 996.7 $ 880.8 $ 626.8
=========== =========== ===========
F-27
1997 1996 1995
----------- ----------- -----------
Depreciation, Depletion and Amortization Expense
Natural gas............................................... $ 135.3 $ 160.7 $ 152.3
Refining, marketing and chemicals......................... 74.6 73.3 61.8
Exploration and production................................ 186.7 159.2 105.5
Coal...................................................... 14.1 37.3 31.3
Power..................................................... 3.1 2.4 2.0
Other..................................................... 1.0 2.0 5.7
----------- ----------- -----------
Segment totals......................................... 414.8 434.9 358.6
Corporate ................................................ 3.1 4.0 4.6
----------- ----------- -----------
Consolidated totals.................................... $ 417.9 $ 438.9 $ 363.2
=========== =========== ===========
Identifiable Assets
Natural gas............................................... $ 5,195.2 $ 5,395.1 $ 5,359.8
Refining, marketing and chemicals......................... 3,795.4 4,061.6 3,125.2
Exploration and production................................ 1,550.8 1,178.4 992.0
Coal...................................................... 252.7 225.3 518.6
Power..................................................... 258.1 211.1 140.3
Other..................................................... 99.1 150.1 159.8
----------- ----------- -----------
Segment totals......................................... 11,151.3 11,221.6 10,295.7
Corporate ................................................ 473.9 391.5 363.1
----------- ----------- -----------
Consolidated totals.................................... $ 11,625.2 $ 11,613.1 $ 10,658.8
=========== =========== ===========
The Coal revenues and operating profit for 1996 include a gain before
income taxes of $272.3 million from the sale of the Utah coal mining operations.
See Notes 10 and 15 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 years ended December 31, 1996 and 1995 include the revenues of Coastal's
natural gas marketing operations ($833.5 million, $2,780.5 million and $1,730.4
million, respectively). Subsequent to the combination, Engage's revenues are not
included in Coastal's operating revenues; however, Coastal's share of Engage's
net earnings is included in Other income-net. As part of the combination,
Coastal received an equalization payment which added $42 million to the natural
gas operating profit for 1997.
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):
1997 1996 1995
----------- ----------- -----------
Revenues................... $ 26.3 $ 26.1 $ 2.3
Impact on earnings......... 17.1 16.9 1.5
The number and magnitude of such transactions may vary significantly from
year to year, particularly in view of conditions in world petroleum markets.
F-28
The Company's operating revenues and operating profit for the years ended
December 31, 1997, 1996 and 1995, and identifiable assets as of December 31,
1997, 1996 and 1995, by geographic area, are shown as follows (Millions of
Dollars):
1997 1996 1995
----------- ----------- -----------
Operating Revenues
United States - third party............................. $ 7,982.6 $ 10,595.8 $ 9,146.2
- interarea............................... 93.1 92.4 129.1
Foreign, Aruba - third party............................. 1,251.4 1,154.8 932.4
- interarea............................... 117.4 143.6 245.0
Foreign, other - third party............................. 419.1 416.3 379.0
- interarea............................... 118.1 239.1 56.4
Interarea elimination........................................ (328.6) (475.1) (430.5)
----------- ----------- -----------
Consolidated totals........................................ $ 9,653.1 $ 12,166.9 $ 10,457.6
=========== =========== ===========
Operating Profit
United States................................................ $ 727.0 $ 923.2 $ 597.0
Foreign, Aruba............................................... 58.4 18.9 90.5
Foreign, other............................................... 13.1 69.4 63.5
----------- ----------- -----------
Consolidated totals........................................ $ 798.5 $ 1,011.5 $ 751.0
=========== =========== ===========
Identifiable Assets
United States................................................ $ 10,061.1 $ 10,269.1 $ 9,590.7
Foreign, Aruba............................................... 994.1 883.2 764.2
Foreign, other............................................... 570.0 460.8 303.9
----------- ----------- -----------
Consolidated totals........................................ $ 11,625.2 $ 11,613.1 $ 10,658.8
=========== =========== ===========
Revenues from sales to any single customer during 1997, 1996 or 1995 did
not amount to 10% or more of the Company's consolidated revenues.
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, $1.67 per share-basic or
$1.65 per share-diluted.
F-29
Following is a summary of the results of operations and the assets and
liabilities of the Utah coal mining operations (Millions of Dollars):
For the Period For the
From January 1, 1996 Year Ended
Through December 20, 1996 December 1995
------------------------- -------------
Operating revenues............................. $ 200.7 $ 213.0
Costs and expenses............................. 145.0 144.7
--------- ---------
Earnings before income taxes................ 55.7 68.3
Income taxes................................... 16.6 18.4
--------- ---------
Net earnings................................ $ 39.1 $ 49.9
========= =========
December 31,
1996
------------
Working capital......................................................................... $ 60.1
Property, plant and equipment-net....................................................... 193.7
Other assets............................................................................ 53.4
Deferred credits and other.............................................................. 8.9
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
Employee Retirement Income Security Act of 1974, as amended. The pension benefit
for 1997, 1996 and 1995 is shown in the following table (Millions of Dollars):
Year Ended December 31,
--------------------------------------------
1997 1996 1995
----------- ----------- -----------
Service cost - benefit earned during the period........... $ 17.2 $ 18.3 $ 15.8
Interest cost on projected benefit obligation............. 47.5 45.6 42.2
Actual return on assets................................... (263.5) (175.8) (223.7)
Net amortization and deferral............................. 146.5 90.3 152.3
----------- ----------- -----------
Net periodic pension benefit.............................. $ (52.3) $ (21.6) $ (13.4)
=========== =========== ===========
The discount rate used in determining the actuarial present value of the
projected benefit obligation was 7.00% in 1997, 7.50% in 1996 and 7.25% in 1995.
The expected increase in future compensation levels was 4% in 1997, 1996 and
1995 and the expected long-term rate of return on assets was 10% in 1997, 1996
and 1995.
F-30
The following table sets forth the funded status of the plans and the
amounts recognized in the Company's Consolidated Balance Sheet (Millions of
Dollars):
December 31,
-----------------------------
1997 1996
----------- ------------
Actuarial present value of benefit obligations:
Accumulated benefit obligation, including vested benefits of
$614.0 million and $544.1 million, respectively........................ $ (635.7) $ (583.8)
=========== ============
Projected benefit obligation for service rendered to date................. $ (729.3) $ (658.2)
Plan assets, primarily equity securities, at fair value................... 1,298.7 1,078.7
----------- ------------
Plan assets in excess of projected benefit obligation..................... 569.4 420.5
Unrecognized net assets at January 1, 1997 and 1996, being
recognized over average remaining service lives........................ (37.1) (45.7)
Prior service cost, not yet recognized.................................... 3.0 3.4
Unrecognized net gain from past experience
different from that assumed............................................ (200.7) (96.6)
----------- ------------
Prepaid pension cost...................................................... $ 334.6 $ 281.6
=========== ============
Plan assets include common stock and Class A common stock of the Company
amounting to a total of 3.75 million shares at December 31, 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 $0.5 million for 1997, $0.7 million for 1996 and $6.4 million
for 1995. The data available from administrators of the multi-employer pension
plans is not sufficient to determine the accumulated benefit obligations, nor
the net assets attributable to the multi-employer plans in which Company
employees participate. The decrease in 1996 results from the Company's trucking
operations being merged into a new company effective November 3, 1995, in which
Coastal has a 50% interest.
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 $18.9 million, $18.5 million and $17.6 million in 1997, 1996 and
1995, 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-31
The following tables set forth the accumulated postretirement benefit
obligation recognized in the Company's Consolidated Balance Sheet as of December
31, 1997 and 1996, and the benefit cost for the years ended December 31, 1997,
1996 and 1995 (Millions of Dollars):
December 31,
-----------------------------
1997 1996
----------- ------------
Accumulated postretirement benefit obligation:
Retirees............................................................... $ (70.4) $ (76.8)
Fully eligible plan participants....................................... (1.4) (1.4)
Other active plan participants......................................... (36.2) (31.9)
----------- ------------
(108.0) (110.1)
Plan assets at fair value................................................. 24.1 26.0
----------- ------------
Accumulated postretirement benefit obligation in excess of plan assets.... (83.9) (84.1)
Unrecognized net transition obligation.................................... 89.7 98.6
Unrecognized net gain from past experience different from that assumed.... (36.3) (36.8)
Unrecognized prior service cost .......................................... 3.9 4.7
----------- ------------
Postretirement benefit obligation included in balance sheet .............. $ (26.6) $ (17.6)
=========== ============
Year Ended December 31,
--------------------------------------------
1997 1996 1995
----------- ----------- -----------
Net postretirement benefit cost consisted of the
following components:
Service cost - benefits earned during the period.......... $ 2.3 $ 2.5 $ 2.2
Interest cost on accumulated postretirement benefit
obligation............................................. 7.0 7.6 8.8
Actual return on assets................................... (1.2) (1.2) (.8)
Amortization of transition obligation..................... 6.0 6.2 6.6
Deferred regulatory amounts............................... 3.5 3.6 2.0
Other amortization and deferral........................... (1.8) (.9) (1.5)
----------- ----------- -----------
Net postretirement benefit cost........................... $ 15.8 $ 17.8 $ 17.3
=========== =========== ===========
The assumed health care cost trend rate used in measuring the accumulated
postretirement benefit obligation was 9.7% in 1997, declining gradually to 6.0%
by the year 2004. The assumed health care cost trend rate used in measuring the
accumulated postretirement benefit obligation was 10.4% in 1996 and 11.2% in
1995. 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, 1997 by approximately 4.5% and the net postretirement health
care cost by approximately 4.3%. The assumed discount rate used in determining
the accumulated postretirement benefit obligation was 7.25%.
Note 12. Taxes on Income
Pretax earnings before extraordinary items are composed of the following
(Millions of Dollars):
Year Ended December 31,
--------------------------------------------
1997 1996 1995
----------- ----------- -----------
United States............................................. $ 448.1 $ 579.9 $ 178.1
Foreign .................................................. 78.8 83.4 144.4
----------- ----------- -----------
$ 526.9 $ 663.3 $ 322.5
=========== =========== ===========
F-32
Provisions for income taxes before extraordinary items are composed of the
following (Millions of Dollars):
Year Ended December 31,
--------------------------------------------
1997 1996 1995
----------- ----------- -----------
Current income taxes:
Federal................................................ $ 52.0 $ 88.0 $ 13.0
Foreign................................................ 5.3 6.4 2.7
State ................................................. 8.4 13.7 3.7
----------- ----------- -----------
65.7 108.1 19.4
----------- ----------- -----------
Deferred income taxes:
Federal................................................ 64.7 51.4 31.0
Foreign................................................ 3.3 3.0 .5
State ................................................. 1.1 .6 1.2
----------- ----------- -----------
69.1 55.0 32.7
----------- ----------- -----------
Taxes on income........................................... $ 134.8 $ 163.1 $ 52.1
=========== =========== ===========
The Company and the Internal Revenue Service ("IRS") Appeals Office have
concluded a final settlement of the adjustments originally proposed to federal
income tax returns filed for the years 1985 through 1987. The IRS has
subsequently proposed additional adjustments to those returns, and the Company
will contest 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.
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):
Year Ended December 31,
--------------------------------------------
1997 1996 1995
----------- ----------- -----------
Tax expense by applying the U.S. federal income
tax rate of 35%........................................ $ 184.4 $ 232.1 $ 112.9
Increases (reductions) in taxes resulting from:
Tight sands gas credit................................. (6.5) (7.3) (11.3)
State income tax cost ................................. 6.2 9.2 3.2
Goodwill............................................... 6.4 6.4 6.4
Full normalization..................................... (1.5) (1.7) (.4)
Research activities credit............................. - (11.8) -
Exclusion for foreign investments and certain
domestic joint ventures............................ (50.6) (59.2) (50.7)
Depletion and depreciation............................. (1.4) (6.3) (9.8)
Other.................................................. (2.2) 1.7 1.8
----------- ----------- -----------
Taxes on income .......................................... $ 134.8 $ 163.1 $ 52.1
=========== =========== ===========
F-33
Deferred tax liabilities (assets) which are recognized for the estimated
future tax effects attributable to temporary differences and carryforwards are
(Millions of Dollars):
December 31,
-----------------------------
1997 1996
----------- ------------
Excess of book basis over tax basis of property, plant and equipment...... $ 1,458.5 $ 1,412.1
Pensions and benefit costs................................................ 99.2 88.3
Purchase gas and other recoverable cost................................... 32.7 28.7
Other..................................................................... 16.2 -
----------- ------------
Deferred tax liabilities ................................................. 1,606.6 1,529.1
----------- ------------
Alternative minimum tax credit carryforward............................... (181.2) (136.7)
Other..................................................................... - (7.7)
----------- ------------
Deferred tax assets....................................................... (181.2) (144.4)
----------- ------------
Deferred income taxes..................................................... $ 1,425.4 $ 1,384.7
=========== ============
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 $301.3 million are considered to
be indefinitely reinvested outside the U.S. and, accordingly, no U.S. income
taxes have been provided on those earnings.
Note 13. 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 $90.6 million ($.85 per share-basic or $.84 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 $12.0 million ($.11 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 $85.6 million ($.81 per share-basic or $.80 per share-diluted), net
of related income taxes of $50.0 million.
F-34
Note 14. Earnings Per Share
Earnings per share are calculated following Statement of Financial
Accounting Standards No. 128. The following data shows the amounts used in
computing basic earnings per share and the effects on income and the weighted
average number of shares of dilutive securities.
For the Year Ended December 31, 1997
-------------------------------------------------
Income Shares
(Numerator) (Denominator) Per-Share
(Millions) (Thousands) Amount
-------------- ------------- -------------
Earnings before extraordinary items..................... $ 392.1
Less preferred stock dividends.......................... 17.4
--------------
Basic earnings per share
Income available to common stockholders.............. 374.7 105,946 $ 3.53
===========
Effect of dilutive securities
Options.............................................. - 899
Convertible preferred stock.......................... .4 706
-------------- -----------
Diluted earnings per share
Income available to common stockholders plus
assumed conversions.............................. $ 375.1 107,551 $ 3.49
============== =========== ===========
For the Year Ended December 31, 1996
-------------------------------------------------
Income Shares
(Numerator) (Denominator) Per-Share
(Millions) (Thousands) Amount
-------------- ------------- -------------
Earnings before extraordinary items..................... $ 500.2
Less preferred stock dividends.......................... 17.4
--------------
Basic earnings per share
Income available to common stockholders.............. 482.8 105,493 $ 4.57
===========
Effect of dilutive securities
Options.............................................. - 621
Convertible preferred stock.......................... .4 729
-------------- -----------
Diluted earnings per share
Income available to common stockholders plus
assumed conversions.............................. $ 483.2 106,843 $ 4.52
============== =========== ===========
For the Year Ended December 31, 1995
-------------------------------------------------
Income Shares
(Numerator) (Denominator) Per-Share
(Millions) (Thousands) Amount
-------------- ------------- -------------
Earnings before extraordinary items..................... $ 270.4
Less preferred stock dividends.......................... 17.4
--------------
Basic earnings per share
Income available to common stockholders.............. 253.0 104,889 $ 2.41
===========
Effect of dilutive securities
Options.............................................. - 318
Convertible preferred stock.......................... .4 764
-------------- -----------
Diluted earnings per share
Income available to common stockholders plus
assumed conversions.............................. $ 253.4 105,971 $ 2.39
============== =========== ===========
F-35
Options to purchase 222,600 shares at prices ranging from $33.81 to $35.94
were not included in the computation of diluted earnings per share for 1995
because the options' exercise prices were greater than the average market price
of the common shares.
Note 15. Litigation, Regulatory and Environmental Matters
Litigation. In connection with the December 20, 1996 sale of the Company's
western coal operations, the Company has 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 continues to have certain responsibilities. The dispute
involves a claim by IPA to expanded audit rights under the contracts. The
Company vigorously disputes IPA's claim and filed a counterclaim for certain
contractual payments wrongfully withheld by IPA. 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 believes
that no gross inequity has occurred and that it should prevail in the
arbitration on the merits. The Company has also asserted that the pending
lawsuit, which presents several common legal issues between the two proceedings,
should be resolved before any related arbitration proceeding is allowed to
proceed. A motion to this effect is pending in the U.S. District Court for Utah.
In December 1992, certain of Colorado Interstate Gas Company's ("CIG")
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, 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 have 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.
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 and seeks
damages in the amount of at least $100 million and punitive damages of at least
three times that amount. Plaintiffs' counsel are seeking to have the suit
certified as a class action. Coastal vigorously denies these allegations and has
filed responsive pleadings. In January 1998, the plaintiffs amended their suit
to exclude ANR Pipeline Company ("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 will file responsive pleadings denying
these allegations.
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 of the above 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.
Regulatory Matters. On January 31, 1996, the FERC issued a "Statement of
Policy and Request for Comments" (the "Policy") with respect to a pipeline's
ability to negotiate and charge rates for individual customers' services which
would not be limited to the "cost-based" rates established by the FERC in
traditional rate making. Under this Policy, a pipeline and a customer will be
allowed to negotiate a contract which provides for rates and charges that exceed
the
F-36
pipeline's posted maximum tariff rates, provided that the shipper 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"). 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 made such
filing and the FERC has accepted that tariff filing. Under the Policy, 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. Some parties have sought judicial
review of the FERC's acceptance of CIG's tariff filing to implement negotiated
rates, but CIG's tariff sheet remains in effect pending review. CIG has filed
for judicial review of the FERC's holding that pipelines which have entered into
"negotiated rate" contracts will not be allowed discount adjustments in
connection with such contracts. The FERC is also considering comments on whether
this "negotiated rate" program should be extended to other terms and conditions
of pipeline transportation services.
In July 1996, the United States Court of Appeals for the D. C. Circuit
upheld the basic structure of the FERC's Order 636 (issued in April 1992), but
remanded to the FERC, for further consideration, certain limited aspects of the
Order. In its order responding to the remand (Order 636-C, issued February 27,
1997) the FERC: (1) reaffirmed the right of pipelines to recover 100% of their
prudently incurred transition costs, but required pipelines to file within 180
days a proposal for the level of costs to be allocated to interruptible
transportation customers; and (2) reduced from 20 years to five years, the term
"cap" to be applied to evaluation of bids for renewal of contracts on existing
volumes. ANR Pipeline and CIG have sought rehearing and clarification of these
holdings as they relate to past and future periods, and have also made the
appropriate compliance filings with the FERC. ANR Pipeline's proposal to retain
its current transition cost allocation level to interruptible service was
accepted by the FERC as part of an uncontested settlement following further
proceedings before the FERC.
From November 1, 1992, to November 1, 1993, gas inventory demand charges
were collected from ANR Pipeline's former resale customers. This method of gas
cost recovery required refunds for any over-collections. In April 1994, ANR
Pipeline filed with the FERC a refund report showing over-collections and
proposing refunds totaling $45.1 million. Certain customers disputed the level
of those refunds. The FERC approved ANR Pipeline's refund allocation methodology
and ANR Pipeline, in March 1995, paid undisputed refunds of $45.1 million,
together with applicable interest, subject to further investigation of
customers' claims. The FERC's approval of ANR Pipeline's refund allocation
methodology was upheld by the United States Court of Appeals for the D.C.
Circuit in April 1996. Disputed issues related to the refunds are the subject of
further proceedings before the FERC. In March 1997, an Initial Decision was
issued which adopted most of ANR Pipeline's positions. On March 12, 1998, the
FERC affirmed the Initial Decision in almost all aspects. Parties may seek
rehearing in thirty days.
ANR Pipeline filed a general rate increase on November 1, 1993. Issues
related to the general rate increase are the subject of continuing FERC and
judicial proceedings. Under a March 1994 order, certain costs were reduced or
eliminated, resulting in revised rates that reflect a $182.8 million increase
over the cost of service underlying ANR Pipeline's approved rates for its Order
636 restructured services. In September 1994, the FERC accepted ANR Pipeline's
filing to place the new rates into effect May 1, 1994, subject to further
modifications. ANR Pipeline submitted revised rates in compliance with this
order in October 1994. In January 1997, an Initial Decision was issued on the
issues set for hearing by the March 1994 Order. That Initial Decision, which
accepted some but not all of ANR Pipeline's rate change proposals, does not take
effect until reviewed by the FERC. ANR Pipeline and other parties have filed
exceptions regarding some of the findings in the Initial Decision. On October
17, 1997, ANR Pipeline filed a comprehensive settlement that will resolve all
issues in the proceeding, as well as result in the voluntary dismissal of
pending court appeals. Under the settlement, ANR Pipeline agreed to place the
settlement rates in effect on November 1, 1997, subject to the prospective
restoration of ANR Pipeline's currently filed rates (subject to refund) if the
settlement is not approved. By order issued October 31, 1997, the FERC
authorized ANR Pipeline to proceed on that basis. The settlement includes
provisions for lower rates, refunds, procedures to resolve certain reserved
matters, as well as a proposal for a new short-term firm service that will
enable ANR Pipeline to charge higher rates for shippers electing to purchase
such service. The settlement is either supported by or not opposed by all active
parties in the proceeding. By order issued February 13, 1998, the FERC approved
the settlement in all respects, other than the proposed new short-term firm
service. The FERC also addressed two of the three reserved matters that the
parties had requested it decide on the merits. On March 16, 1998, ANR Pipeline
filed written notification with the FERC that the order on the settlement was
acceptable to ANR Pipeline and all parties, and the settlement became effective
as of such date. The approved settlement includes a stipulation that ANR
Pipeline will refund $66.6 million, which includes interest, for rates collected
during the
F-37
period its proposed rates were in effect. Pursuant to the settlement, all
refunds must be remitted within 30 days of the effective date. During the period
the proposed rates were in effect, ANR Pipeline estimated and recorded
provisions for potential rate refunds, which exceed the final refund
requirements.
The FERC has also issued a series of orders in ANR Pipeline's rate
proceeding that apply a new policy governing the order of attribution of
revenues received by ANR Pipeline related to transition costs under Order 636.
Under that new policy, ANR Pipeline is required to first attribute the revenues
it receives for its services to the recovery of its transition costs under Order
636 rather than to the recovery of its base cost of service. The FERC's change
in its revenue attribution policy has the effect of understating ANR Pipeline's
currently effective maximum rates and accelerating its amortization of
transitions costs for regulatory accounting purposes. In light of the FERC's
policy, ANR Pipeline filed with the FERC to increase its discount recovery
adjustment in its rate proceeding. ANR Pipeline also sought judicial review of
these orders before the United States Court of Appeals for the D.C. Circuit,
which appeals were dismissed as premature in light of the pending general rate
increase proceeding discussed above. As a result of the rate case settlement
described above, ANR Pipeline can no longer pursue such judicial review of the
specific orders involved.
In May 1997, certain of ANR Pipeline's customers filed a motion with the
FERC for immediate refund of approximately $77 million, which is related to ANR
Pipeline's settlement with Dakota Gasification Company. ANR Pipeline responded
to the FERC, demonstrating that the customers' claim is grossly overstated by
identifying the appropriate amounts to be refunded to its customers. On June 30,
1997, ANR Pipeline paid such refunds (totaling $21.1 million) to its customers.
On December 2, 1997, the FERC issued an order rejecting the customers' claims,
and found that ANR Pipeline had properly calculated the level of refunds due to
the customers. The FERC's decision on this matter is now final because the
customers did not seek rehearing.
On March 29, 1996, CIG filed with the FERC under Docket No. RP96-190 to
increase its rates by approximately $30 million annually, to realign certain
transportation services and to add tariff language that would allow CIG to enter
into "negotiated rates" (rates which could exceed CIG's "cost-based" rates) in
certain circumstances, subject to FERC policies. On April 25, 1996, the FERC
accepted the rate change filing and the transportation service realignment to
become effective October 1, 1996, subject to refund, and also accepted the
"negotiated rate" tariff provision to become effective May 1, 1996. Certain
parties sought judicial review of the acceptance of the "negotiated rate" tariff
provisions. On October 16, 1997, the FERC approved an unopposed settlement filed
by CIG that resolves all issues in this general rate case except the issues that
are on appeal relating to the "negotiated rate" tariff provisions. The final
settlement modifies the services provided by CIG, and the charges for those
services. The final settlement became effective on November 17, 1997, and is no
longer subject to review by the FERC or subject to any judicial review. CIG has
now made refunds of amounts collected which were in excess of the final
settlement rates. The appeal of the "negotiated rate" provision has been
consolidated with other appeals involving the same issues, and is being held in
abeyance by the United States Court of Appeals for the D.C. Circuit. Pending
completion of judicial review, the "negotiated rate" tariff provisions are fully
effective, although during 1997 CIG did not enter into any "negotiated rate"
transactions.
On May 30, 1997, Wyoming Interstate Company, Ltd. filed at the FERC to
increase its rates by approximately $5.7 million annually. On June 27, 1997, the
FERC accepted the filing to become effective December 1, 1997, subject to
refund. In the event the case cannot be settled, a hearing before a FERC
Administrative Law Judge is currently scheduled for May 5, 1998.
CIG, ANR Pipeline, ANR Storage Company and Wyoming Interstate Company,
Ltd., subsidiaries of the Company, are regulated by the FERC. Certain of the
above regulatory matters and other regulatory issues remain unresolved among
these companies, 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.
Environmental Matters. The Company's operations are subject to extensive
and evolving federal, state and local environmental laws and regulations. The
Company spent approximately $23 million in 1997 on environmental capital
projects and anticipates capital expenditures of approximately $35 million in
1998 in order to comply with such laws and regulations. The majority of the 1998
expenditures is attributable to projects at the Company's refining, chemical
F-38
and terminal facilities. The Company currently anticipates capital expenditures
for environmental compliance for the years 1999 through 2001 of $20 to $40
million per year. Additionally, appropriate governmental authorities may enforce
the laws and regulations with a variety of civil and criminal enforcement
measures, including monetary penalties and remediation requirements.
The Comprehensive Environmental Response, Compensation and Liability Act,
also known as "Superfund," as reauthorized, imposes liability, without regard to
fault or the legality of the original act, for disposal of a "hazardous
substance." Certain subsidiaries of the Company and a company in which Coastal
owns a 50% interest have been named as a potentially responsible party ("PRP")
in several "Superfund" waste disposal sites. At the 16 sites for which there is
sufficient information, total clean-up costs are estimated to be approximately
$313 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 seven other sites, the Environmental Protection Agency ("EPA") is
currently unable to provide the Company with an estimate of total clean-up costs
and, accordingly, the Company is unable to calculate its share of those costs.
Finally at 10 other sites, the Company has paid amounts to other PRPs or to the
EPA as its proportional share of associated clean-up costs. As to these latter
sites, the Company believes that its activities were de minimis. 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 clean-up costs to be approximately $50
million, but the Company believes that the subsidiary's activities at this site
were de minimis. At the other 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 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.
Note 16. Quarterly Results of Operations (Unaudited)
Results of operations by quarter for the years ended December 31, 1997 and
1996 were (Millions of Dollars except per share):
Quarter Ended
----------------------------------------------------------------------
March 31, 1997 June 30, 1997 Sept. 30, 1997 Dec. 31, 1997
-------------- ------------- -------------- -------------
Operating revenues......................... $ 3,205.8 $ 2,079.6 $ 2,143.0 $ 2,224.7
Less purchases............................. 2,465.4 1,396.2 1,427.9 1,497.0
---------- ----------- ---------- ----------
740.4 683.4 715.1 727.7
Other income and expenses.................. 639.2 604.1 634.7 596.5
---------- ----------- ---------- ----------
Earnings before extraordinary item......... 101.2 79.3 80.4 131.2
Extraordinary item......................... (90.6) - - -
---------- ----------- ---------- ----------
Net earnings .............................. $ 10.6 $ 79.3 $ 80.4 $ 131.2
========== =========== ========== ==========
Basic earnings per share:
Before extraordinary item............... $ .91 $ .71 $ .72 $ 1.19
Extraordinary item...................... (.85) - - -
---------- ----------- ---------- ----------
Net basic earnings per share............ $ .06 $ .71 $ .72 $ 1.19
========== =========== ========== ==========
Diluted earnings per share:
Before extraordinary item............... $ .90 $ .70 $ .71 $ 1.18
Extraordinary item...................... (.84) - - -
---------- ----------- ---------- ----------
Net diluted earnings per share.......... $ .06 $ .70 $ .71 $ 1.18
========== =========== ========== ==========
F-39
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.
Quarter Ended
----------------------------------------------------------------------
March 31, 1996 June 30, 1996 Sept. 30, 1996 Dec. 31, 1996
-------------- ------------- -------------- -------------
Operating revenues......................... $ 3,097.8 $ 2,940.1 $ 2,786.1 $ 3,342.9*
Less purchases............................. 2,360.5 2,252.4 2,089.4 2,277.5
---------- ----------- ---------- ----------
737.3 687.7 696.7 1,065.4
Other income and expenses.................. 654.8 621.6 638.1 772.4
---------- ----------- ---------- ----------
Earnings before extraordinary items........ 82.5 66.1 58.6 293.0*
Extraordinary items........................ - (12.0) - (85.6)
---------- ----------- ---------- ----------
Net earnings .............................. $ 82.5 $ 54.1 $ 58.6 $ 207.4*
========== =========== ========== ==========
Basic earnings per share:
Before extraordinary items.............. $ .74 $ .58 $ .52 $ 2.73*
Extraordinary items..................... - (.11) - (.81)
---------- ----------- ---------- ----------
Net basic earnings per share ........... $ .74 $ .47 $ .52 $ 1.92*
========== =========== ========== ==========
Diluted earnings per share:
Before extraordinary items.............. $ .73 $ .58 $ .51 $ 2.70*
Extraordinary items..................... - (.11) - (.80)
---------- ----------- ---------- ----------
Net diluted earnings per share ......... $ .73 $ .47 $ .51 $ 1.90*
========== =========== ========== ==========
* Amounts for 1996 included a gain of $272.3 million ($177 million net of
income taxes, or $1.67 per share-basic, $1.65 per share-diluted), related
to the sale of the Utah coal mining operations. Excluding the gain,
earnings before extraordinary items for 1996 amounted to $323.2 million
($2.90 per share-basic, $2.87 per share-diluted).
Note 17. Subsequent Event (Unaudited)
The Company has called for redemption on April 15, 1998 of all outstanding
shares of its $2.125 Cumulative Preferred Stock, Series H. There are 8,000,000
shares of the series currently outstanding. Redemption price for the Series H
stock is $25 per share plus accrued dividends of $.182986 to April 15, 1998.
F-40
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
Exploration
Natural and
Gas Production
Systems --------------------------
Developed Developed Undeveloped Total
--------- --------- ----------- ---------
Natural Gas (MMcf):
1997.................................................. 248,248 953,235 551,031 1,752,514
1996.................................................. 267,927 757,117 431,488 1,456,532
1995.................................................. 302,420 543,509 307,555 1,153,484
Oil, Condensate and Natural Gas Liquids (000 barrels):
1997.................................................. 349 27,016 12,778 40,143
1996.................................................. 391 30,328 13,743 44,462
1995.................................................. 126 30,400 5,764 36,290
Changes in proved reserves since the end of 1994 are shown in the following
table.
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
- --------------------- -------- ------------ ------- -----------
Total, end of 1994.............................. 334,597 623,817 11 33,666
-------- ---------- ------- ---------
Production during 1995.......................... (41,638) (85,415) (16) (4,829)
Extensions and discoveries...................... - 170,075 - 2,457
Acquisitions.................................... - 141,104 118 696
Sales of reserves in-place...................... - - - -
Revisions of previous quantity estimates and
other..................................... 9,461 1,483 13 4,174
-------- ---------- ------- ---------
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
======== ========= ======= =========
F-41
Total proved reserves for natural gas systems exclude storage gas and
liquids volumes. The natural gas systems storage gas volumes are 213,571,
153,276 and 143,134 million cubic feet and storage liquids volumes are
approximately 209,000, 192,000 and 138,000 at December 31, 1997, 1996 and 1995,
respectively. Total proved reserves for natural gas includes approximately
32,000, 90,000 and 90,000 MMcf associated with volumetric production payments
sold by the Company for the years 1997, 1996 and 1995, 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)
December 31,
--------------------
1997 1996
-------- --------
Proved and Unproved Properties:
- ------------------------------
Proved properties............................................... $ 2,006 $ 1,488
Unproved properties............................................. 108 117
-------- --------
2,114 1,605
Accumulated depreciation, depletion and amortization............ (757) (627)
-------- --------
$ 1,357 $ 978
======== ========
The Company follows the full-cost method of accounting for oil and gas
properties.
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, 1997. 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.
Years Costs Incurred
-------------------------------------------------------------
Prior to
Total 1997 1996 1995 1995
--------- --------- -------- -------- --------
Property acquisition............................. $ 58 $ 37 $ 19 $ 2 $ -
Exploration...................................... 47 34 8 5 -
Development...................................... 30 24 5 1 -
Capitalized interest............................. 4 4 - - -
--------- --------- -------- -------- ---------
$ 139 $ 99 $ 32 $ 8 $ -
========= ========= ======== ======== =========
F-42
Costs Incurred in Oil and Gas Acquisition, Exploration and Development Activities
(Millions of Dollars)
Year Ended December 31,
--------------------------------
1997 1996 1995
-------- -------- --------
Property acquisition costs:
Proved................................................................. $ 48 $ 42 $ 65
Unproved............................................................... 49 27 16
Exploration costs............................................................ 83 48 33
Development costs............................................................ 388 255 112
Results of Operations for Domestic Exploration and Production Activities
(Millions of Dollars)
Year Ended December 31,
--------------------------------
1997 1996 1995
-------- -------- --------
Revenues:
Sales..................................................................... $ 227 $ 113 $ 112
Transfers................................................................. 240 282 112
-------- -------- --------
Total.................................................................. 467 395 224
-------- -------- --------
Production costs............................................................. (92) (73) (76)
Operating expenses........................................................... (34) (32) (35)
Depreciation, depletion and amortization..................................... (171) (141) (102)
-------- -------- --------
170 149 11
Income tax (expense) benefit................................................. (52) (45) 4
-------- -------- --------
Results of operations for producing activities (excluding corporate
overhead and interest costs).............................................. $ 118 $ 104 $ 15
======== ======== ========
The average domestic amortization rate per equivalent Mcf was $0.91 in
1997, $0.88 in 1996 and $0.89 in 1995. Depreciation, depletion and amortization
excludes provisions for the impairment of international projects of $10.7
million in 1997, $14.6 million in 1996 and $0.8 million in 1995.
Standardized Measure of Discounted Future Net Cash Flows Relating to
Proved Oil and Gas Reserve Quantities. Future cash inflows from the sale of
proved reserves and estimated production and development costs as calculated by
the Company's independent engineers are discounted by 10% after they are reduced
by the Company's estimate for future income taxes. 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-43
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):
Year Ended December 31,
----------------------------------------------------------------------------------
1997 1996 1995
------------------------- ------------------------- --------------------------
Exploration Exploration Exploration
Natural Gas and Natural Gas and Natural Gas and
Systems Production Systems Production Systems Production
----------- ----------- ----------- ----------- ----------- ------------
Future cash inflows.......... $ 291 $ 4,190 $ 430 $ 5,384 $ 286 $ 2,281
Future production and
development costs......... (87) (1,479) (85) (1,432) (82) (964)
Future income tax expenses... (67) (635) (117) (1,141) (68) (294)
----------- ----------- ----------- ----------- ----------- -----------
Future net cash flows........ 137 2,076 228 2,811 136 1,023
10% annual discount for
estimated timing of
cash flows................ (57) (651) (88) (851) (61) (304)
----------- ----------- ----------- ----------- ----------- -----------
Standardized measure of
discounted future net
cash flows................ $ 80 $ 1,425 $ 140 $ 1,960 $ 75 $ 719
=========== =========== =========== =========== =========== ===========
Future cash inflows include $50 million for 1997, $245 million for 1996
and $111 million for 1995 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):
Year Ended December 31,
----------------------------------------------------------------------------------
1997 1996 1995
------------------------- ------------------------- --------------------------
Exploration Exploration Exploration
Natural Gas and Natural Gas and Natural Gas and
Systems Production Systems Production Systems Production
----------- ----------- ----------- ----------- ----------- ------------
Sales and transfers, net of
production costs.......... $ (34) $ (373) $ (45) $ (304) $ (31) $ (136)
Net changes in prices and
production costs.......... (53) (906) 95 874 46 88
Extensions and discoveries... 10 322 4 941 - 187
Acquisitions................. - 289 - 188 1 109
Sales of reserves in-place... - (117) - (27) - -
Development costs incurred
during the period that
reduced estimated future
development costs......... - 11 - 36 - 21
Revisions of previous
quantity estimates,
timing and other.......... (34) (392) 39 26 (15) (70)
Accretion of discount........ 17 233 7 57 7 49
Net change in income taxes... 34 398 (35) (550) (1) (57)
----------- ----------- ----------- ----------- ----------- -----------
Net change................... $ (60) $ (535) $ 65 $ 1,241 $ 7 $ 191
=========== =========== =========== =========== =========== ===========
None of the amounts include any value for natural gas systems storage gas
and liquids volumes, which was approximately 40 Bcf for CIG, 120 Bcf for ANR
Pipeline, 53 Bcf for Mid Michigan Gas Storage Company and 209,000 barrels of
liquids for CIG at the end of 1997.
F-44
THE COASTAL CORPORATION AND SUBSIDIARIES
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT
THE COASTAL CORPORATION
BALANCE SHEET
(Millions of Dollars)
December 31,
------------------------
1997 1996
--------- ---------
ASSETS
- ------
CURRENT ASSETS:
Cash and cash equivalents......................................................... $ .5 $ 15.6
Receivables....................................................................... 8.9 32.6
Receivables from subsidiaries..................................................... 1,150.6 1,553.9
Prepaid expenses and other........................................................ 3.4 5.7
--------- ---------
Total Current Assets........................................................... 1,163.4 1,607.8
--------- ---------
PROPERTY, PLANT AND EQUIPMENT - at cost, net......................................... .9 .9
--------- ---------
INVESTMENTS IN SUBSIDIARIES AND OTHER ASSETS:
Investment in subsidiaries at cost plus equity in undistributed earnings since
acquisition.................................................................... 3,992.4 3,625.6
Due from subsidiaries............................................................. - 324.8
Deferred federal income taxes..................................................... 54.9 18.2
Other assets...................................................................... 324.9 275.3
--------- ---------
4,372.2 4,243.9
--------- ---------
$ 5,536.5 $ 5,852.6
========= =========
See Notes to Condensed Financial Statements.
S-1
THE COASTAL CORPORATION AND SUBSIDIARIES
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT
THE COASTAL CORPORATION
BALANCE SHEET
(Millions of Dollars)
December 31,
------------------------
1997 1996
--------- ---------
LIABILITIES AND STOCKHOLDERS' EQUITY
- ------------------------------------
CURRENT LIABILITIES:
Notes payable..................................................................... $ 114.0 $ 105.0
Accounts payable and accrued expenses............................................. 92.9 57.7
Payable to subsidiaries........................................................... 171.7 756.5
Current maturities on long-term debt.............................................. 30.0 -
--------- ---------
Total Current Liabilities...................................................... 408.6 919.2
--------- ---------
DEBT:
Long-term debt.................................................................... 1,845.2 1,896.6
--------- ---------
DEFERRED CREDITS AND OTHER........................................................... .3 .3
--------- ---------
COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY.......................................... 3,282.4 3,036.5
--------- ---------
$ 5,536.5 $ 5,852.6
========= =========
See Notes to Condensed Financial Statements.
S-2
THE COASTAL CORPORATION AND SUBSIDIARIES
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT
THE COASTAL CORPORATION
STATEMENT OF OPERATIONS
(Millions of Dollars)
Year Ended December 31,
---------------------------------------
1997 1996 1995
--------- --------- ---------
OPERATING REVENUES..................................................... $ - $ - $ -
OPERATING COSTS AND EXPENSES........................................... - - -
--------- --------- ---------
OPERATING PROFIT....................................................... - - -
--------- --------- ---------
OTHER INCOME:
Equity in net earnings of subsidiaries.............................. 424.8 465.5 384.2
Interest income from subsidiaries - net............................. 63.0 119.2 152.7
Other income - net.................................................. 62.0 28.3 17.1
--------- --------- ---------
549.8 613.0 554.0
--------- --------- ---------
OTHER EXPENSES (BENEFITS):
General and administrative.......................................... 11.7 6.6 10.4
Interest and debt expense........................................... 166.9 245.4 305.8
Taxes on income..................................................... (20.9) (53.6) (32.6)
--------- --------- ---------
157.7 198.4 283.6
--------- --------- ---------
EARNINGS BEFORE EXTRAORDINARY ITEM..................................... 392.1 414.6 270.4
--------- --------- ---------
EXTRAORDINARY ITEM, NET OF INCOME TAXES:
Loss on early extinguishment of debt................................ (90.6) (12.0) -
--------- --------- ---------
NET EARNINGS........................................................... $ 301.5 $ 402.6 $ 270.4
========= ========= =========
See Notes to Condensed Financial Statements.
S-3
THE COASTAL CORPORATION AND SUBSIDIARIES
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT
THE COASTAL CORPORATION
STATEMENT OF CASH FLOWS
(Millions of Dollars)
Year Ended December 31,
---------------------------------------
1997 1996 1995
--------- --------- ---------
Net Cash Flow From Operating Activities:
Earnings before extraordinary item.................................. $ 392.1 $ 414.6 $ 270.4
Items not requiring (providing) cash:
Depreciation, depletion and amortization......................... .1 .1 .1
Deferred income taxes............................................ (25.1) 44.8 (22.0)
Undistributed subsidiary earnings................................ (363.7) (340.9) (260.9)
Working capital and other changes, excluding changes relating to
cash and non-operating activities:
Receivables................................................... 1.8 30.1 (29.5)
Prepaid expenses and other.................................... (.5) (.3) 1.2
Accounts payable and accrued expenses......................... 82.6 (76.2) 25.7
Other......................................................... (39.9) (24.2) (11.1)
--------- --------- ---------
47.4 48.0 (26.1)
--------- --------- ---------
Cash Flow from Investing Activities:
Purchases of property, plant and equipment.......................... (.1) (.1) (.1)
Net change in accounts with subsidiaries............................ 143.2 903.8 12.4
Investments in subsidiaries......................................... (2.5) (77.2) -
Proceeds from investments........................................... - - 19.3
--------- --------- ---------
140.6 826.5 31.6
--------- --------- ---------
Cash Flow from Financing Activities:
Increase (decrease) in short-term notes............................. 259.0 (268.2) 322.7
Proceeds from issuing common stock.................................. 7.3 14.7 10.5
Proceeds from long-term debt issues................................. 523.4 - 218.5
Payments to retire long-term debt................................... (933.1) (549.1) (500.6)
Dividends paid...................................................... (59.7) (59.6) (59.3)
--------- ---------- ---------
(203.1) (862.2) (8.2)
--------- --------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents................... (15.1) 12.3 (2.7)
Cash and Cash Equivalents at Beginning of Year......................... 15.6 3.3 6.0
--------- --------- ---------
Cash and Cash Equivalents at End of Year............................... $ .5 $ 15.6 $ 3.3
========= ========= =========
See Notes to Condensed Financial Statements.
S-4
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 $178.5 million, $279.0 million
and $333.5 million in 1997, 1996 and 1995, respectively. Cash payments (refunds
- - primarily from subsidiaries) for income taxes amounted to $(97.9) million,
$(41.9) million and $(44.5) million for 1997, 1996 and 1995, respectively.
Federal Income Taxes -- The Company follows the liability method of
accounting for income taxes as required by the provisions of FAS 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 $270.5 million of guaranteed
long-term debt of subsidiaries was outstanding at December 31, 1997, 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 1997 are (Millions of Dollars):
1998........... $ 30.0 2001.......... $ 84.1
1999........... 245.0 2002.......... 250.0
2000........... 121.3
Note 4. Dividends Received
Cash dividends received from consolidated subsidiaries were as follows:
1997 - $61.1 million, 1996 - $124.6 million and 1995 - $123.3 million.
S-5
THE COASTAL CORPORATION AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(Millions of Dollars)
Additions
Balance at Charged to Balance
Beginning Costs and at End
Description of Year Expenses Other of Year
- ---------------------------- ---------- ---------- --------- -------
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
===== ===== ===== =======
Year Ended December 31, 1995
- ----------------------------
Allowance for doubtful accounts.................... $19.0 $ 4.9 $(2.5)(A) $ 21.4
===== ===== ===== =======
- --------
(A) Accounts charged off net of recoveries.
S-6
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.
10.8* The Coastal Corporation Amended and Restated Deferred Compensation
Plan for Directors, effective October 9, 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.
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.
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.
10.19* Agreement for Consulting Services between The Coastal Corporation
and Oscar S. Wyatt, Jr. dated August 1, 1997.
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.