================================================================================
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, 1996 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
---------------------------
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:ior Debentures
Class A Common Stock ($.33-1/3 par value)
---------------------------
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. [X]
As of March 12, 1997, there were outstanding 105,451,513 shares of common
stock, 380,099 shares of Class A common stock, 59,068 shares of $1.19 Cumulative
Convertible Preferred Stock, Series A, 72,398 shares of $1.83 Cumulative
Convertible Preferred Stock, Series B, 31,940 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 $4.3 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 1997 Annual Meeting of
Stockholders, filed pursuant to Regulation 14A under the Securities Exchange Act
of 1934, referred to in Part III hereof.
================================================================================
<PAGE>
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................................................... 4
ANR Storage Company........................................ 5
Gas System Reserves........................................ 5
Wyoming Interstate Company, Ltd............................ 6
Great Lakes Gas Transmission Limited Partnership........... 6
Coastal Gas Services Company............................... 6
Regulations Affecting Gas Systems.......................... 7
Other Developments......................................... 9
Refining, Marketing and Distribution, and Chemicals............ 10
Exploration and Production..................................... 13
Coal........................................................... 17
Power.......................................................... 18
Other Operations............................................... 20
Competition.................................................... 20
Environmental.................................................. 20
2. Properties......................................................... 21
3. Legal Proceedings.................................................. 22
4. Submission of Matters to a Vote of Security Holders................ 22
PART II
5. Market for the Registrant's Common Equity and Related Stockholder
Matters ........................................................... 23
6. Selected Financial Data............................................ 24
7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.............................................. 24
8. Financial Statements and Supplementary Data........................ 24
9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure............................................... 24
PART III
10. Directors and Executive Officers of the Registrant................. 25
11. Executive Compensation............................................. 26
12. Security Ownership of Certain Beneficial Owners and Management..... 27
13. Certain Relationships and Related Transactions..................... 27
PART IV
14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K... 28
(i)
<PAGE>
GLOSSARY
"AICPA" means American Institute of Certified Public Accountants
"ANR Pipeline" means ANR Pipeline Company
"ANR Storage" means ANR Storage Company
"Bcf" means billion cubic feet
"BTU" means British thermal unit
"CFS" means CIG Field Services Company
"CGS" means Coastal Gas Services Company
"CIG" or "Colorado" means Colorado Interstate Gas Company
"Coastal" or "Company" means The Coastal Corporation and its subsidiaries
"Empire" means Empire State Pipeline
"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
"HIOS" means High Island Offshore System
"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
"UTOS" means U-T Offshore System
"WIC" means Wyoming Interstate Company, Ltd.
"Working Gas" means that volume of gas available for withdrawal 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.
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)
<PAGE>
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 14,700 persons as
of December 31, 1996.
Annual Reports on Form 10-K for the year ended December 31, 1996 are also
filed by Coastal's subsidiaries, ANR Pipeline and Colorado, and by the limited
partnership oil and gas drilling program, of which Coastal's subsidiary, Coastal
Limited Ventures, Inc., is the managing general partner. 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, 1996, 1995 and 1994, and the related
identifiable assets as of December 31, 1996, 1995 and 1994, 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 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, New
Jersey, Ohio, Oklahoma, Tennessee, Texas, Wisconsin, Wyoming and offshore in
federal waters. ANR Pipeline operates two offshore gas pipeline systems in the
Gulf of Mexico which are owned by HIOS and UTOS, general partnerships composed
of ANR Pipeline subsidiaries and subsidiaries of other companies. ANR Pipeline
also operates Empire, 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, 1996 consisted
of 10,600 miles of pipeline and 75 compressor stations with 1,030,069 installed
horsepower. At December 31, 1996, the design peak day delivery capacity of the
transmission system, considering supply sources, storage, markets and
transportation for others, was approximately 5.7 Bcf per day.
Colorado is involved in the production, gathering, processing,
transportation, storage and sale of natural gas. Colorado also contracts to
gather, process, transport and store natural gas owned by third parties.
Separately, Colorado
1
<PAGE>
purchases and produces natural gas and makes sales of such gas at the wellhead
principally to local gas distribution companies for resale.
On June 26, 1996, the FERC approved Colorado's request for authority to
transfer to its subsidiary, CFS, all of Colorado's gathering facilities except
for those in the Panhandle Field of Texas ("Panhandle Field"). The transferred
facilities had a net book value of approximately $42 million. The June 26, 1996
order further confirmed that the facilities transferred to CFS would be
considered non-jurisdictional. The FERC issued a related order on September 26,
1996, accepting Colorado's filing under Section 4 of the NGA, confirming that
Colorado no longer offered gathering services through the transferred
facilities. The FERC orders accepting Colorado's spin-down and related Section 4
filings were not appealed and are now final. Colorado completed the transfer to
CFS effective October 1, 1996.
Colorado's gas transmission system extends from gas production areas in the
Texas Panhandle, western Oklahoma and western Kansas, northwesterly through
eastern Colorado to the Denver area, and from production areas in Montana,
Wyoming and Utah, southeasterly to the Denver area. Colorado's gas gathering and
processing facilities are located throughout the production areas adjacent to
its transmission system. Most of Colorado's gathering facilities connect
directly to its transmission system, but some gathering systems are connected to
other pipelines. Colorado 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, at December 31, 1996
consisted of 4,123 miles of pipeline and 56 compressor stations with
approximately 300,200 installed horsepower. At December 31, 1996, the design
peak day delivery capacity of the transmission system was approximately 2.0 Bcf
per day. The underground 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 facilites
in the Panhandle Field, consist of 2,289 miles of gathering lines and
approximately 48,500 horsepower of compression. Colorado owned and operated five
gas processing plants in 1996. 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 formed CGS as a wholly-owned subsidiary in early 1993 to
consolidate its unregulated natural gas businesses. CGS and its subsidiaries
operate certain of Coastal's natural gas gathering and processing, gas supply
and marketing, price risk management and producer financing activities.
Competition
ANR Pipeline and Colorado have historically competed with interstate and
intrastate pipeline companies in the sale, transportation and storage of gas and
with independent producers, brokers, marketers and other pipelines in the
gathering, processing and sale of gas within their service areas. On October 1,
1993 and November 1, 1993, Colorado and ANR Pipeline, respectively, implemented
Order 636 on their systems. As a consequence, Colorado's gas sales contracts
have been "unbundled" at the producer wellhead and ANR Pipeline is no longer a
seller of natural gas to resale customers. In certain circumstances, the
implementation of Order 636 has resulted in capacity release, secondary delivery
point options and segmentation; thus allowing a pipeline's firm transportation
customers to compete with the pipeline for firm and interruptible transportation
and storage.
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.
ANR Pipeline's transportation, storage and balancing services are
influenced by its customers' access to alternative service providers and the
price of such services. ANR Pipeline competes directly with Panhandle Eastern
Pipe Line
2
<PAGE>
Company, Trunkline Gas Company, Northern Natural Gas Company, Natural Gas
Pipeline Company of America, Michigan Consolidated Gas Company and CMS Energy
Company in its historical market areas of Wisconsin and Michigan for its
transportation, storage and balancing business. ANR Pipeline also faces
competition in the Northeast markets from Tennessee Gas Pipeline Company, Texas
Eastern Transmission Corporation, CNG Transmission Corporation, Columbia Gas
Transmission Corporation, Iroquois Gas Transmission System, L.P.,
Transcontinental Gas Pipe Line Corporation and National Fuel Gas Supply
Corporation in serving electric generation plants and local distribution
companies. Increasingly, ANR Pipeline also competes with independent producers
and other pipeline 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.
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 $510 million for 1996 compared to
$572 million for 1995 and $555 million for 1994. During 1996, approximately 30%
of ANR Pipeline's transportation service revenues were contributed by 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 1996, 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 1996, 1995 and 1994 were as
follows:
Total System Daily Average
Year Deliveries System Deliveries
(Bcf) (MMcf)
1996 1,517 4,145
1995 1,404 3,847
1994 1,371 3,756
Gas Storage
ANR Pipeline has approximately 209 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 76 Bcf of
working gas storage capacity of which 46 Bcf is provided by Blue Lake Gas
Storage Company and 30 Bcf is provided by ANR Storage. Excluded from the 209 Bcf
is 62.1 Bcf of working gas storage capacity which ANR Pipeline has reclassified
to recoverable base gas, subject to approval by the FERC as part of ANR
Pipeline's general rate proceeding discussed below. Gas storage revenues
amounted to $131 million for both 1996 and 1995 as compared to $150 million for
1994.
3
<PAGE>
Gas Sales and Gas Purchases
With ANR Pipeline's implementation of Order 636 effective November 1, 1993,
ANR Pipeline is no longer engaged in the sale for resale of natural gas.
However, ANR Pipeline auctions gas on the open market to handle a residual
quantity of gas purchased under certain remaining gas purchase contracts pending
expiration of such contracts. ANR Pipeline's Order 636 restructured tariff
provides mechanisms for recovering from its transportation customers the pricing
differential between costs incurred to purchase gas under these contracts and
the amounts recovered through the auctioning of such gas on the open market. Gas
sales revenues realized by ANR Pipeline from the auctioning of such gas amounted
to $39 million during 1996, compared to $46 million in 1995 and $91 million in
1994. The remainder of gas sales revenues for 1995 and 1994 was primarily
attributable to the recovery of purchased gas adjustment costs incurred prior to
the implementation of Order 636.
COLORADO
Gas Sales, Storage and Transportation
Beginning in October 1993, Colorado implemented Order 636 on its system and
as a result, Colorado's gas sales contracts have been "unbundled" and such sales
are now made at the producer wellhead. Colorado's unincorporated Merchant
Division conducts most of Colorado's sales activity in the Order 636
environment. The gas sales volumes reported include those sales which continue
to be made by Colorado together with those of its Merchant Division.
Colorado has engaged in "open access" transportation and storage of gas
owned by third parties for several years. As a result of Order 636, Colorado
continues to provide these services to third parties under individual contracts.
Such services are at rates that are within minimum and maximum levels approved
by the FERC.
Pursuant to an operating agreement with an affiliate, Colorado operates the
newly completed Young Gas Storage Field located in northeastern Colorado. When
fully developed, the field will have a storage capacity of 5.3 Bcf with a
delivery rate of 200 MMcf per day. Such capacity is fully subscribed under
30-year contracts.
Colorado's deliveries for the years 1996, 1995 and 1994 were as follows:
Total System Daily Average
Year Deliveries System Deliveries
(Bcf) (MMcf)
1996 475 1,298
1995 456 1,248
1994 436 1,195
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 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, CFS, provides is not regulated by the FERC. However,
under the terms by which Colorado obtained FERC approval to transfer these
facilities to CFS, CFS offered "default contracts" to all gathering customers
receiving service at the date of the transfer. Under the "default contracts",
CFS is required to honor the rates and terms of any pre-existing gathering
contracts that were in effect as of the transfer date between Colorado and the
customers for a period of two-years. However, the "default contract" obligation
does not apply to new customers or new contracts entered into after the date of
the transfer.
4
<PAGE>
The gas processing plants recovered approximately 66 million gallons of
liquid hydrocarbons in 1996 compared to 81 million gallons in 1995, and 88
million gallons in 1994, as well as 3,100 long tons of sulfur in 1996, compared
to 4,600 long tons in 1995 and 4,300 long tons in 1994. Additionally, Colorado
processed approximately 6 million gallons of liquid hydrocarbons owned by others
in 1996, 1995 and 1994.
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
certain of its 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 three 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 46 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 the 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. Interconnecting pipelines
provide shippers with access to all other major gas producing areas in the
United States and Canada.
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 4,700 MMcf per day. Of
the 4,700 MMcf per day, 200 MMcf per day is attributable to sources connected to
facilities in the Southwest gathering area, which were sold to GPM Gas
Corporation ("GPM") in December 1996. Another 390 MMcf per day of deliverability
associated with facilities in the Southwest gathering area was spun down to ANR
Field Services Company (a wholly owned subsidiary of ANR Pipeline), also in
December 1996. All deliverability associated with mainline contiguous Southwest
gathering facilities sold in 1996 remains accessible to ANR Pipeline through
interconnections with GPM. An additional 335 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 1996, field development, newly connected gas wells, gas
production facilities and pipeline interconnections contributed over 1,380 MMcf
per day to total deliverability accessible to shippers on ANR Pipeline's
pipeline system.
5
<PAGE>
Colorado
Colorado has reported in its Form 10-K for the year ended December 31, 1996
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 Mesa Operating Company ("Mesa"), 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 Mesa.
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 500 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 (despite Order
636) 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 494 MMcf daily. In 1996,
the WIC line transported an average of 486 MMcf daily, compared to 455 MMcf
daily and 339 MMcf daily in 1995 and 1994, respectively. WIC plans to expand its
system by 193 MMcf per day and has received FERC certification of the expansion.
The expansion is estimated to be in service by August 1997.
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 933 Bcf in 1996 as compared to
953 Bcf in 1995 and 897 Bcf in 1994. 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 145 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.
COASTAL GAS SERVICES COMPANY
CGS and its subsidiaries operate the Company's unregulated natural gas
business, including certain of Coastal's natural gas gathering and processing,
gas supply and marketing, and price risk management activities. In mid-1994, CGS
expanded its functional areas to form Coastal Electric Services Company to
market electricity and provide related physical and financial services.
Additionally, in May, 1994, CGS's subsidiary, Coastal Gas Marketing Company,
accelerated its transition from a national marketing company to a North American
operation by opening Coastal Gas Marketing Canada, in Calgary, Alberta, which
focuses on Canadian markets and supplies. CGS, through its subsidiaries, managed
the sale of 1,391 Bcf of natural gas in 1996, as compared to 1,182 Bcf in 1995
and 1,047 Bcf in 1994, and processed 141 Bcf of natural gas, producing 4.3
million barrels of natural gas liquids in 1996 compared to processing 127 Bcf of
natural gas, producing 3.8 million barrels of natural gas liquids in 1995. In
1996, CGS and its affiliates conducted business with 1,174 producer and market
customers in Canada, Mexico and the United States.
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
6
<PAGE>
businesses. The combination created new entities, Engage Energy US, L.P. in
the United States and Engage Energy Canada, L.P. in Canada, which Coastal and
Westcoast will indirectly own 50% each. The new entities expect to handle
aggregate physical sales volumes of approximately 7 Bcf of natural gas per day
for more than 2,000 customers.
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, gathering and
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.
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 its processing
plants. Operations on United States government land are regulated by the
Department of the Interior.
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, and subsequent tariff filings will indicate each
time the pipeline negotiates a rate for service which exceeds the recourse rate.
The FERC is also considering comments on whether this "negotiated rate" program
should be extended to other terms and conditions of pipeline transportation
services.
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.
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 its service rates. The FERC may also initiate
proceedings to determine whether a subsidiary's rates are "just and reasonable."
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 have 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.
7
<PAGE>
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), and
remanded to the FERC, for further consideration, certain limited aspects of the
Order, such as the basis for its determination of the recovery by the pipelines
of the full level of their prudently incurred transition costs. Several persons,
including ANR Pipeline, have appealed the rate and other aspects of the FERC's
orders approving ANR Pipeline's Order 636 restructuring filings and those
appeals are the subject of further proceedings before the Court.
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 an $85.7 million increase in
the cost of service underlying that approved and 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, which rates are currently in effect, subject to refund.
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 will file exceptions as to some of the negative findings in
the Initial Decision.
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 has filed with the FERC to increase its discount recovery
adjustment in its pending rate proceeding. ANR Pipeline has sought judicial
review of these orders before the United States Court of Appeals for the D.C.
Circuit.
Claims were filed in 1990 in the United States District Court in North
Dakota by Dakota Gasification Company ("Dakota") and the United States
Department of Energy regarding ANR Pipeline's obligations under certain gas
purchase and transportation contracts with the Great Plains Coal Gasification
Plant (the "Plant"). In February 1994, ANR Pipeline, Dakota and the Department
of Energy executed a Settlement Agreement, which, subject to FERC approval,
resolves the litigation and disputes among the parties, amends the gas purchase
agreement between ANR Pipeline and Dakota and terminates the transportation
contract with the Plant. In August 1994, ANR Pipeline filed a petition with the
FERC requesting: (i) approval of the Settlement Agreement; (ii) an order
approving ANR Pipeline's proposed tariff mechanism to recover the costs incurred
to implement the Settlement Agreement; and (iii) an order dismissing a then
pending FERC proceeding wherein certain of ANR Pipeline's customers challenged
Dakota's pricing under the original gas supply contract. In December 1996, the
FERC issued an Opinion and Order Reversing Initial Decision in which it found
that the pipelines, including ANR Pipeline, were prudent in entering into the
Settlement Agreement. No appeals were taken of the FERC's decision and it has
become final.
Colorado. On March 29, 1996, Colorado filed with the FERC under Docket No.
RP96-190 to increase its rates by approximately $30 million annually and to
realign certain transportation services. On April 25, 1996, the FERC accepted
the filing to become effective October 1, 1996, subject to refund. In the event
that the case cannot be settled, a hearing before a FERC Administrative Law
Judge is currently scheduled for late 1997.
The FERC April 25, 1996 order also accepted tariff sheets filed by Colorado
to establish its rights to enter into negotiated rates consistent with the
negotiated rate Policy. Colorado's tariff sheets became effective May 1, 1996,
and continue to be effective despite the fact that certain parties have sought
judicial review of the FERC's actions with respect to Colorado's negotiated rate
provisions.
On June 26, 1996, the FERC approved Colorado's request for authority to
transfer to its subsidiary, CFS, all of Colorado's gathering facilities except
for those in the Panhandle Field. The transferred facilities had a net book
value of approximately $42 million. The June 26, 1996 order further confirmed
that the facilities transferred to CFS would be considered non-jurisdictional.
The FERC issued a related order on September 26, 1996, accepting Colorado's
filing
8
<PAGE>
under Section 4 of the NGA, confirming that Colorado no longer offered gathering
services through the transferred facilities. The FERC orders accepting
Colorado's spin-down and related Section 4 filings were not appealed and are now
final.
Certain of the above regulatory matters and other regulatory issues remain
unresolved among CIG, 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,
results of operations or cash flows. 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.
OTHER DEVELOPMENTS
In February 1997, Coastal and Westcoast Energy Inc. ("Westcoast") concluded
agreements to create jointly owned natural gas and electricity marketing
companies for North America to operate as Engage Energy US, L.P. in the United
States and Engage Canada, L.P. in Canada. The new entities will immediately
become one of North America's largest energy service providers by combining
Coastal's and Westcoast's unregulated natural gas and electric marketing and
energy management businesses. Coastal has a 50% interest in the new companies.
In February 1997, ANR Pipeline and Transcontinental Gas Pipe Line Corp.
("Transco"), a subsidiary of The Williams Companies, signed a letter of intent
to form a joint venture known as the Independence Pipeline Co., which plans to
build and operate a new interstate natural gas pipeline (the "Independence
Pipeline") to serve markets for natural gas in the Eastern United States. The
proposed Independence Pipeline would consist of approximately 370 miles of
36-inch diameter pipe, with an initial capacity of up to 900 MMcf of gas per
day. It would extend from ANR Pipeline's existing compressor station at
Defiance, Ohio, to Transco's facilities at Leidy, Pennsylvania. Along the
proposed route, interconnections with numerous other pipelines serving the
Mid-Atlantic and Northeast regions are anticipated. Affiliates of ANR Pipeline
and Transco would each own 50 percent of the new project, with an estimated
total project investment of $630 million. The Independence Pipeline is planned
to be in service November 1999, subject to receipt of satisfactory regulatory
approvals.
In January 1997, ANR Pipeline announced an open season to gauge shipper
interest in a proposed extension of its interstate natural gas pipeline system
between Katy, Texas and Eunice, Louisiana. This 224-mile project would make
additional supplies of Texas natural gas available for transport to multiple
markets via ANR Pipeline's southeast mainline, as well as at other
interconnections.
In December 1996, Colorado's subsidiary, CFS, and Snyder Oil Corp.
announced the formation of a joint venture to operate and expand the two
companies' unregulated natural gas assets in certain geographic regions. The new
company, Great Divide Gas Services, LLC, which is owned 73% by Coastal and 27%
by Snyder Oil Corp., has combined assets in the Rocky Mountains of more than 600
miles of field pipelines, connecting 650 natural gas wells producing
approximately 165 Mcf of gas per day.
In December 1996, Coastal entered into an agreement with the Indonesian
state oil company, Pertamina, for the joint development of liquefied natural gas
("LNG") import projects and related activities in India. Pertamina, as the
world's largest producer of LNG, will supply fuel for the projects. Coastal will
develop LNG receiving terminals, natural gas pipelines, and gas-fired
combined-cycle power projects based on the availability of fuel.
Funding for certain pending and proposed natural gas pipeline projects is
anticipated to be provided through non-recourse financings in which certain of
the projects' assets and contracts will be pledged as collateral. This type of
financing typically requires the participants to make equity investments
totaling approximately 20% to 30% of the cost of the project, with the remainder
financed on a long-term basis. Equity participation by other entities will also
be considered.
9
<PAGE>
REFINING, MARKETING AND DISTRIBUTION, AND CHEMICALS
The Company has subsidiary operations involved in the purchase,
transportation and sale of refined products, crude oil, condensate and natural
gas liquids; the operation of refineries and chemical plants; the sale at retail
of gasoline, petroleum products and convenience items; petroleum product
terminaling and marketing of crude oil and refined products worldwide.
Refining
Subsidiaries of the Company operated their wholly-owned refineries at 97%
of average combined capacity in 1996 compared to 88% in 1995 and at 87% in 1994.
The aggregate sales volumes (millions of barrels) of Coastal's wholly-owned
refineries for the three years ended December 31, 1996 were 160.4 (1996), 142.3
(1995) and 136 (1994). Of the total refinery sales in 1996, 27% was gasoline,
49% was middle distillates, such as jet fuel, diesel fuel and home heating oil,
and 24% was heavy industrial fuels and other products.
The average daily processing capacity of crude oil increased approximately
6% during 1996. At December 31, 1996, average daily throughput and storage
capacity at the Company's wholly-owned operating refineries are set forth below:
<TABLE>
<CAPTION>
Refinery Location Daily Average Daily Storage
Capacity Throughput (Barrels) Capacity
(Barrels) 1996 1995 (Barrels)
--------- ---------- ---------- -----------
<S> <C> <C> <C> <C>
Aruba Aruba 210,000 188,200 145,100 8,500,000
Corpus Christi Corpus Christi, Texas 100,000 91,300 89,000 7,100,000
Eagle Point Westville, New Jersey 140,000 133,600 127,800 10,700,000
Mobile Mobile, Alabama 18,000 14,000 12,400 600,000
-------- ---------- ---------- -----------
Total 468,000 427,100 374,300 26,900,000
</TABLE>
Pacific Refining Company ("PRC") at Hercules, California has a refining
capacity of 55,000 barrels per day. In August 1995, PRC suspended processing
operations at its California refinery. The Company is operating this facility,
which was restructured in June 1996 to be a wholly-owned indirect affiliate of
the Company, as a crude and product terminal as well as for purchasing and
terminaling asphalt for sales to third parties.
In addition, Coastal's international operations include a minority
interest, through a foreign subsidiary, in a refinery located in Hamburg,
Germany which has a refining capacity of 100,000 barrels per day and a storage
capacity of 1,800,000 barrels for crude oil and 5,200,000 barrels for products.
The Company's refineries produce a full range of petroleum products ranging
from transportation fuels to paving asphalt. The refineries are operated to
produce the particular products required by customers within each refinery's
geographic area. In 1996, the products emphasized included premium gasolines and
products for specialty markets such as petrochemical feedstocks, aviation fuels
and asphalt.
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.
10
<PAGE>
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.
In January 1996, Coastal Refining & Marketing, Inc., a subsidiary of the
Company, completed the purchase of a chemical production facility at St. Helens,
Oregon. The facility includes a 360-ton-per-day urea plant, a 275-ton-per- day
ammonia plant, and a 65-ton-per-day carbon dioxide plant. The main product of
the facility is an industrial-grade urea used by the adhesives industry. Other
products include fertilizers for the agricultural and forestry industries.
Sales volumes for the three years ended December 31, 1996, are set forth
below (thousands of tons):
<TABLE>
<CAPTION>
1996 1995 1994
-------- -------- --------
<S> <C> <C> <C>
Agricultural Sales................................................... 276 242 188
Industrial Sales..................................................... 608 445 407
MTBE................................................................. 204 203 187
-------- -------- --------
Total .......................................................... 1,088 890 782
======== ======== ========
</TABLE>
Coastal Chem and the St. Helens plant compete with many nitrogen and MTBE
producers across the United States and Canada. The Company's strengths are
product quality, service, and dependability. Coastal Chem and the St. Helens
plant produce commodity products with strong price competition. Reduced rail
rates on long hauls has encouraged competition from Canadian and Eastern U.S.
producers.
The petrochemical facility in Montreal East, Quebec, Canada, acquired and
started up in 1994 by a subsidiary of Coastal, 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 and Texas refineries. The aggregate sales volumes (tons),
including purchases from other suppliers, for the three years ended December 31,
1996 were 447,900 (1996), 240,500 (1995) and 29,700 (1994).
In October 1996, the Company announced that it will build an anhydrous
ammonia production facility at Oyster Creek, Texas, with a capacity of 231,000
tons per year. The plant is expected to begin operations in November 1997 and
will serve a number of major chemical customers in the surrounding area.
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, 1996, are set forth
below (thousands of barrels):
<TABLE>
<CAPTION>
Type of Sale 1996 1995 1994
- ------------ -------- --------- --------
<S> <C> <C> <C>
Company Produced Refined Products........................................ 160,383 142,301 135,973
Refined Products Purchased from Others................................... 130,240 143,913 145,093
Natural Gas Liquids...................................................... 16,205 14,551 17,352
-------- --------- --------
Total............................... 306,828 300,765 298,418
======== ========= ========
</TABLE>
Subsidiaries of the Company market refined products and liquefied petroleum
gas at wholesale in 32 states through 269 terminals. Coastal Refining &
Marketing, Inc. serves customers primarily in the Midwest, Mississippi Valley
and the Southwest through 235 product and liquefied petroleum gas terminals in
26 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 1996, these subsidiaries' sales
volumes were 103.4 million barrels, which accounted for approximately 34% of the
total marketing and distribution sales. International subsidiaries that acquire
11
<PAGE>
feedstocks for the refineries and products for the distribution system are
located in Aruba, Bermuda, London and Singapore.
The Company completed a 3-year restructuring of its refineries in 1996,
enabling them to process higher volumes at a lower fixed cost per barrel and to
increase the yield of higher-value, light products. During 1996, the Company
continued selling, exchanging or disposing of marketing operations that cannot
be integrated with core refining assets. In 1997, Coastal plans to improve its
wholesale and retail marketing by concentrating more on the products made at its
core refineries.
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.
In September 1996, 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. The
joint venture recently completed the construction of a 4.6-mile pipeline
connecting the terminal with the Port of Muuga, one of the deepest ports on the
Baltic. The terminal operation will import and export 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 1,700 Coastal branded
outlets, with 583 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 43
states, plus the District of Columbia, Puerto Rico and 16 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 230,000 barrels daily of crude oil, condensate, natural gas liquids and
refined products. These pipelines include 226 miles of crude oil pipelines, 724
miles of refined products pipelines, and 671 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 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 1996,
throughput of crude oil pipelines averaged 14,323 barrels per day, compared to
14,441 barrels per day in 1995. In 1996, throughput of refined products and
natural gas liquid pipelines averaged 215,897 barrels per day, compared to
215,652 barrels per day in 1995.
The marine transportation fleet at December 31, 1996 consisted of 14 tug
boats, 21 oil barges, 6 owned tankers and 4 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.
12
<PAGE>
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, Montana, New
Mexico, North Dakota, Oklahoma, Texas, Utah, West Virginia, Wyoming and offshore
in the Gulf of Mexico. In addition, Coastal subsidiaries have exploration and
production rights in Colombia, Hungary, Indonesia and Peru.
In 1996, the Company's domestic exploration and production operations sold
approximately 80% of all the gas it produced to its natural gas system
affiliates. 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.
Acreage held under gas and oil mineral leases as of December 31, 1996 is
summarized as follows:
<TABLE>
<CAPTION>
Undeveloped Developed
------------------- -------------------
Area Gross Net Gross Net
------------------------------------------------------------ --------- -------- --------- --------
(Thousands of Acres)
<S> <C> <C> <C> <C>
Exploration and Production
--------------------------
United States (Domestic)
Onshore........................................... 568 391 1,078 473
Offshore.......................................... 228 107 158 113
--------- -------- --------- ---------
Total Domestic.................................... 796 498 1,236 586
--------- -------- --------- ---------
International
Colombia.......................................... 104 52 - -
Hungary........................................... 568 568 - -
Indonesia......................................... 950 238 - -
Peru.............................................. 2,974 2,974 - -
--------- -------- --------- ---------
Total International............................... 4,596 3,832 - -
--------- -------- --------- ---------
Total Exploration and Production.................. 5,392 4,330 1,236 586
--------- -------- --------- ---------
Natural Gas Systems
-------------------
Domestic Onshore....................................... - - 265 261
--------- -------- --------- ---------
Total Acreage.......................................... 5,392 4,330 1,501 847
========= ======== ========= =========
</TABLE>
The domestic net developed acreage is concentrated principally in Texas
(36%), Utah (24%), offshore Gulf of Mexico (13%), Kansas (6%) and Wyoming (6%).
Approximately 13%, 8% and 10% of the Company's total domestic net undeveloped
acreage is under leases that have minimum remaining primary terms expiring in
1997, 1998 and 1999, respectively.
13
<PAGE>
Productive wells as of December 31, 1996 are as follows (domestic):
<TABLE>
<CAPTION>
Type of Well Gross Net
------------------------------------------------------------------------------------ --------- ---------
<S> <C> <C>
Exploration and Production
--------------------------
Oil............................................................................ 3,155 964
Gas............................................................................ 1,833 820
--------- ---------
Total Exploration and Production............................................... 4,988 1,784
--------- ---------
Natural Gas Systems
-------------------
Oil............................................................................ 9 8
Gas............................................................................ 675 671
--------- ---------
Total Natural Gas Systems...................................................... 684 679
--------- ---------
Total.................................................................... 5,672 2,463
========= =========
</TABLE>
Exploration and Drilling
During 1996, Coastal's domestic subsidiaries participated in drilling 109
gross wells, 74.0 net wells, to the Company's interest. Coastal's participation
in wells drilled in the three years ended December 31, 1996, is summarized as
follows:
<TABLE>
<CAPTION>
Exploration and Production 1996 1995 1994
-------------------------- ------------------- ------------------- --------------------
Exploratory Wells Gross Net Gross Net Gross Net
----------------- -------- -------- --------- -------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
Oil...................... - - 1 0.3 1 0.2
Gas...................... 7 2.3 6 2.5 2 1.3
Dry Holes................ 4 1.9 4 2.3 5 2.9
-------- -------- --------- -------- --------- ---------
11 4.2 11 5.1 8 4.4
======== ======== ========= ======== ========= =========
Development Wells
-----------------
Oil...................... 5 1.6 22 9.8 15 6.1
Gas...................... 80 56.8 59 25.6 82 35.1
Dry Holes................ 3 1.4 1 0.1 3 2.1
-------- -------- --------- -------- --------- ---------
88 59.8 82 35.5 100 43.3
======== ======== ========= ======== ========= =========
Natural Gas Systems
-------------------
Development Wells
-----------------
Oil...................... 2 2.0 - - - -
Gas...................... 8 8.0 1 1.0 3 3.0
Dry Holes................ - - - - - -
-------- -------- --------- -------- --------- ---------
10 10.0 1 1.0 3 3.0
======== ======== ========= ======== ========= =========
Total.......................... 109 74.0 94 41.6 111 50.7
======== ======== ========= ======== ========= =========
</TABLE>
14
<PAGE>
Wells in progress as of December 31, 1996 are as follows (domestic):
<TABLE>
<CAPTION>
Type of Well Gross Net
------------------------------------------------------------------------------------------ --------- -----
<S> <C> <C>
Exploration and Production
--------------------------
Exploratory............................................................................ 2 0.9
Development............................................................................ 11 7.6
--------- -----
Total Exploration and Production....................................................... 13 8.5
--------- -----
Natural Gas Systems
-------------------
Exploratory............................................................................ - -
Development............................................................................ - -
--------- -----
Total Natural Gas Systems.............................................................. - -
--------- -----
Total.................................................................................. 13 8.5
========= =====
</TABLE>
Coastal Limited Ventures, Inc., a domestic subsidiary of Coastal, is the
general partner in a limited partnership drilling program which was offered to
Coastal's employees and shareholders. Information pertaining thereto can be
located in the Annual Report on Form 10-K filed by such limited partnership and
available from the Company.
Domestically in 1996, Coastal's exploration and production subsidiaries
more than tripled their daily production levels of gas from the Gulf of Mexico,
increasing from a net 47 MMcf of gas per day to 145 MMcf of gas per day at
year's end. Net oil and condensate production increased from 3,760 to 4,200
barrels per day. This production increase resulted from exploration and
developmental drilling on blocks in its existing inventory as well as
exploitation drilling of additional producing blocks acquired over the last two
years.
In 1996, Coastal set three platforms in the Gulf of Mexico, and plans to
construct 11 additional structures in 1997. Coastal added a total of 27 offshore
blocks to its inventory in 1996. Coastal's working interest in these blocks
ranges from 25% to 100%.
Coastal has expanded its exploration and production operations to several
international prospects, with exploration oriented primarily toward oil. The
Company expects to drill its first wildcat well on a 104,000-acre lease in
Colombia in 1997 as part of a joint venture. Coastal subsidiaries have completed
seismic studies for a 568,000-acre block in Hungary, and two wells will be
drilled before year end. In Peru, Coastal is conducting exploration activities
on 3 million acres held by a license agreement. After drilling a dry hole in
1996, Coastal, with its joint venture partner, intends to drill two wells on
prospects this year. In addition, the Company is continuing evaluation on a
block in South Central Sumatra, Indonesia, where it holds a 25% interest,
following the drilling of 2 unsuccessful wells in 1996.
Gas and Oil Production
Natural gas production during 1996 averaged 461 MMcf daily, compared to 348
MMcf daily in 1995. Production from non-pipeline-owned wells averaged 353 MMcf
daily in 1996, compared to 234 MMcf daily in 1995. Crude oil, condensate and
natural gas liquids production averaged 13,893 barrels daily in 1996, compared
to 13,273 barrels daily in 1995.
15
<PAGE>
The following table shows gas, oil, condensate and natural gas liquids
production volumes attributable to Coastal's domestic interest in gas and oil
properties for the three years ended December 31, 1996:
<TABLE>
<CAPTION>
Natural Gas
Oil Condensate Liquids
Gas (Thousands (Thousands (Thousands
Year (MMcf) of Barrels) of Barrels) of Barrels)
---- ----- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Exploration and Production
--------------------------
1996 129,149 3,885 853 324
1995 85,415 4,064 436 329
1994 79,845 3,634 428 404
Natural Gas Systems
-------------------
1996 39,405 23 - -
1995 41,638 15 1 -
1994 46,288 - 1 -
</TABLE>
Many of Coastal's domestic gas wells are situated in areas near, and are
connected to, its gas systems. In other areas, gas production is sold to
pipeline companies and other purchasers.
Generally, Coastal's domestic production of crude oil, condensate and
natural gas liquids is purchased at the lease by its marketing and refinery
affiliates. Some quantities are delivered via Coastal's gathering and
transportation lines to its refineries, but most quantities are redelivered to
Coastal through various exchange agreements.
The following table summarizes sales price and production cost information
for domestic exploration and production operations during the three years ended
December 31, 1996:
<TABLE>
<CAPTION>
1996 1995 1994
-------- -------- --------
<S> <C> <C> <C>
Average sales price:
Gas - per Mcf................................................. $ 2.19 $ 1.57 $ 1.86
Oil - per barrel.............................................. 20.28 17.43 15.87
Condensate - per barrel....................................... 20.76 16.63 15.41
Natural Gas Liquids - per barrel.............................. 21.74 15.02 8.78
Average production cost per unit (equivalent Mcf)................ 0.51 0.74 0.67
</TABLE>
Natural Gas Processing
ANR Production Company and Coastal Oil & Gas Corporation, domestic
subsidiaries of the Company, are also engaged in the processing of natural gas
for the extraction and sale of natural gas liquids. In 1996, these subsidiaries
extracted and sold 231 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, 1996, as estimated by Huddleston, its independent
engineers, were 44.5 million barrels, compared to 36.3 million barrels at the
end of 1995. Proved gas reserves as of December 31, 1996, net to Coastal's
interest, were estimated by the engineers to be 1,456.5 Bcf compared to 1,153.5
Bcf as of December 31, 1995. In 1996, reserve additions were more than triple
the production volumes.
16
<PAGE>
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 proxi mity, 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.
COAL
The Company restructured its eastern coal operations in December 1996.
Through the newly formed ANR Coal Company, LLC ("ANR Coal") and its operations
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, with reserves of approximately 300 million tons,
for approximately $610 million in cash to a limited liability company jointly
owned by subsidiaries of Atlantic Richfield Co. and ITOCHU Corp. Information
concerning the western coal operations is set forth in Note 10 of the Notes to
Consolidated Financial Statements included herein.
At December 31, 1996, coal properties consisted of the following:
<TABLE>
<CAPTION>
Coal Holdings (Acres) Clean,
----------------------------------------------
Leased Recoverable
Owned Exchanged Total Tons
-------------------------------
Fee Mineral Surface (Net) Acres (Millions)<F1>
-------- --------- -------- --------- -------- -------------
<S> <C> <C> <C> <C> <C> <C>
Kentucky......................... 14,275 76,287 2,275 23,139 115,976 204
Virginia......................... 24,353 36,935 2,084 13,515 76,887 161
West Virginia.................... 402 55,823 7,950 128,865 193,040 201
-------- --------- -------- -------- -------- ------
Total...................... 39,030 169,045 12,309 165,519 385,903 566
======== ========= ======== ======== ======== ======
- ------------------------
<FN>
<F1> Based on a 65% recovery rate.
</FN>
</TABLE>
17
<PAGE>
At December 31, 1996, the Company controlled approximately 566 million
recoverable tons of bituminous coal reserves and resources. Production in 1996
from ANR Coal's reserves totalled 8.8 million tons, of which 6.1 million tons
were produced from captive operations and 2.7 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 four company mines operated by ANR Coal
in Kentucky and West Virginia. Captive production and clean coal processed from
these mines totalled one million tons in 1996.
Captive sales from ANR Coal were 7.0 million tons in 1996. Brokerage sales
in which the Company receives a commission totalled 1.3 million tons for the
same period.
In 1996, approximately 69% of the captive sales were to domestic utilities,
9% of the sales were to domestic industrial customers and 22% of the sales were
to export markets in Europe, Canada and South America. Nearly one million tons
of ANR Coal's production were sold to domestic and foreign metallurgical
markets. Of the total 1996 tonnage sold, 5.5 million tons (79%) were sold under
long-term contracts. At December 31, 1996, the weighted average remaining life
of these contracts was 40 months.
The Company had approximately 12.4 million tons of annual production
capacity at December 31, 1996 from six coal preparation plants and nine 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 448 million tons of lignite
reserves in North Dakota. Production from these reserves in 1996 totalled 12.9
million tons.
The Company, through its captive operations, leasing programs and brokerage
activities, participates in all aspects of the eastern bituminous coal industry
and is a significant competitor in international metallurgical coal markets. A
significant portion of its reserves are low-sulfur, compliance coal which will
allow the Company to remain a major supplier of steam coal to domestic utilities
under the Clean Air Act Amendments of 1990.
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 four
foreign operating independent power projects, as well as interests in other
projects in various stages of development.
Capitol District Energy Center Cogeneration Associates ("CDECCA") owns a
combined-cycle cogeneration project 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 equity partner of CDECCA.
An affiliate of Coastal Power is the managing partner and 50-percent owner
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 is provided to the cogeneration plant by other Coastal
affiliates. CTI is the operator of the cogeneration plant.
18
<PAGE>
Fulton Cogeneration Associates owns a cogeneration facility with a capacity
of approximately 47 megawatts, located in Fulton, New York. This facility 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 plant in Michigan, which is the largest cogeneration
facility in the United States. 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 48.5% 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 had an initial capacity of
approximately 91 megawatts. A 53 megawatt expansion began operations in the
second quarter of 1996. Coastal Power, through its affiliates, currently
receives approximately 86.6% of the distributable cash flow and an unrelated
investor receives the remainder. Coastal affiliates provide fuel for this
project. 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 in April 1995. 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 Wuxi New District Ltd., an affiliate of Coastal Power, together
with two Chinese partners, formed a Sino-foreign joint venture company to own,
construct, and operate a 40 megawatt diesel-fired peaking plant adjacent to the
existing 40 megawatt power plant in Wuxi City. Coastal Wuxi New District Ltd.
owns a 60% equity interest in the joint venture. This project is expected to be
operational in 1997.
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 in October 1995. 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. Power is sold to the local utility under a
long-term contract. 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 development 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 is expected to
commence operations in May of 1997 and will sell power to the local utility
under a long-term contract.
19
<PAGE>
A subsidiary of Coastal Power holds a 50% voting interest in a 140-megawatt
capacity natural gas-fired power plant in Quetta, Pakistan, with an unrelated
entity holding the remaining 50%. The power from the project will be sold to the
national utility under a long-term contract. Construction is expected to be
completed in late 1997.
In early 1997, a subsidiary of Coastal Power completed negotiations to
build and operate a 114-megawatt capacity heavy-fuel oil project in Farouqabad,
Pakistan. The Coastal Power subsidiary will initially hold a 90.75% equity
interest in the project. The power from the project will be sold to the national
utility under a long-term contract, with operations expected to commence in
early 1999.
Competition
Coastal is subject to competition with other energy organizations and
utilities seeking to develop and acquire independent power operations. Due to an
excess of generation capacity in the domestic market, Coastal and many other
power producers are concentrating their efforts abroad, where the demand for
independent power production is greater and opportunities exist for greater
rates of return. International competition continues to increase as the world
market for independent power production develops and power purchasers employ
competitive bidding for project awards. In the United States and international
locations, the sale of power and the operation of power cogeneration facilities
are regulated by the applicable laws, rules and regulations of the respective
governments and agencies having jurisdiction.
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. Due to the merger in 1995, trucking operations do not
constitute a business segment of the Company.
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 $37 million in 1996 on environmental capital projects and
anticipates capital expenditures of approximately $42 million in 1997 in order
to comply with such laws and regulations. The majority of the 1997 expenditures
is attributable to construction projects at the Company's refining, chemical and
terminal facilities. The Company currently anticipates capital expenditures for
environmental compliance for the years 1998 through 2000 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.
20
<PAGE>
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
$333 million, and the Company estimates its pro-rata exposure, to be paid over a
period of several years, is approximately $7.4 million and has made appropriate
provisions. At 4 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 subsidiaries' 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
$40,000 and suitable remediation. There is not sufficient information to
estimate the remedial costs or the Company's pro-rata exposure at this site.
In October 1996, the New Jersey Department of Environmental Protection
issued an administrative order and notice of civil administration assessment
(the "Order") to Coastal Eagle Point Oil Company ("CEPOC"), a subsidiary of
Coastal. The Order alleged that sulphur dioxide emissions from the sulfur
recovery unit and carbon monoxide from the marine thermal oxidizer at CEPOC's
New Jersey refinery exceeded the permit limits during the last quarter of 1995.
CEPOC and the State of New Jersey have tentatively negotiated a settlement
agreement of approximately $262,400 for the alleged violations and remaining
emission violations incurred in 1996. CEPOC is awaiting final approval from the
state.
In January 1996, the EPA Region II issued a Notice of Violation to CEPOC
and the Eagle Point Cogeneration Partnership, in which Coastal has an indirect
50% interest. The EPA's Notice alleges certain violations of air and operating
permits at the New Jersey facility, but the EPA has not specified the relief it
is seeking. The Company believes that this action could result in monetary
sanctions which, while not material to the Company and its subsidiaries, could
exceed $100,000.
In January 1993, the State of Texas filed suit against the Corpus Christi,
Texas refinery of Coastal Refining & Marketing, Inc., a subsidiary of the
Company, 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 and seeking penalties in unspecified amounts.
The Texas Natural Resources Conservation Commission is currently involved in
negotiating an agreed upon penalty settlement among the parties. The Company
believes that this suit could result in monetary sanctions which, while not
material to the Company and its subsidiaries, could exceed $100,000.
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 liquidity, consolidated financial
position or results of operations.
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
21
<PAGE>
pipelines and necessary land or other property for compressor and other stations
and equipment necessary to the operation of pipelines.
Item 3. Legal Proceedings.
A subsidiary of Coastal initiated a suit against TransAmerican Natural Gas
Corporation ("TransAmerican") in the District Court of Webb County, Texas for
breach of two gas purchase agreements. In February 1993, TransAmerican filed a
Third Party Complaint and a Counterclaim in this action against Coastal and
certain subsidiaries. TransAmerican alleged breach of contract, fraud,
conspiracy, duress, tortious interference and violations of the Texas Free
Enterprises and Anti-trust Act arising out of the gas purchase agreements. Final
judgment in this matter was entered April 22, 1994. The subsidiary was awarded
approximately $2.0 million, including pre-judgment interest and attorney fees.
All of TransAmerican's claims and causes of action were denied. The Court of
Appeals for the Fourth Judicial District has denied TransAmerican's appeal in
this case. TransAmerican subsequently filed a Writ of Error with the Texas
Supreme Court, which was denied in December 1996. In January 1997, TransAmerican
filed a motion for rehearing of its Writ of Error, which is pending before the
Texas Supreme Court.
In December 1992, certain of Colorado'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 Colorado 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 Colorado, 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 Colorado. On June 7, 1995, the Trial Court entered a judgment that
the lessors recover no monetary damages from Colorado and permanently estopping
the lessors from asserting any claim based on an interpretation of the contract
different than that asserted by Colorado in the litigation. The lessors' motion
for a new trial is pending. On June 7, 1996, the same plaintiffs sued Colorado
in state court in Amarillo, Texas for underpayment of royalties. Colorado
removed the second lawsuit to federal court which granted a stay of the second
suit pending the outcome of the first lawsuit.
A natural gas producer has filed a claim on behalf of the U.S. government
in the U.S. District Court for the District of Columbia under the federal False
Claims Act. The Second Amended Complaint filed on May 24, 1996, against seventy
(70) defendants, including ANR Pipeline, CIG and Coastal States Gas Transmission
Company, alleges that the defendants' methods of measuring the heating content
and volume of natural gas purchased from federally-owned or Indian properties
have caused underpayment of royalties to the U.S. government. The Company's
subsidiaries, together with the other pipeline defendants, have filed a motion
to dismiss.
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 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.
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,
results of operations or cash flows.
Item 4. Submission of Matters to a Vote of Security Holders.
None.
22
<PAGE>
PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters.
The principal market on which Coastal Common Stock is traded is the New
York Stock Exchange; Coastal Common Stock is also listed on The Stock Exchange
in London, the Stock Exchanges of Dusseldorf, Frankfurt, Hamburg and Munich in
Germany and on the Amsterdam Stock Exchange. The Class A Common Stock of Coastal
is non-transferable; however, such stock is convertible share-for-share into
Coastal Common Stock. As of March 12, 1997, the approximate number of holders of
record of Common Stock was 8,850 and of the Class A Common Stock was 3,220.
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.
<TABLE>
<CAPTION>
1996 1995
----------------------------------- ------------------------------------
Quarters High Low Dividends High Low Dividends
- -------------------- -------- ----- --------- -------- ----- ---------
<S> <C> <C> <C> <C> <C> <C>
First Quarter $40.75 $34.88 $.10 $29.50 $25.13 $.10
Second Quarter 43.75 36.25 .10 31.75 28.38 .10
Third Quarter 43.88 37.00 .10 34.25 30.25 .10
Fourth Quarter 51.50 40.81 .10 37.75 31.13 .10
</TABLE>
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 1996 and 1995. At December 31, 1996, 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 $598.8 million.
23
<PAGE>
Item 6. Selected Financial Data.
The following selected financial data (in millions of dollars except per
share amounts) is derived from the Consolidated Financial Statements included
herein and Item 6 of the Company's Annual Report on Form 10-K for the fiscal
year ended December 31, 1995, as adjusted for minor reclassifications. The Notes
to Consolidated Financial Statements included herein contain other information
relating to this data.
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------------------------------------
1996*** 1995 1994 1993 1992
----------- ------------ ------------ ------------ ----------
<S> <C> <C> <C> <C> <C>
Operating revenues $ 12,166.9 $ 10,457.6 $ 10,226.2 $ 10,147.2 $ 10,073.7
Earnings (loss) before extraordinary items* 500.2 270.4 232.6 118.3 (126.8)
Net earnings (loss)* 402.6 270.4 232.6 115.8 (126.8)
Earnings (loss) per common and common
equivalent share before extraordinary
items* 4.54 2.40 2.05 1.02 (1.23)
Net earnings (loss) per common and
common equivalent share* 3.62 2.40 2.05 1.00 (1.23)
Cash dividends per common share** .40 .40 .40 .40 .40
Total assets 11,613.1 10,658.8 10,534.6 10,227.1 10,579.8
Debt, excluding current maturities 3,526.1 3,661.7 3,720.2 3,812.5 4,306.1
Preferred stock of subsidiaries,
excluding current maturities 100.0 .6 .6 26.6 36.7
<FN>
* Amounts for 1996 include $177 million, or $1.66 per share, relating to the
sale of the Utah coal mining operations.
** In addition, cash dividends of $.36 per share were paid on the Company's
Class A Common Stock in 1996, 1995, 1994, 1993 and 1992.
*** 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.
</FN>
</TABLE>
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.
The Management's Discussion and Analysis of Financial Condition and Results
of Operations is presented on pages F-1 through F-9 hereof.
Item 8. Financial Statements and Supplementary Data.
The Financial Statements and Supplementary Data required hereunder are
included in this Annual Report as set forth in Item 14(a) hereof.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
None.
24
<PAGE>
PART III
Item 10. Directors and Executive Officers of the Registrant.
The information called for by this Item with respect to the directors is
set forth under "Election of Directors" and "Information Regarding Directors" in
the Coastal Proxy Statement for the May 8, 1997 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 12, 1997, were as
follows:
Name (Age), Year First Positions and Offices with the
Elected An Officer Registrant
- ------------------------------- -----------------------------------
O. S. Wyatt, Jr. (72), 1955 Chairman of the Board of Directors
David A. Arledge (52), 1982 President, Chief Executive Officer,
Chief Financial Officer and
Director
Coby C. Hesse (49), 1986 Executive Vice President
James A. King (57), 1992 Executive Vice President
Jerry D. Bullock (67), 1992 Senior Vice President
Jeffrey A. Connelly (50), 1988 Senior Vice President
Carl A. Corrallo (53), 1993 Senior Vice President and General
Counsel
Donald H. Gullquist (53), 1994 Senior Vice President
Dan J. Hill (56), 1978 Senior Vice President
Kenneth O. Johnson (76), 1978 Senior Vice President and Director
Austin M. O'Toole (61), 1974 Senior Vice President and Secretary
Jack C. Pester (62), 1987 Senior Vice President
James L. Van Lanen (52), 1985 Senior Vice President
M. Truman Arnold (68), 1993 Vice President
Daniel F. Collins (55), 1989 Vice President
Robert C. Hart (52), 1994 Vice President
Thomas E. Jackson (57), 1997 Vice President
Jeffrey B. Levos (36), 1997 Vice President and Controller
John J. Lipinski (46), 1995 Vice President
Edward A. More'(48), 1995 Vice President
M. Frank Powell (46), 1993 Vice President
Keith O. Rattie (42), 1996 Vice President
Thomas M. Wade (44), 1995 Vice President
Ronald D. Matthews (49), 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 for five years or more with the following
exceptions:
Mr. Arnold was elected Vice President of Coastal in August 1993. He has
been a Vice President of Coastal States Management Corporation, a subsidiary of
Coastal, since 1977.
Mr. Bullock was elected Senior Vice President of Coastal in August 1992.
From 1987 to 1990, he was an Executive Vice President of British Petroleum's BP
Exploration Company and a director and a member of the management committee of
BP Exploration USA. From 1990 to 1992, he was an independent petroleum
consultant for several major exploration companies.
25
<PAGE>
Mr. Corrallo was elected Senior Vice President and General Counsel of
Coastal in March 1993. He has served as a Senior Vice President of Coastal
States Management Corporation, a subsidiary of Coastal, since August 1991 and
prior thereto as Vice President since December 1986.
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. King was elected Executive Vice President of Coastal in May 1992. From
1987 to 1990, he was Senior Vice President of refining, supply and
transportation for Crown Central Petroleum Corporation.
Mr. Levos was elected Vice President and Controller of Coastal in March
1997. He has served as Vice President of Coastal States Management Corporation,
a subsidiary of Coastal, since December 1995 and also served as General Auditor
since July 1994. Prior thereto, he was a Certified Public Accountant with the
Houston office of Deloitte & Touche LLP since January 1986.
Mr. Lipinski was elected Vice President of Coastal in March 1995. He has
held various positions with subsidiaries of Coastal since 1985.
Mr. Matthews was elected Treasurer of the Company and Vice President and
Treasurer of ANR Pipeline in September 1994. He was also elected Vice President
and Treasurer of Colorado in October 1994. He has served as Assistant Treasurer
of Coastal since 1983 and as Vice President of Coastal States Management
Corporation, a subsidiary of Coastal, since 1991.
Mr. More was elected Vice President of Coastal in March 1995. He has held
various positions with subsidiaries of Coastal since 1991. Prior thereto, he
served as Executive Vice President at Harken Marketing, Inc. from 1987 to 1991.
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.
Mr. Wade was elected Vice President of Coastal in March 1995. He has held
various positions with subsidiaries of Coastal since 1980.
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 8, 1997
Annual Meeting of Stockholders filed pursuant to Regulation 14A under the
Securities Exchange Act of 1934, and is incorporated herein by reference.
26
<PAGE>
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 8, 1997 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 Management and Others" in the Coastal Proxy
Statement for the May 8, 1997 Annual Meeting of Stockholders filed pursuant to
Regulation 14A under the Securities Exchange Act of 1934, and is incorporated
herein by reference.
27
<PAGE>
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a) The following documents are filed as part of this Annual Report or
incorporated herein by reference:
1. Financial Statements and Supplemental Information.
The following Consolidated Financial Statements of Coastal and
Subsidiaries and Supplemental Information are included in response to
Item 8 hereof on the attached pages as indicated:
<TABLE>
<CAPTION>
Page
<S> <C>
Independent Auditors' Report.................................................................... F-10
Statement of Consolidated Operations for the years ended December 31, 1996, 1995 and 1994....... F-11
Consolidated Balance Sheet at December 31, 1996 and 1995........................................ F-12
Statement of Consolidated Cash Flows for the years ended December 31, 1996, 1995 and 1994....... F-14
Statement of Consolidated Common Stock and Other Stockholders' Equity for the years ended
December 31, 1996, 1995 and 1994............................................................. F-15
Notes to Consolidated Financial Statements...................................................... F-16
Supplemental Information on Oil and Gas Producing Activities (Unaudited)........................ F-38
</TABLE>
2. Financial Statement Schedules.
The following schedules of Coastal and Subsidiaries are included on the
attached pages as indicated:
<TABLE>
<CAPTION>
Page
<S> <C>
Schedule I - Condensed Financial Information of the Registrant............................. S-1
Schedule II - Valuation and Qualifying Accounts............................................. S-6
</TABLE>
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).
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).
28
<PAGE>
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 Stock Grant Plan, effective December
1, 1988 (Exhibit 10.12 to Coastal's Annual Report on Form 10-K
for the fiscal year ended December 31, 1988).
10.8+ The Coastal Corporation Deferred Compensation Plan for
Directors (Exhibit 10.13 to Coastal's Annual Report on Form
10-K for the fiscal year ended December 31, 1988).
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+ Employment Agreement between The Coastal Corporation and James
F. Cordes dated April 12, 1990 (Exhibit 10.13 to Coastal's
Annual Report on Form 10-K for the fiscal year ended December
31, 1990).
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).
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.
11* Statement re Computation of Per Share Earnings.
21* Subsidiaries of Coastal.
29
<PAGE>
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,
1996.
30
<PAGE>
POWERS OF ATTORNEY
Each person whose signature appears below hereby appoints David A. Arledge,
Coby C. Hesse and Austin M. O'Toole and each of them, any one of whom may act
without the joinder of the others, as his attorney-in-fact to sign on his behalf
and in the capacity stated below and to file all amendments to this Annual
Report on Form 10-K, which amendment or amendments may make such changes and
additions thereto as such attorney-in-fact may deem necessary or appropriate.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
THE COASTAL CORPORATION
(Registrant)
By: DAVID A. ARLEDGE
-------------------------------------
David A. Arledge
President and Chief Executive Officer
March 25, 1997
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: O. S. WYATT, JR.
-------------------------------------
O. S. Wyatt, Jr.
Chairman of the Board
March 25, 1997
By: DAVID A. ARLEDGE
-------------------------------------
David A. Arledge
Principal Financial Officer and Director
March 25, 1997
By: COBY C. HESSE
-------------------------------------
Coby C. Hesse
Principal Accounting Officer
March 25, 1997
By: JOHN M. BISSELL
-------------------------------------
John M. Bissell
Director
March 25, 1997
* * *
31
<PAGE>
By: GEORGE L. BRUNDRETT, JR.
-------------------------------------
George L. Brundrett, Jr.
Director
March 25, 1997
By: HAROLD BURROW
-------------------------------------
Harold Burrow
Director
March 25, 1997
By: ROY D. CHAPIN, JR.
-------------------------------------
Roy D. Chapin, Jr.
Director
March 25, 1997
By: JAMES F. CORDES
-------------------------------------
James F. Cordes
Director
March 25, 1997
By: ROY L. GATES
-------------------------------------
Roy L. Gates
Director
March 25, 1997
By: KENNETH O. JOHNSON
-------------------------------------
Kenneth O. Johnson
Director
March 25, 1997
By: JEROME S. KATZIN
-------------------------------------
Jerome S. Katzin
Director
March 25, 1997
By: THOMAS R. McDADE
-------------------------------------
Thomas R. McDade
Director
March 25, 1997
By: L. D. WOODDY, JR.
-------------------------------------
L. D. Wooddy, Jr.
Director
March 25, 1997
32
<PAGE>
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 in the near future; however, many factors which may affect the
actual results, including commodity prices, market conditions, industry
competition and changing regulations, are difficult to predict. Accordingly,
there is no assurance that the Company's expectations will be realized.
The Notes to Consolidated Financial Statements contain information that is
pertinent to the following analysis.
Liquidity and Capital Resources
The Company uses the following consolidated ratios to measure liquidity and
ability to meet future funding needs and debt service requirements.
<TABLE>
<CAPTION>
1996 1995 1994
-------- -------- --------
<S> <C> <C> <C>
Net return on average common stockholders' equity............................ 14.8% 10.8% 10.0%
Cash flow from operating activities to long-term debt........................ 15.9% 17.7% 18.0%
Total debt to total capitalization........................................... 53.7% 59.4% 61.7%
Times interest earned (before tax)........................................... 2.5 1.8 1.8
</TABLE>
The above ratios reflect increased earnings and decreased long-term debt in
both 1996 and 1995. The 1996 and 1995 decreases in the cash flow from operating
activities to long-term debt ratio resulted from changes in working capital and
distributed/undistributed earnings from equity investments as well as increased
earnings.
Cash flows provided from operating activities were $561.4 million in 1996,
$649.1 million in 1995 and $669.1 million in 1994. The 1996 decrease is due to
increased working capital requirements and an increase in undistributed earnings
from equity investments partially offset by increased earnings. The decrease for
1995 can be primarily attributed to increases for working capital requirements
partially offset by increased earnings and an increase in distributed earnings
from equity investments.
Capital expenditures amounted to $880.8 million, $626.8 million and $543.2
million in 1996, 1995 and 1994, respectively. The 1996 increase is 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 1996 production. Property additions also increased in the Natural Gas
segment due to the acquisition of additional storage facilities and increased
expenditures for the regulated 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.
The increased capital expenditures in 1995 were due to expansion of the earnings
bases in the Natural Gas and Exploration and Production segments.
Proceeds from the sale of property, plant and equipment 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. The liquid pipelines sale
resulted in the $79.5 million increase in 1995. Additions to investments
increased in 1996 primarily due to investments in power projects and gas
pipeline ventures, while the 1995 increase resulted from investments in power
projects. Proceeds from the sale of investments decreased in 1995 as a result of
the Company's sale in 1994 of exploration and production interests in Argentina.
The Company received proceeds of approximately $610.1 million in December 1996
from the sale of its Utah coal mining operations.
The Company was able to reduce total debt by $274.3 million and $49.3
million in 1996 and 1995, respectively. The 1996 reduction is primarily due to
the use of proceeds from the sale of the Utah coal mining operations, while the
1995 reduction was primarily by the use of internally generated funds and other
financial transactions. The 1995 change
F-1
<PAGE>
in redemption of mandatory redemption preferred stock is due to ANR Pipeline
Company ("ANR Pipeline") redeeming all shares of its outstanding Cumulative
Preferred Stock in 1994. In December 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 1997, including the Company's equity investments
in partnerships and joint ventures, are currently projected at approximately
$920 million; 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.
On December 20, 1996, the Company completed the sale of its Utah coal
mining operations for approximately $610.1 million in cash. The sale resulted in
a gain before income taxes of $272.3 million. The net earnings from the sale was
a gain of $177.0 million, or $1.66 per share. See Note 10 of the Notes to
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 new entities in which Coastal and Westcoast
indirectly own 50% each.
The interstate natural gas pipelines and certain storage subsidiaries of
the Company are subject to the regulations and accounting procedures of the
Federal Energy Regulatory Commission ("FERC"). These subsidiaries have
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. The accounting change was made because the
Company concluded that the competitive environment for these subsidiaries was no
longer consistent with the form of regulation contemplated by FAS 71. The net
impact of the change was a charge to earnings of $85.6 million, net of related
income taxes of $50.0 million, and is shown as an extraordinary item in the
Statement of Consolidated Operations. The charge to earnings was noncash and
will have no effect on the subsidiaries' ability to include the underlying
deferred items in their future rate proceedings or on their ability to collect
the rates set thereby. The Company does not expect the change to have a material
adverse impact on financial results in future periods, and believes that the
change will result in financial reporting which better reflects the results of
operations in the economic environment in which these subsidiaries operate. See
Note 13 of the Notes to Consolidated Financial Statements.
Financing for budgeted expenditures and mandatory debt retirements in 1997
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, 1996 were as follows (millions of
dollars):
Short-term.................................................. $ 967.3
Long-term*.................................................. 688.0
--------
$1,655.3
*$52.4 million of unused long-term credit lines is dedicated to a specific
use.
In February 1997, the Company purchased and retired $798 million of debt
securities 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 will incur an after-tax extraordinary charge in the first
quarter of 1997 of approximately $90 million in connection with the repurchase
of these debt securities.
F-2
<PAGE>
Also in February 1997, the Company issued $200.0 million of 6.7% 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.
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, 1996, net assets of
consolidated subsidiaries amounted to approximately $5.6 billion, of which
approximately $1.3 billion was restricted. These provisions have not and are not
expected to have any meaningful impact on the ability of the Company to meet its
cash obligations.
The Company's operations involve managing market risks related to changes
in interest rates and foreign exchange rates. Derivative financial instruments,
specifically interest rate swaps and foreign currency swaps, are used to reduce
and manage these risks. The Company currently does not hold or issue financial
instruments for trading purposes.
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 the exposure to interest rate fluctuations. At December 31, 1996, the
Company had interest rate swaps with a notional amount of $40.0 million, and a
portfolio of variable rate debt outstanding in the amount of $1,037.2 million.
Under these agreements, Coastal will pay the counterparties interest at a fixed
rate and the counterparties will pay Coastal interest at a variable rate equal
to the London Interbank Offered Rate ("LIBOR"), which is subject to change over
time as LIBOR fluctuates. Terms expire at various dates through of the year
2000. At December 31, 1996, the Company had no outstanding foreign currency
swaps.
Neither the Company nor the counterparties, which are prominent banking
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, 1996, the Company had no exposure to credit loss on
interest rate swaps. See Note 7 of the Notes to Consolidated Financial
Statements for more information on these swaps. The Company does not believe
that any reasonably likely change in interest rates would have a material
adverse effect on the consolidated 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. The Company and its
subsidiaries also frequently enter into swaps, futures and other contracts to
hedge the price risks associated with inventories, commitments and certain
anticipated transactions. The swaps, futures and other contracts are with
established exchanges, 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.
The Financial Accounting Standards Board has issued Statement of Financial
Accounting Standards No. 125, "Accounting for Transfers and Servicing of
Financial Assets and Extinguishments of Liabilities" ("FAS 125") to be effective
in 1997. Under FAS 125, which uses a "financial - components approach," an
entity recognizes the financial assets it controls and liabilities it has
incurred, derecognizes financial assets when control has been surrendered and
derecognizes liabilities when extinguished. The application of the new standard
is not expected to have a material effect on the Company's consolidated results
of operations, financial position or cash flows in 1997.
The Accounting Standards Executive Committee of the AICPA issued Statement
of Position 96-1 ("SOP 96-1") on Environmental Remediation Liabilities to be
effective in 1997. SOP 96-1 provides additional guidance on accrual measurement
and the disclosure of environmental liabilities. The Company is currently
evaluating the impact of SOP 96-1.
The Company's operations are subject to extensive and evolving federal,
state and local environmental laws and regulations. The Company spent
approximately $37 million in 1996 on environmental capital projects and
anticipates capital expenditures of approximately $42 million in 1997 in order
to comply with such laws and regulations. The majority of the 1997 expenditures
is attributable to construction projects at the Company's refining, chemical and
F-3
<PAGE>
terminal facilities. The Company currently anticipates capital expenditures for
environmental compliance for the years 1998 through 2000 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
$333 million, and the Company estimates its pro-rata exposure, to be paid over a
period of several years, is approximately $7.4 million, and has made appropriate
provisions. At 4 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 subsidiaries' 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
$40,000, 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 liquidity, consolidated financial
position or results of operations.
Results of Operations
The Company operates principally in the following lines of business:
natural gas; refining, marketing and chemicals; exploration and production;
coal; and power.
Natural Gas. Natural Gas operations involve the production, purchase,
gathering, storage, transportation and sale of natural gas, principally to
utilities, industrial customers and other pipelines, and include the operations
of natural gas liquids extraction plants. The operations involve both regulated
and unregulated companies.
The 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.
<TABLE>
<CAPTION>
Million of Dollars
-------------------------------------------
1996 1995 1994
----------- ----------- ----------
<S> <C> <C> <C>
Operating revenues.............................................. $ 3,914.9 $ 2,898.6 $ 3,075.7
Depreciation, depletion and amortization........................ 160.7 152.3 151.0
Operating profit................................................ 378.3 403.5 431.3
Total throughput volume (Bcf)................................... 2,246 2,102 1,980
</TABLE>
F-4
<PAGE>
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 results 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's gathering facilities, reduced
operating and general expenses of $8 million and other increases of $2 million.
The transportation and storage revenue decrease is primarily due to decreases of
$46 million for revenue received in 1995 related to storage and contract
settlements and increases in provisions for 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.
The operating profit decrease reflects the increased competition in the
natural gas industry. Although the firm capacity on the Company's major
interstate pipelines is sold out, the pipeline subsidiaries have instituted
reengineering projects and cost-cutting efforts to remain competitive and
improve operating profits.
The Company has teamed with a Canadian gas marketing company to form one of
the largest marketers of natural gas and electricity, through a combination of
the operations of the two companies related marketing and services subsidiaries.
Agreements were concluded in February 1997, which created new entities with the
ability to compete aggressively in the emerging deregulated electric and natural
gas markets. Coastal has a 50% interest in the joint venture.
1995 Versus 1994. The decrease in operating revenue of $177 million can be
primarily attributed to decreased prices more than offsetting increased volumes
for the unregulated gas marketing companies. Also contributing to the revenue
decrease was a reduction in the volumes of gas auctioned by ANR Pipeline on the
open market. Partially offsetting the decreases was an increase in
transportation revenue due primarily to increased volumes. Total throughput
volumes for the pipelines increased by approximately 6% while the volumes
managed by the gas marketing companies increased by 15%.
Purchases decreased by $163 million in 1995, as decreased prices more than
offset increased volumes for the unregulated gas marketing companies, resulting
in a gross profit decrease of $14 million.
The operating profit decrease of $28 million resulted from decreased sales
margins of $24 million, decreased storage revenue of $23 million, increased
operating expenses of $10 million and other decreases of $7 million offset by
increased transportation revenue of $28 million and increased sales volumes of
$8 million.
The increased operating expenses resulted from non-recurring 1994 expense
reductions of $13 million (primarily related to revisions of certain estimated
costs) and other expense increases partially offset by decreases for storage and
transportation expenses and gas used in operations.
F-5
<PAGE>
Refining, Marketing and Chemicals. Refining, marketing and chemicals
operations involve the purchase, transportation and sale of refined products,
crude oil, condensate and natural gas liquids; the operation of refineries and
chemical plants; the sale at retail of gasoline, petroleum products and
convenience items; petroleum product terminaling and marketing of crude oil and
refined petroleum products worldwide.
<TABLE>
<CAPTION>
Million of Dollars
-------------------------------------------
1996 1995 1994
----------- ----------- ----------
<S> <C> <C> <C>
Operating revenues.............................................. $ 7,364.8 $ 6,851.3 $ 6,458.9
Depreciation, depletion and amortization........................ 73.3 61.8 53.9
Operating profit ............................................... 93.3 208.8 153.3
Refined product sales (MM Bbls)................................. 307 301 298
</TABLE>
1996 Versus 1995. Operating revenues increased by $514 million as a result
of increased prices and volumes. The volume increase is 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
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 results 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 result 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.
The Company completed the 3-year restructuring of its refineries in 1996,
enabling them to process higher volumes at a lower fixed cost per barrel and to
increase the yield of higher-value, light products. During 1996, the Company
continued selling, exchanging or disposing of marketing operations that cannot
be integrated with core refining assets. In 1997, Coastal plans to further
revamp wholesale and retail marketing to more directly support its core
refineries.
1995 Versus 1994. Operating revenues increased by $392 million as a result
of increased prices and volumes. The volume increase was primarily due to
increased throughput of 15,000 barrels per day at the Company's refineries.
Purchases for the segment increased by $335 million, resulting in an
increased gross profit of $57 million. Increased volumes of $111 million and a
gain of $17 million from the sale of interests in certain liquid pipeline assets
offset by reduced margins of $64 million and other decreases of $7 million make
up the gross profit increase. On an industrywide basis, refinery margins in 1995
were the second worst seen in the past decade.
The operating profit increase of $55 million resulted from the increased
gross profit of $57 million and reduced operating expenses of $6 million being
offset by increased depreciation, depletion and amortization of $8 million. The
decreased operating expenses resulted from decreases at the refineries due to
reduced fuel costs and other improvements more than offsetting increases for the
retail and chemical operations. The reduced refinery operating expenses resulted
from improvements made at the refineries as part of Coastal's objective to be a
low-cost operator. The increases for retail and chemical operations resulted
from the acquisition of additional convenience stores and expanded chemicals
operations, respectively. Depreciation, depletion and amortization increased due
to the expanded operations noted above.
F-6
<PAGE>
The marketing of paraxylene from Coastal's petrochemical plant in Montreal
East, Quebec was a strong contributor to the segment's operating profit in 1995.
By the end of 1995, production was boosted to 310,000 tons per year from a
capacity of 180,000 tons per year at December 31, 1994.
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.
<TABLE>
<CAPTION>
Millions of Dollars
-------------------------------------------
1996 1995 1994
----------- ----------- ---------
<S> <C> <C> <C>
Operating revenues.............................................. $ 473.1 $ 278.6 $ 309.8
Depreciation, depletion and amortization........................ 159.2 105.5 106.0
Operating profit................................................ 154.9 24.9 41.8
Natural gas production (MMcf/d)................................. 353 234 218
Oil, condensate and natural gas liquids production (bpd)........ 13,831 13,231 12,237
Average sales price (dollars):
Gas (per Mcf)................................................ $ 2.19 $ 1.57 $ 1.86
Oil, condensate and natural gas liquids (per bbl)............ 20.46 17.20 15.18
</TABLE>
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. Average daily net production of natural gas
increased by 51% and net production of oil, condensate and natural gas liquids
increased by 4.5% over 1995. The volume increase results from Coastal's ongoing
successful exploration programs, especially in South Texas and offshore in the
Gulf of Mexico.
The operating profit increase of $130 million results 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 is higher due to the increased volumes
and provisions for the impairment of international projects.
Coastal added reserves in 1996 that were more than triple the 1996
production due to its successful exploration programs, and the 1997 capital
budget is up slightly from 1996 expenditures. With the growth in production, the
Company has been able to reduce its costs per thousand cubic feet equivalent by
approximately 19% since 1993.
1995 Versus 1994. Operating revenues decreased by $31 million as lower
natural gas prices and decreased revenues from natural gas marketing activities
were partially offset by increased volumes for all products and higher prices
for crude oil, condensate and natural gas liquids. Natural gas revenue decreases
of $41 million, including $28 million for natural gas marketing, and other
decreases of $7 million were partially offset by increases of $17 million for
crude oil, condensate and natural gas liquids.
The operating profit decrease of $17 million resulted from decreased
natural gas prices of $23 million, reduced gross profit from natural gas
marketing activities of $4 million, increased operating expenses of $11 million
and other decreases of $5 million offset by increased volumes of $16 million and
increased prices for crude oil, condensate and natural gas liquids of $10
million. The increased operating expenses resulted from additional producing
wells acquired or drilled during the year.
F-7
<PAGE>
Coal. Coal operations include mining, processing and marketing of coal from
Company-owned reserves and from other sources, and the brokering of coal for
others.
<TABLE>
<CAPTION>
Millions of Dollars
-------------------------------------------
1996 1995 1994
----------- ----------- ----------
<S> <C> <C> <C>
Operating revenues.............................................. $ 713.6 $ 459.6 $ 451.3
Depreciation, depletion and amortization........................ 37.3 31.3 28.9
Operating profit................................................ 356.0 98.7 98.2
Captive and brokered sales (millions of tons)................... 17.9 18.0 17.5
</TABLE>
1996 Versus 1995. The increase in coal revenues is primarily the result of
a gain of $272 million from the sale of the Utah coal mining operations (See
Note 10 of the Notes to the Consolidated Financial Statements) 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 results 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 results primarily from sales in 1996 of coke from the Company's Aruba
refinery.
The Company restructured its coal operations in the eastern United States
in late 1996 and will continue to develop ANR Coal Company, LLC and its
divisions, where the Company sees additional potential.
1995 Versus 1994. The increase in coal revenues was a result of increased
volumes sold more than offsetting reduced prices. Much of the volume increase
came from increased demand in the steam coal market. The segment experienced a
5% increase in volumes sold and produced, while industrywide coal production and
sales decreased about 1 percent.
The operating profit increase of $1 million resulted from increased sales
volumes of $14 million offset by decreased prices of $4 million; increased
operating expenses of $4 million; increased depreciation, depletion and
amortization of $3 million and other of $2 million. Operating expenses,
including coal costs, and depreciation, depletion and amortization increased as
a result of the volume increase. The other decrease results from reduced
brokerage and royalty volumes.
Power. Power operations include the ownership of, participation in and
operation of power projects in the United States and internationally.
<TABLE>
<CAPTION>
Millions of Dollars
-------------------------------------------
1996 1995 1994
---------- ------------ ----------
<S> <C> <C> <C>
Operating revenues.............................................. $ 92.6 $ 48.4 $ 27.2
Depreciation, depletion and amortization........................ 2.4 2.0 1.5
Operating profit................................................ 17.3 7.8 2.7
</TABLE>
1996 Versus 1995. The operating revenue increase of $44 million results
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. Most of the plants in which
the Power segment has investments are partially-owned, thus the equity earnings
from those plants are classified as other income-net rather than operating
profit. In 1996, equity income from the partially-owned plants amounted to $24
million.
The Company has power plants located in the United States, China, Central
America and in the Caribbean, and there are projects in various stages of
development in Pakistan, India, Indonesia, Guatemala and other countries.
F-8
<PAGE>
1995 Versus 1994. The increase in operating revenues of $21 million
resulted primarily from the power plant in El Salvador beginning operations in
1995. The operating profit increase of $5 million resulted from the increased
revenues of $21 million offset by increased operating expenses, also due to the
El Salvador operations, of $16 million. In 1995, the equity income from
partially-owned investments amounted to $20 million.
Other. Other operations involve trucking, real estate and other activities.
<TABLE>
<CAPTION>
Millions of Dollars
--------------------------------------------
1996 1995 1994
----------- ----------- -----------
<S> <C> <C> <C>
Operating revenues.............................................. $ 32.7 $ 148.3 $ 181.1
Depreciation, depletion and amortization........................ 2.0 5.7 5.9
Operating profit................................................ 11.7 7.3 6.3
</TABLE>
1996 Versus 1995. The $116 million decrease in operating revenues is 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 now included in other
income-net.
1995 Versus 1994. The $33 million decrease in operating revenues resulted
from decreased rates and volumes for the trucking operations through October,
1995 and no operating revenues during the last two months due to the merger
noted above. Operating profit increased by $1 million as the reduced revenues
were more than offset by reduced expenses for the trucking and other operations.
Other Income - Net
1996 Versus 1995. Other income-net increased by $33 million due to
increased equity income from unconsolidated subsidiaries.
1995 Versus 1994. Other income-net decreased by $10 million in 1995 due to
reduced equity income from unconsolidated subsidiaries, primarily from the 50%
owned Pacific Refining Company.
Interest and Debt Expense
1996 Versus 1995. Interest and debt expense decreased by $47 million in
1996 due to a lower average interest rate.
1995 Versus 1994. Interest and debt expense increased by $8 million in 1995
due to certain favorable 1994 financing costs transactions and interest
adjustments not recurring, partially offset by reduced average debt levels and a
slightly lower average rate.
Taxes on Income
Income taxes fluctuated primarily 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 for 1996 and 1995 were affected by certain foreign
subsidiaries' unremitted earnings, which are considered to be indefinitely
reinvested outside the United States and, accordingly, no U.S. income taxes have
been provided on those earnings.
Extraordinary Items
The 1996 extraordinary items, net of income taxes, resulted from the early
retirement of debt and the discontinuation of regulatory accounting. See Note 13
of the Notes to Consolidated Financial Statements.
F-9
<PAGE>
INDEPENDENT AUDITORS' REPORT
Board of Directors and Stockholders
The Coastal Corporation
Houston, Texas
We have audited the accompanying consolidated balance sheets of The Coastal
Corporation and subsidiaries as of December 31, 1996 and 1995, 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, 1996. 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, 1996 and 1995, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 1996, 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
January 31, 1997
F-10
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED OPERATIONS
(Millions of Dollars Except Per Share)
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------
1996 1995 1994
----------- ----------- -----------
<S> <C> <C> <C>
OPERATING REVENUES.............................................. $ 12,166.9 $ 10,457.6 $ 10,226.2
----------- ----------- -----------
OPERATING COSTS AND EXPENSES
Purchases.................................................... 8,979.8 7,554.2 7,360.5
Operating expenses........................................... 1,722.0 1,773.9 1,768.9
Depreciation, depletion and amortization..................... 453.6 378.5 363.2
----------- ----------- -----------
11,155.4 9,706.6 9,492.6
----------- ----------- -----------
OPERATING PROFIT................................................ 1,011.5 751.0 733.6
----------- ----------- -----------
OTHER INCOME-NET................................................ 85.0 51.6 61.2
----------- ----------- -----------
OTHER EXPENSES
General and administrative................................... 64.9 64.7 62.1
Interest and debt expense.................................... 368.3 415.4 407.8
Taxes on income.............................................. 163.1 52.1 92.3
----------- ----------- -----------
596.3 532.2 562.2
----------- ----------- -----------
EARNINGS BEFORE EXTRAORDINARY ITEMS............................. 500.2 270.4 232.6
EXTRAORDINARY ITEMS - NET OF INCOME TAXES
Loss on early extinguishment of debt......................... (12.0) - -
Discontinuation of regulatory accounting..................... (85.6) - -
----------- ----------- -----------
NET EARNINGS.................................................... 402.6 270.4 232.6
DIVIDENDS ON PREFERRED STOCK.................................... 17.4 17.4 17.4
----------- ----------- -----------
NET EARNINGS AVAILABLE TO
COMMON STOCKHOLDERS........................................... $ 385.2 $ 253.0 $ 215.2
=========== =========== ===========
EARNINGS PER SHARE
Before extraordinary items................................... $ 4.54 $ 2.40 $ 2.05
Extraordinary items.......................................... (.92) - -
----------- ----------- -----------
NET EARNINGS PER COMMON AND
COMMON EQUIVALENT SHARE....................................... $ 3.62 $ 2.40 $ 2.05
=========== =========== ===========
</TABLE>
See Notes to Consolidated Financial Statements.
F-11
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Millions of Dollars)
<TABLE>
<CAPTION>
December 31,
---------------------------
1996 1995
----------- ----------
<S> <C> <C>
ASSETS
CURRENT ASSETS
Cash and cash equivalents..................................................... $ 106.3 $ 58.4
Receivables, less allowance for doubtful accounts
$23.4 million (1996) and $21.4 million (1995).............................. 1,801.0 1,192.3
Inventories................................................................... 1,143.9 781.1
Prepaid expenses and other.................................................... 145.2 218.3
----------- ----------
Total Current Assets....................................................... 3,196.4 2,250.1
----------- ----------
PROPERTY, PLANT AND EQUIPMENT - AT COST
Natural gas systems........................................................... 5,691.5 5,866.2
Refining, crude oil and chemical facilities................................... 2,213.9 1,957.8
Gas and oil properties-at full-cost........................................... 1,669.4 1,450.9
Other......................................................................... 386.7 743.1
----------- ----------
9,961.5 10,018.0
Accumulated depreciation, depletion and amortization.......................... 3,306.6 3,556.1
----------- ----------
6,654.9 6,461.9
----------- ----------
OTHER ASSETS
Goodwill...................................................................... 508.9 525.7
Investments - equity method .................................................. 589.1 447.4
Other......................................................................... 663.8 973.7
----------- ----------
1,761.8 1,946.8
----------- ----------
$ 11,613.1 $ 10,658.8
=========== ==========
</TABLE>
See Notes to Consolidated Financial Statements.
F-12
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Millions of Dollars)
<TABLE>
<CAPTION>
December 31,
---------------------------
1996 1995
----------- ----------
<S> <C> <C>
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Notes payable ................................................................ $ 105.0 $ 123.2
Accounts payable.............................................................. 2,425.9 1,630.2
Accrued expenses.............................................................. 408.3 325.4
Current maturities on long-term debt.......................................... 8.0 128.5
----------- ----------
Total Current Liabilities.................................................. 2,947.2 2,207.3
----------- ----------
DEBT
Long-term debt, excluding current maturities.................................. 3,526.1 3,661.7
----------- ----------
DEFERRED CREDITS AND OTHER
Deferred income taxes......................................................... 1,404.8 1,473.8
Other deferred credits........................................................ 598.5 636.6
----------- ----------
2,003.3 2,110.4
----------- ----------
PREFERRED STOCK
Issued by subsidiaries........................................................ 100.0 .6
----------- ----------
COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY
Cumulative preferred stock (with aggregate
liquidation preference of $208.9 million) ................................. 2.6 2.7
Class A common stock - Issued (1996 - 382,449 shares;
1995 - 404,269 shares)..................................................... .1 .1
Common stock - Issued (1996 - 109,756,251 shares;
1995-109,168,216 shares)................................................... 36.6 36.4
Additional paid-in capital.................................................... 1,239.6 1,225.0
Retained earnings............................................................. 1,890.1 1,547.1
----------- ----------
3,169.0 2,811.3
Less common stock in treasury-at cost (1996-4,395,405 shares;
1995-4,395,405 shares)..................................................... 132.5 132.5
----------- ----------
3,036.5 2,678.8
----------- ----------
$ 11,613.1 $ 10,658.8
=========== ==========
</TABLE>
See Notes to Consolidated Financial Statements.
F-13
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CASH FLOWS
(Millions of Dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------------------------
1996 1995 1994
----------- ----------- ----------
<S> <C> <C> <C>
NET CASH FLOW FROM OPERATING ACTIVITIES
Earnings before extraordinary items.......................... $ 500.2 $ 270.4 $ 232.6
Add (subtract) items not requiring (providing) cash:
Depreciation, depletion and amortization ................. 455.7 382.0 370.2
Deferred income taxes..................................... 55.0 32.7 39.7
Gain from sale of Utah coal mining operations............. (272.3) - -
Amortization of producer contract reformation costs....... 25.6 29.0 32.8
Distributed (undistributed) earnings from equity
investments............................................ (.8) 28.6 (36.6)
Working capital and other changes, excluding changes
relating to cash and non-operating activities:
Accounts receivable....................................... (684.4) (8.6) (59.0)
Inventories............................................... (387.2) 36.4 (58.1)
Prepaid expenses and other................................ .4 19.8 (12.6)
Accounts payable.......................................... 796.9 (132.3) 299.7
Accrued expenses.......................................... 61.0 (2.6) (59.1)
Other..................................................... 11.3 (6.3) (80.5)
----------- ----------- ----------
....................................................... 561.4 649.1 669.1
----------- ----------- ----------
CASH FLOW FROM INVESTING ACTIVITIES
Purchases of property, plant and equipment................... (880.8) (626.8) (543.2)
Proceeds from sale of property, plant and equipment.......... 79.4 109.6 30.1
Additions to investments..................................... (114.2) (75.2) (36.0)
Proceeds from investments.................................... 25.9 27.5 91.5
Proceeds from sale of Utah coal mining operations............ 610.1 - -
Recovery of gas supply prepayments........................... .3 .5 .7
----------- ----------- ----------
(279.3) (564.4) (456.9)
----------- ----------- ----------
CASH FLOW FROM FINANCING ACTIVITIES
Increase (decrease) in short-term notes...................... (318.2) 366.0 (206.8)
Redemption of mandatory redemption preferred stock........... (.6) - (33.7)
Proceeds from issuing common stock........................... 14.7 10.5 5.4
Proceeds from issuing stock of subsidiaries.................. 105.0 - -
Proceeds from long-term debt issues.......................... 590.7 323.9 199.3
Payments to retire long-term debt............................ (566.2) (740.9) (202.8)
Dividends paid............................................... (59.6) (59.3) (59.3)
----------- ----------- ----------
(234.2) (99.8) (297.9)
----------- ----------- ----------
NET INCREASE (DECREASE) IN CASH
AND CASH EQUIVALENTS......................................... 47.9 (15.1) (85.7)
Cash and cash equivalents at beginning of year............... 58.4 73.5 159.2
----------- ----------- ----------
Cash and cash equivalents at end of year..................... $ 106.3 $ 58.4 $ 73.5
=========== =========== ==========
</TABLE>
See Notes to Consolidated Financial Statements.
F-14
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED COMMON STOCK AND
OTHER STOCKHOLDERS' EQUITY
(Thousands of Shares and Million of Dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------------------------------------------------
1996 1995 1994
------------------- -------------------- -------------------
Shares Amount Shares Amount Shares Amount
-------- ------- ------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
PREFERRED STOCK, PAR VALUE 33-1/3(cent)
PER SHARE, AUTHORIZED 50,000,000
SHARES CUMULATIVE CONVERTIBLE
PREFERRED:
$1.19, Series A: Beginning balance. 61 $ - 63 $ - 65 $ -
Converted to common................ (1) - (2) - (2) -
-------- -------- -------- -------- ------- --------
Ending balance................... 60 - 61 - 63 -
======== -------- ======== -------- ======= --------
$1.83, Series B: Beginning balance. 79 .1 84 .1 89 .1
Converted to common................ (5) (.1) (5) - (5) -
-------- -------- -------- -------- ------- --------
Ending balance................... 74 - 79 .1 84 .1
======== -------- ======== -------- ======= --------
$5.00, Series C: Beginning balance. 33 - 34 - 35 -
Converted to common................ (1) - (1) - (1) -
-------- -------- -------- -------- ------- --------
Ending balance................... 32 - 33 - 34 -
======== -------- ======== -------- ======= --------
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.................. 404 .1 416 .1 423 .1
Converted to common................ (35) - (20) - (24) -
Conversion of preferred stock and
exercise of stock options.......... 13 - 8 - 17 -
-------- -------- -------- -------- ------- --------
Ending balance................... 382 .1 404 .1 416 .1
======== -------- ======== -------- ======= --------
COMMON STOCK, PAR VALUE 33-1/3(cent)
PER SHARE, AUTHORIZED 250,000,000
SHARES
Beginning balance.................. 109,168 36.4 108,726 36.2 108,512 36.2
Conversion of preferred stock...... 34 - 34 - 31 -
Conversion of Class A common stock. 35 - 20 - 24 -
Exercise of stock options.......... 519 .2 388 .2 159 -
-------- -------- -------- -------- ------- --------
Ending balance................... 109,756 36.6 109,168 36.4 108,726 36.2
======== -------- ======== -------- ======= --------
ADDITIONAL PAID-IN CAPITAL
Beginning balance.................. 1,225.0 1214.7 1,209.3
Exercise of stock options.......... 14.6 10.3 5.4
-------- -------- --------
Ending balance................... 1,239.6 1,225.0 1,214.7
-------- -------- --------
RETAINED EARNINGS
Beginning balance.................. 1,547.1 1,336.0 1,162.7
Net earnings for period............ 402.6 270.4 232.6
Cash dividends on preferred stock.. (17.4) (17.4) (17.4)
Cash dividends on Class A common
stock, 36(cent)(1996), 36(cent)(1995)
and 36(cent)(1994) per share..... (.1) (.1) (.2)
Cash dividends on common stock,
40(cent)(1996), 40(cent)(1995) and
40(cent)(1994) per share......... (42.1) (41.8) (41.7)
-------- -------- --------
Ending balance................ 1,890.1 1,547.1 1,336.0
-------- -------- --------
LESS TREASURY STOCK - AT COST........... 4,395 132.5 4,395 132.5 4,395 132.5
======== -------- ======== -------- ======= --------
TOTAL................................... $3,036.5 $2,678.8 $2,457.2
======== ======== ========
</TABLE>
See Notes to Consolidated Financial Statements.
F-15
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Summary of Significant Accounting Policies
Principles of Consolidation. The consolidated financial statements include
accounts of the Company and its wholly owned subsidiaries, after eliminating all
significant intercompany transactions. The equity method of accounting is used
for investments in which the Company has a 20% to 50% voting interest and
exercises significant influence. The equity method is also used for investments
in limited partnerships in which the Company has an interest of more than 5%.
Other investments in which the Company has less than a 20% voting interest are
accounted for by the cost method.
Statement of Cash Flows. For purposes of this statement, cash equivalents
include time deposits, certificates of deposit and all highly liquid instruments
with original maturities of three months or less. Cash flows of a hedging
instrument that is accounted for as a hedge of an identifiable transaction are
classified in the same category as the cash flows from the item being hedged.
The Company made cash payments for interest and financing fees (net of amounts
capitalized) of $386.0 million, $443.6 million and $431.8 million in 1996, 1995
and 1994, respectively. Cash payments for income taxes amounted to $57.2
million, $33.3 million and $73.7 million for 1996, 1995 and 1994, 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. Natural gas inventories
are accounted for by Colorado Interstate Gas Company ("CIG") using the last-in,
first-out method. The unregulated gas marketing companies account for natural
gas inventories 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. 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.
Property, Plant and Equipment. Property additions include acquisition
costs, administrative costs and, where appropriate, capitalized interest
allocable to construction. Capitalized interest amounted to $8.0 million, $5.9
million and $8.3 million in 1996, 1995 and 1994, respectively. All costs
incurred in the acquisition, exploration and development of gas and oil
properties, including unproductive wells, are capitalized under the full-cost
method of accounting. Such costs include the costs of all unproved properties
and internal costs directly related to acquisition and exploration activities.
All other general and administrative costs, as well as production costs, are
expensed as incurred.
Depreciation, depletion and amortization ("DD & A") of gas and oil
properties are provided on the unit-of-production basis whereby the unit rate
for DD&A is determined by dividing the total unrecovered carrying value of gas
and oil properties 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 $.88 for 1996, $.89 for 1995 and $.96
for 1994. Unamortized costs of proved properties are subject to a ceiling which
limits such costs to the estimated future net cash flows from proved gas and oil
properties, net of related income tax effects, discounted at 10 percent. If the
unamortized costs are greater than this ceiling, any excess will be charged to
DD & A expense. No such charge was required in the periods presented. Provisions
for depletion of coal properties, including exploration and development costs,
are based upon estimates of
F-16
<PAGE>
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............................................... 0.6% - 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.
The Company adopted Statement of Financial Accounting Standards No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
Be Disposed Of," in 1996. The application of the new standard, which does not
apply to costs capitalized pursuant to the full-cost method, did not have a
material effect on the Company's consolidated results of operations, financial
position or cash flows.
Goodwill. Goodwill, which primarily relates to the acquisitions of American
Natural Resources Company ("ANR") and CIG, amounted to $508.9 million at
December 31, 1996, 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 1996, 1995 and 1994, 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. Earnings per common and common equivalent share amounts
are based on the average number of common and Class A common shares outstanding
during each period, assuming conversion of preferred stocks which are common
stock equivalents and exercise of all stock options having exercise prices less
than the average market price of the common stock using the treasury stock
method.
Average shares entering into the computations are:
1996 ...................................................106,335,208
1995 ...................................................105,434,830
1994 ...................................................105,207,492
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 have historically followed the reporting and accounting
requirements of FAS 71. Effective November 1, 1996, these subsidiaries
discontinued application of FAS 71. See Note 13 of the Notes to Consolidated
Financial Statements.
Statement of Financial Accounting Standards No. 125, "Accounting for
Transfers and Servicing of Financial Assets and Extinguishments of Liabilities"
("FAS 125"). The Financial Accounting Standards Board ("FASB") has
F-17
<PAGE>
issued FAS 125 to be effective in 1997. Under FAS 125, which uses a "financial -
components approach," an entity recognizes the financial assets it controls and
liabilities it has incurred, derecognizes financial assets when control has been
surrendered and derecognizes liabilities when extinguished. The application of
the new standard is not expected to have a material effect on the Company's
consolidated results of operations, financial position or cash flows in 1997.
Statement of Position 96-1 ("SOP 96-1"). The Accounting Standards Executive
Committee of the AICPA issued SOP 96-1 on Environmental Remediation Liabilities
to be effective in 1997. SOP 96-1 provides additional guidance on accrual
measurement and the disclosure of environmental liabilities. The Company is
currently evaluating the impact of SOP 96-1.
Reclassification of Prior Period Statements. Certain minor
reclassifications have been made to conform with current reporting practices.
The effect of the reclassifications was not material to the Company's
consolidated results of operations, financial position or cash flows.
Note 2. Inventories
Inventories at December 31 were (millions of dollars):
<TABLE>
<CAPTION>
1996 1995
----------- ----------
<S> <C> <C>
Refined products, crude oil and chemicals.................................. $ 920.3 $ 556.5
Natural gas in underground storage......................................... 77.7 49.9
Coal, materials and supplies............................................... 145.9 174.7
----------- ----------
$ 1,143.9 $ 781.1
=========== ==========
</TABLE>
Elements included in inventory cost are material, labor and manufacturing
expenses. The excess of replacement cost over the carrying value of natural gas
in underground storage carried by the last-in, first-out method was
approximately $126.2 million and $36.5 million at December 31, 1996 and 1995,
respectively. The increase over the 1995 amount is due to the higher replacement
cost rates at December 31, 1996.
Note 3. Investments
The Company has interests in corporations and partnerships which are
accounted for on an equity basis. These investments, included in Other Assets,
are Great Lakes Gas Transmission Limited Partnership (50% interest), which
operates an interstate pipeline system; Blue Lake Gas Storage Company (50%
interest), which operates a gas storage system in Michigan; 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 $589.1 million and $447.4 million at December 31, 1996 and 1995,
respectively. The Company's equity in income of the investments, included in
Other Income-Net, was $103.7 million, $60.6 million and $75.7 million in 1996,
1995 and 1994, respectively, while dividends and partnership distributions
received amounted to $102.9 million, $89.2 million and $39.1 million in 1996,
1995 and 1994, respectively.
F-18
<PAGE>
Summarized financial information of these entities is as follows (millions
of dollars):
<TABLE>
<CAPTION>
December 31,
---------------------------
1996 1995
----------- ----------
<S> <C> <C>
Current assets............................................................. $ 800.4 $ 687.8
Noncurrent assets.......................................................... 5,268.5 5,140.1
----------- ----------
$ 6,068.9 $ 5,827.9
=========== ==========
Current liabilities........................................................ $ 863.6 $ 858.7
Noncurrent liabilities..................................................... 3,412.8 3,423.3
Deferred credits........................................................... 230.4 241.4
Equity..................................................................... 1,562.1 1,304.5
----------- ----------
$ 6,068.9 $ 5,827.9
=========== ==========
</TABLE>
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------
1996 1995 1994
----------- ----------- -----------
<S> <C> <C> <C>
Revenues..................................................... $ 2,229.0 $ 1,924.5 $ 1,882.7
Operating income............................................. 591.1 558.9 469.9
Net income................................................... 266.9 153.2 146.4
</TABLE>
F-19
<PAGE>
Note 4. Debt
Long-Term Debt - Balances at December 31 were (millions of dollars):
<TABLE>
<CAPTION>
1996 1995
----------- ----------
<S> <C> <C>
The Coastal Corporation:
Notes payable (revolving credit agreements)................................ $ - $ 70.0
Swiss franc bonds, 5-3/4%, due 1996........................................ - 66.5
Senior notes:
10-3/8%, due 2000....................................................... 249.9 249.9
10%, due 2001........................................................... 299.4 299.2
8-3/4%, due 1999........................................................ 150.0 150.0
8-1/8%, due 2002........................................................ 249.5 249.4
Senior debentures:
11-3/4%, due 2006....................................................... - 400.0
10-1/4%, due 2004....................................................... 199.9 199.8
10-3/4%, due 2010....................................................... 149.6 149.5
9-3/4%, due 2003........................................................ 299.1 298.9
9-5/8%, due 2012........................................................ 149.2 149.2
7-3/4%, due 2035........................................................ 149.9 149.9
Other...................................................................... .1 .1
----------- ----------
1,896.6 2,432.4
----------- ----------
Subsidiary Companies:
Notes payable (term credit facilities)..................................... 378.1 50.0
Notes payable (revolving credit agreements)................................ 510.0 264.7
Notes payable (project financing), due 1998................................ 18.2 22.4
Debentures, 7% to 10%, due 2005-2024 ...................................... 677.2 677.0
Capitalized lease obligations.............................................. - 25.2
Other, due 2000-2028....................................................... 54.0 18.5
----------- ----------
1,637.5 1,057.8
----------- ----------
Amount reclassified from short-term debt................................... - 300.0
----------- ----------
Total Long-Term Debt....................................................... 3,534.1 3,790.2
Less Current Maturities.................................................... 8.0 128.5
----------- ----------
$ 3,526.1 $ 3,661.7
=========== ==========
</TABLE>
At December 31, 1996, amounts available under long-term credit agreements
with banks totaled $1,576.1 million, including $125.0 million available to The
Coastal Corporation. Loans under these agreements bear interest at money
market-related rates (weighted average 5.78% at December 31, 1996). Annual
commitment fees range up to 3/8% payable on the unused portion of the applicable
facility. At December 31, 1996, $888.1 million was outstanding and $52.4 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, 1996, net assets of consolidated subsidiaries
amounted to approximately $5.6 billion, of which $1.3 billion was restricted by
such provisions.
Maturities. The aggregate amounts of long-term debt maturities for the five
years following 1996 are (millions of dollars):
1997 $ 8.0 2000 $254.1
1998 18.1 2001 820.8
1999 320.0
F-20
<PAGE>
Notes Payable. At December 31, 1996, Coastal and its subsidiaries had
$105.0 million of outstanding indebtedness to banks under short-term lines of
credit, compared to $423.2 million at December 31, 1995. As of December 31,
1995, the Company's financial statements reflected $300.0 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 5.94% and 6.16% at December 31, 1996 and 1995, respectively.
As of December 31, 1996, $967.3 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 $598.8 million
of retained earnings was available at December 31, 1996 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, 1996, the Company had guaranteed 50% of construction financings of
two partially owned partnerships. The Company's proportionate share of the
outstanding principal balance under these guarantees was $79.8 million at
December 31, 1996. One of these loans is expected to be refinanced on a
non-recourse basis in 1997, and the other in early 1998. Other guarantees and
indemnities related to obligations of unconsolidated affiliates amounted to
approximately $168.9 million as of December 31, 1996. 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 $7.1 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 $92.7 million, $79.4 million and
$72.1 million in 1996, 1995 and 1994, respectively, excluding leases covering
natural resources. Aggregate minimum lease payments under existing
noncapitalized long-term leases are estimated to be $88.0 million, $79.0
million, $79.0 million, $77.0 million, and $77.0 million for the years
1997-2001, respectively, and $751.0 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):
<TABLE>
<CAPTION>
Subsidiaries Stock
---------------------------
Shares Value
----------- ----------
<S> <C> <C>
Balance, December 31, 1993.................................................... 866 $ 26.6
Redemptions................................................................... (860) (26.0)
----------- ----------
Balance, December 31, 1994.................................................... 6 .6
Redemptions................................................................... - -
----------- ----------
Balance, December 31, 1995.................................................... 6 .6
Redemptions................................................................... (6) (.6)
----------- ----------
Balance, December 31, 1996.................................................... - $ -
=========== ==========
</TABLE>
F-21
<PAGE>
In December 1996, Coastal Securities Company Limited ("Coastal
Securities"), a wholly-owned subsidiary, issued 4,000,000 shares of preferred
stock for $100 million in cash. Quarterly cash dividends will be paid on the
preferred stock at a rate based on the London Interbank Offered Rate ("LIBOR").
The preferred shareholders are also entitled to participating dividends based on
certain refining margins. Coastal Securities may redeem the preferred stock on
or after December 31, 1999 for cash. Also, on 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 the Company's exposure to interest rate
fluctuations. At December 31, 1996, the Company had interest rate swaps with a
notional amount of $40.0 million, and a portfolio of variable rate debt
outstanding in the amount of $1,037.2 million. Under these agreements, Coastal
will pay the counterparties interest at a fixed rate of 6.71%, and the
counterparties will pay Coastal interest at a variable rate equal to LIBOR. The
weighted average LIBOR rate applicable to these agreements was 5.90% at December
31, 1996. 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 banking
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, 1996, 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-22
<PAGE>
Fair Value of Financial Instruments. The estimated fair value amounts of
the Company's financial instruments have been determined by the Company, using
appropriate market information and valuation methodologies. Considerable
judgment is required to develop the estimates of fair value, thus, the estimates
provided herein are not necessarily indicative of the amounts that the Company
could realize in a current market exchange.
<TABLE>
<CAPTION>
(Millions of Dollars)
------------------------------------------------------------
Dec. 31, 1996 Dec. 31, 1995
--------------------------- -----------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
---------- ----------- ----------- ------------
<S> <C> <C> <C> <C>
Nonderivatives:
Financial assets:
Cash and cash equivalents................... $ 106.3 $ 106.3 $ 58.4 $ 58.4
Notes receivable............................ 206.5 219.7 172.2 172.2
Financial liabilities:
Short-term debt............................. 105.0 105.0 123.2 123.2
Long-term debt ............................. 3,534.1 3,879.8 3,815.0 4,296.6
Preferred stock - issued by subsidiaries.... 100.0 101.3 0.6 0.6
Derivatives relating to:
Commodity swaps loss........................ - (44.3) - (48.5)
Debt:
Currency swaps gain......................... - - (50.0) (50.0)
Interest rate swaps loss and options........ - 0.4 9.8 11.8
</TABLE>
The estimated value of the Company's long-term debt and preferred stock -
issued by subsidiaries is based on interest rates at December 31, 1996 and 1995,
respectively, for new issues with similar remaining maturities. The fair value
of the derivatives relating to commodity swaps reflects the estimated amount to
terminate the contracts at December 31, 1996 and 1995, respectively, taking into
account unrealized gains or losses. Dealer quotes are available for these
derivatives. The fair market value of the Company's interest rate and foreign
currency swaps is based on the estimated termination values at December 31, 1996
and 1995, respectively.
Note 8. Common and Preferred Stock
Executives and other key employees have been granted options to purchase
common shares under stock option plans adopted in 1990 and 1994. Under each
plan, the option price equals the fair market value of the common shares on the
date of grant. Options vest cumulatively at a rate of 20% of the option shares
on each anniversary date of the date of grant beginning with the second
anniversary. The options, which expire ten years from the grant date, do not
carry any stock appreciation rights.
F-23
<PAGE>
The following table presents a summary of stock option transactions for the
three years ended December 31, 1996:
<TABLE>
<CAPTION>
Class A Average
Common Common Option Price
Shares Shares Per Share
----------- ----------- --------------
<S> <C> <C> <C>
December 31, 1993........................................... 2,187,455 40,630 $ 26.21
Granted.................................................. 232,900 - 30.44
Exercised................................................ (172,914) (16,823) 20.10
Revoked or expired....................................... (70,784) (1,216) 32.21
----------- ----------- --------------
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
=========== =========== --------------
</TABLE>
In accordance with the provisions of Statement of Financial Accounting
Standards No. 123, "Accounting for Stock-Based Compensation" ("FAS 123"), the
Company applies APB Opinion 25 in accounting for its stock option plans and,
accordingly, does not recognize compensation cost. 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):
<TABLE>
<CAPTION>
Year Ended
December 31,
-----------------------------
1996 1995
----------- ------------
<S> <C> <C>
Earnings before extraordinary items....................................... $ 498.0 $ 269.5
Net earnings.............................................................. 400.4 269.5
Earnings per share
Before extraordinary items............................................. $ 4.52 $ 2.39
Extraordinary items.................................................... (.92) -
----------- ------------
Net earnings per share................................................. $ 3.60 $ 2.39
=========== ============
</TABLE>
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 1996: risk free interest rate of 6.25%; expected dividend yield of
1.40%; expected life of eight years; and expected volatility of .1925. The
weighted average fair value of options granted during 1996 is $12.32 per share.
Stock options available for future grants amounted to 906,771; 1,530,830;
and 1,927,379 at December 31, 1996, 1995 and 1994, respectively. Exercisable
stock options amounted to 748,354; 1,096,479; and 1,149,721 at December 31,
1996, 1995 and 1994, respectively.
F-24
<PAGE>
The following table summarizes information about stock options outstanding
and exercisable at December 31, 1996:
<TABLE>
<CAPTION>
Outstanding Exercisable
-------------------------------------- -------------------------
Average Average
Exercise Average Exercise Exercise
Price Range Shares Life (*) Price Shares Price
----------- ----------- ---------- ----------- ------------ -----------
<S> <C> <C> <C> <C> <C>
$17.08 - $21.50............................ 94,900 1.6 $ 20.71 94,900 $ 20.71
25.50 - 29.13............................ 989,854 6.8 27.59 354,464 26.94
30.31 - 40.56............................ 1,150,911 7.5 34.74 298,990 33.46
----------- -----------
2,235,665 6.9 748,354
=========== ===========
<FN>
(*) Average life remaining in years.
</FN>
</TABLE>
Note 9. Segment and Geographic Reporting
The Company operates principally in the following lines of business:
natural gas; refining, marketing and chemicals; exploration and production;
coal; and power. Natural gas operations involve the production, purchase,
gathering, storage, transportation and sale of natural gas, principally to
utilities, industrial customers and other pipelines, and include the 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-25
<PAGE>
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, 1996, 1995
and 1994, and identifiable assets as of December 31, 1996, 1995 and 1994, by
segment, are shown as follows (millions of dollars):
<TABLE>
<CAPTION>
1996 1995 1994
----------- ----------- ----------
<S> <C> <C> <C>
OPERATING REVENUES
Natural gas............................................... $ 3,914.9 $ 2,898.6 $ 3,075.7
Refining, marketing and chemicals ........................ 7,364.8 6,851.3 6,458.9
Exploration and production................................ 473.1 278.6 309.8
Coal...................................................... 713.6 459.6 451.3
Power..................................................... 92.6 48.4 27.2
Other..................................................... 32.7 148.3 181.1
Adjustments and eliminations.............................. (424.8) (227.2) (277.8)
----------- ----------- -----------
Consolidated totals.................................... $ 12,166.9 $ 10,457.6 $ 10,226.2
=========== =========== ===========
OPERATING PROFIT
Natural gas............................................... $ 378.3 $ 403.5 $ 431.3
Refining, marketing and chemicals......................... 93.3 208.8 153.3
Exploration and production................................ 154.9 24.9 41.8
Coal...................................................... 356.0 98.7 98.2
Power..................................................... 17.3 7.8 2.7
Other..................................................... 11.7 7.3 6.3
----------- ----------- -----------
Consolidated totals.................................... $ 1,011.5 $ 751.0 $ 733.6
=========== =========== ===========
EARNINGS BEFORE INTEREST,
TAXES AND EXTRAORDINARY ITEMS
Natural gas............................................... $ 469.7 $ 473.9 $ 491.3
Refining, marketing and chemicals ........................ 94.4 184.3 143.9
Exploration and production................................ 156.2 24.9 53.2
Coal...................................................... 356.0 98.7 98.2
Power..................................................... 41.4 27.8 17.1
Other..................................................... (2.5) 6.7 5.6
----------- ----------- -----------
Segment totals......................................... 1,115.2 816.3 809.3
Corporate................................................. (83.6) (78.4) (76.6)
----------- ----------- -----------
Consolidated totals.................................... $ 1,031.6 $ 737.9 $ 732.7
=========== =========== ===========
CAPITAL EXPENDITURES
Natural gas............................................... $ 206.5 $ 128.6 $ 91.4
Refining, marketing and chemicals......................... 215.3 190.3 228.2
Exploration and production................................ 381.2 230.3 150.3
Coal...................................................... 51.5 54.0 56.9
Power..................................................... 3.7 12.1 .4
Other..................................................... 14.4 5.0 9.5
----------- ----------- -----------
Segment totals......................................... 872.6 620.3 536.7
Corporate assets.......................................... 8.2 6.5 6.5
----------- ----------- -----------
Consolidated totals.................................... $ 880.8 $ 626.8 $ 543.2
=========== =========== ===========
</TABLE>
F-26
<PAGE>
<TABLE>
<CAPTION>
1996 1995 1994
----------- ----------- -----------
<S> <C> <C> <C>
DEPRECIATION, DEPLETION AND
AMORTIZATION EXPENSE
Natural gas.................................................. $ 160.7 $ 152.3 $ 151.0
Refining, marketing and chemicals............................ 73.3 61.8 53.9
Exploration and production................................... 159.2 105.5 106.0
Coal......................................................... 37.3 31.3 28.9
Power........................................................ 2.4 2.0 1.5
Other........................................................ 2.0 5.7 5.9
----------- ----------- -----------
Segment totals............................................ 434.9 358.6 347.2
Corporate assets............................................. 4.0 4.6 4.2
----------- ----------- -----------
Consolidated totals....................................... $ 438.9 $ 363.2 $ 351.4
=========== =========== ===========
IDENTIFIABLE ASSETS
Natural gas.................................................. $ 5,395.1 $ 5,359.8 $ 5,497.0
Refining, marketing and chemicals............................ 4,061.6 3,125.2 3,041.4
Exploration and production................................... 1,178.4 992.0 837.2
Coal......................................................... 225.3 518.6 498.3
Power........................................................ 211.1 140.3 75.6
Other........................................................ 150.1 159.8 193.1
----------- ----------- -----------
Segment totals............................................ 11,221.6 10,295.7 10,142.6
Corporate assets............................................. 391.5 363.1 392.0
----------- ----------- -----------
Consolidated totals....................................... $ 11,613.1 $ 10,658.8 $ 10,534.6
=========== =========== ===========
</TABLE>
The Coal revenues and operating profit include a gain before income taxes
of $272.3 million from the sale of the Utah coal mining operations. See Note 10
of the Notes to the Consolidated Financial Statements.
Refining, marketing and chemicals revenues include gross profit arising
from the selling, trading and exchanging of third party products. Approximate
amounts from these transactions included in revenues and the impact on earnings,
exclusive of interest costs, were (millions of dollars):
<TABLE>
<CAPTION>
1996 1995 1994
----------- ----------- -----------
<S> <C> <C> <C>
Revenues........................................................ $ 26.1 $ 2.3 $ .7
Impact on earnings.............................................. 16.9 1.5 .4
</TABLE>
The number and magnitude of such transactions may vary significantly from
year to year, particularly in view of conditions in world petroleum markets.
F-27
<PAGE>
The Company's operating revenues and operating profit for the years ended
December 31, 1996, 1995 and 1994 and identifiable assets as of December 31, 1996
1995 and 1994, by geographic area, are shown as follows (millions of dollars):
<TABLE>
<CAPTION>
1996 1995 1994
----------- ----------- -----------
<S> <C> <C> <C>
Operating Revenues
United States - Third Party............................... $ 10,595.8 $ 9,146.2 $ 9,207.6
- Interarea................................. 92.4 129.1 31.0
Foreign - Third Party............................... 1,571.1 1,311.4 1,018.6
- Interarea................................. 382.7 294.5 205.2
Interarea elimination..................................... (475.1) (423.6) (236.2)
----------- ----------- -----------
Consolidated totals.................................... $ 12,166.9 $ 10,457.6 $ 10,226.2
=========== =========== ===========
Operating Profit
United States............................................. $ 923.2 $ 597.0 $ 697.9
Foreign................................................... 88.3 154.0 35.7
----------- ----------- -----------
Consolidated totals.................................... $ 1,011.5 $ 751.0 $ 733.6
=========== =========== ===========
Identifiable Assets
United States............................................. $ 10,269.1 $ 9,590.7 $ 9,503.0
Foreign................................................... 1,344.0 1,068.1 1,031.6
----------- ----------- -----------
Consolidated totals.................................... $ 11,613.1 $ 10,658.8 $ 10,534.6
=========== =========== ===========
</TABLE>
Revenues from sales to any single customer during 1996, 1995 or 1994 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 will continue 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, or $1.66 per share.
Following is a summary of the results of operations and the assets and
liabilities of the Utah coal mining operations (millions of dollars):
<TABLE>
<CAPTION>
For the Period For the Year Ended
From January 1, 1996 December 31,
---------------------------
Through December 20, 1996 1995 1994
------------------------- ----------- -----------
<S> <C> <C> <C>
Operating revenues.......................... $ 200.7 $ 213.0 $ 195.5
Costs and expenses.......................... 145.0 144.7 131.1
----------- ----------- -----------
Earnings before income taxes............. 55.7 68.3 64.4
Income taxes................................ 16.6 18.4 21.2
----------- ----------- -----------
Net earnings............................. $ 39.1 $ 49.9 $ 43.2
=========== =========== ===========
</TABLE>
<TABLE>
<CAPTION>
December 20, December 31,
1996 1995
------------ ------------
<S> <C> <C>
Working capital.............................. $ 60.1 $ 34.5
Property, plant and equipment-net............ 193.7 188.8
Other assets................................. 53.4 50.4
Deferred credits and other................... 8.9 6.2
</TABLE>
F-28
<PAGE>
Note 11. Benefit Plans
The Company has non-contributory pension plans covering substantially all
U.S. employees. These plans provide benefits based on final average monthly
compensation and years of service. The Company's funding policy is to contribute
the amount necessary for the plan to maintain its qualified status under the
Employment Retirement Income Security Act of 1974, as amended. The pension
benefit for 1996, 1995 and 1994 is shown in the following table (millions of
dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------
1996 1995 1994
----------- ----------- -----------
<S> <C> <C> <C>
Service cost - benefit earned during the period........... $ 18.3 $ 15.8 $ 17.6
Interest cost on projected benefit obligation............. 45.6 42.2 37.7
Actual return on assets................................... (175.8) (223.7) 2.0
Net amortization and deferral............................. 90.3 152.3 (74.5)
----------- ----------- -----------
Net periodic pension benefit.............................. $ (21.6) $ (13.4) $ (17.2)
=========== =========== ===========
</TABLE>
The discount rate used in determining the actuarial present value of the
projected benefit obligation was 7.50% in 1996, 7.25% in 1995 and 8.75% in 1994.
The expected increase in future compensation levels was 4% in both 1996 and 1995
and 5% in 1994 and the expected long-term rate of return on assets was 10% in
1996, 1995 and 1994.
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):
<TABLE>
<CAPTION>
December 31,
------------------------------
1996 1995
----------- ------------
<S> <C> <C>
Actuarial present value of benefit obligations:
Accumulated benefit obligation, including vested benefits of
$544.1 million and $510.4 million, respectively........................ $ (583.8) $ (559.3)
=========== ============
Projected benefit obligation for service rendered to date................ $ (658.2) $ (620.2)
Plan assets, primarily equity securities, at fair value................... 1,078.7 938.4
----------- ------------
Plan assets in excess of projected benefit obligation..................... 420.5 318.2
Unrecognized net assets at January 1, 1996 and 1995, being
recognized over average remaining service lives........................ (45.7) (54.3)
Prior service cost, not yet recognized.................................... 3.4 4.0
Unrecognized net gain from past experience different
from that assumed...................................................... (96.6) (25.4)
----------- ------------
Prepaid pension cost...................................................... $ 281.6 $ 242.5
=========== ============
</TABLE>
In 1995, the Company offered an early retirement incentive program to
eligible employees of its rate regulated subsidiaries. The impact of this
program is reflected in the above table.
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, 1996 and 1995.
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 $0.7 million for 1996, $6.4 million for 1995 and $7.6 million
for 1994. 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.
F-29
<PAGE>
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 $18.5 million, $17.6 million and $17.5 million in 1996, 1995 and
1994, 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 will no longer be deferred as a result of the
Company's discontinued application of FAS 71.
The following tables set forth the accumulated postretirement benefit
obligation recognized in the Company's Consolidated Balance Sheet as of December
31, 1996 and 1995 and the benefit cost for the years ended December 31, 1996,
1995 and 1994 (millions of dollars):
<TABLE>
<CAPTION>
December 31,
-----------------------------
1996 1995
----------- ------------
<S> <C> <C>
Accumulated postretirement benefit obligation:
Retirees............................................................... $ (76.8) $ (78.2)
Fully eligible plan participants....................................... (1.4) (2.5)
Other active plan participants......................................... (31.9) (42.8)
----------- ------------
(110.1) (123.5)
Plan assets at fair value................................................. 26.0 22.9
----------- ------------
Accumulated postretirement benefit obligation
in excess of plan assets............................................... (84.1) (100.6)
Unrecognized net transition obligation.................................... 98.6 108.1
Unrecognized net gain from past
experience different from that assumed................................. (36.8) (22.5)
Unrecognized prior service cost........................................... 4.7 4.7
----------- ------------
Postretirement benefit obligation included in balance sheet .............. $ (17.6) $ (10.3)
=========== ============
</TABLE>
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------------
1996 1995 1994
----------- ----------- -----------
<S> <C> <C> <C>
Net postretirement benefit cost consisted
of the following components:
Service cost - benefits earned during the period.......... $ 2.5 $ 2.2 $ 2.5
Interest cost on accumulated postretirement benefit
obligation............................................. 7.6 8.8 8.9
Actual return on assets................................... (1.2) (.8) (.1)
Amortization of transition obligation..................... 6.2 6.6 6.6
Deferred regulatory amounts............................... 3.6 2.0 1.8
Other amortization and deferral........................... (.9) (1.5) (1.1)
----------- ----------- -----------
Net postretirement benefit cost........................... $ 17.8 $ 17.3 $ 18.6
=========== =========== ===========
</TABLE>
The assumed health care cost trend rate used in measuring the accumulated
postretirement benefit obligation was 10.4% in 1996, 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 11.2% in 1995 and 12.0% in
1994. 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, 1996 by approximately 4.3% and the net postretirement health
care cost by approximately 3.9%. The assumed discount rate used in determining
the accumulated postretirement benefit obligation was 7.5%.
F-30
<PAGE>
Note 12. Taxes on Income
Pretax earnings before extraordinary items are composed of the following
(millions of dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------
1996 1995 1994
----------- ----------- -----------
<S> <C> <C> <C>
United States............................................. $ 579.9 $ 178.1 $ 295.0
Foreign................................................... 83.4 144.4 29.9
----------- ----------- -----------
$ 663.3 $ 322.5 $ 324.9
=========== =========== ===========
</TABLE>
Provisions for income taxes before extraordinary items are composed of the
following (millions of dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------
1996 1995 1994
----------- ----------- -----------
<S> <C> <C> <C>
Current Income Taxes:
Federal................................................ $ 88.0 $ 13.0 $ 46.2
Foreign................................................ 6.4 2.7 .3
State ................................................. 13.7 3.7 6.1
----------- ----------- -----------
108.1 19.4 52.6
----------- ----------- -----------
Deferred Income Taxes:
Federal................................................ 51.4 31.0 42.0
Foreign................................................ 3.0 .5 -
State.................................................. .6 1.2 (2.3)
----------- ----------- -----------
55.0 32.7 39.7
----------- ----------- -----------
Taxes on Income........................................... $ 163.1 $ 52.1 $ 92.3
=========== =========== ===========
</TABLE>
The Company and the Internal Revenue Service ("IRS") Appeals Office have
concluded a tentative settlement of all adjustments proposed through early 1997
to federal income tax returns filed for the years 1985 through 1987. However,
the IRS has notified the Company that additional adjustments will be proposed
for those years. 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 and 1993 is expected to begin in 1997. It is the opinion of
management that adequate provisions for federal income taxes have been reflected
in the consolidated financial statements.
F-31
<PAGE>
Provisions for income taxes were different than the amount computed by
applying the statutory U.S. federal income tax rate to earnings before tax. The
reasons for these differences are (millions of dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------
1996 1995 1994
----------- ----------- -----------
<S> <C> <C> <C>
Tax expense by applying the U.S. federal income
tax rate of 35%........................................ $ 232.1 $ 112.9 $ 113.7
Increases (reductions) in taxes resulting from:
Tight sands gas credit................................. (7.3) (11.3) (10.2)
State income tax cost ................................. 9.2 3.2 2.5
Goodwill............................................... 6.4 6.4 6.4
Exclusion for dividends and equity earnings............ (2.9) (2.9) (5.3)
Full normalization..................................... (1.7) (.4) (2.9)
Research activities credit............................. (11.8) - -
Exclusion for foreign earnings......................... (56.3) (47.8) (6.9)
Depletion and depreciation............................. (6.3) (9.8) (5.2)
Other.................................................. 1.7 1.8 .2
----------- ----------- -----------
Taxes on income .......................................... $ 163.1 $ 52.1 $ 92.3
=========== =========== ===========
</TABLE>
Deferred tax liabilities (assets) which are recognized for the estimated
future tax effects attributable to temporary differences and carryforwards are
(millions of dollars):
<TABLE>
<CAPTION>
December 31,
-----------------------------
1996 1995
----------- ------------
<S> <C> <C>
Excess of book basis over tax basis of property, plant and equipment ..... $ 1,412.1 $ 1,501.4
Pensions and benefit costs................................................ 88.3 35.3
Purchase gas and other recoverable costs.................................. 28.7 38.0
Other..................................................................... - .5
----------- ------------
Deferred tax liabilities.................................................. 1,529.1 1,575.2
----------- ------------
Alternative minimum tax credit carryforward............................... (136.7) (186.8)
Other..................................................................... (7.7) (9.2)
----------- ------------
Deferred tax assets....................................................... (144.4) (196.0)
----------- ------------
Deferred income taxes..................................................... $ 1,384.7 $ 1,379.2
=========== ============
</TABLE>
U.S. income taxes have been provided for earnings of foreign subsidiaries
that are expected to be distributed to the U.S. parent company. Foreign
subsidiaries' cumulative unremitted earnings of approximately $227.8 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
Discontinuation of Regulatory Accounting. The interstate natural gas
pipeline and certain storage subsidiaries of the Company are subject to the
regulations and accounting procedures of the FERC, and have historically
followed the reporting and accounting requirements of FAS 71. FAS 71 provides
that rate regulated enterprises account for and report assets and liabilities
consistent with the economic effect of the way in which regulators establish
rates, if the rates established are designed to recover the costs of providing
the regulated service and if the competitive environment makes it reasonable to
assume that such rates can be charged and collected. As a result of FERC Order
636 (which unbundled pipeline services giving customers more options for
transporting their gas), the effect of discounted rates, and new competitive
developments on the horizon, the Company has concluded that the competitive
environment for these subsidiaries is no longer consistent with the form of
regulation contemplated by FAS 71. Accordingly, effective November 1, 1996,
these subsidiaries have ceased to apply the provisions of FAS 71 to their
transactions and balances, which accounting change has been implemented pursuant
to the guidance contained in Statement of Financial
F-32
<PAGE>
Accounting Standards No. 101, " Regulated Enterprises - Accounting for the
Discontinuance of Application of FASB Statement No. 71". The Company believes
this accounting change will result in financial reporting which better reflects
the results of operations in the economic environment in which these
subsidiaries now operate.
This accounting change has resulted in the elimination from the
Consolidated Balance Sheet of the effects of actions of regulators, which
effects have been recognized as regulatory assets and liabilities recorded
pursuant to FAS 71, and the revaluation of certain other assets. The impact of
these changes was a charge to earnings of $85.6 million, net of related income
taxes of $50.0 million, and is shown as an extraordinary item in the Statement
of Consolidated Operations. The charge to earnings was noncash and will have no
direct effect on the subsidiaries' ability to include the underlying deferred
items in their future rate proceedings or on their ability to collect the rates
set thereby.
Early Extinguishment of Debt. 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.
Note 14. Litigation, Regulatory and Environmental Matters
Litigation. A subsidiary of Coastal initiated a suit against TransAmerican
Natural Gas Corporation ("TransAmerican") in the District Court of Webb County,
Texas for breach of two gas purchase agreements. In February 1993, TransAmerican
filed a Third Party Complaint and a Counterclaim in this action against Coastal
and certain subsidiaries. TransAmerican alleged breach of contract, fraud,
conspiracy, duress, tortious interference and violations of the Texas Free
Enterprises and Anti-trust Act arising out of the gas purchase agreements. Final
judgment in this matter was entered April 22, 1994. The subsidiary was awarded
approximately $2.0 million, including pre-judgment interest and attorney fees.
All of TransAmerican's claims and causes of action were denied. The Court of
Appeals for the Fourth Judicial District has denied TransAmerican's appeal in
this case. TransAmerican subsequently filed a Writ of Error with the Texas
Supreme Court, which was denied in December 1996. In January 1997, TransAmerican
filed a motion for rehearing of its Writ of Error, which is pending before the
Texas Supreme Court.
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 is pending. One 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.
A natural gas producer has filed a claim on behalf of the U.S. government
in the U.S. District Court for the District of Columbia under the federal False
Claims Act. The Second Amended Complaint filed on May 24, 1996, against seventy
(70) defendants, including ANR Pipeline Company ("ANR Pipeline"), CIG and
Coastal States Gas Transmission Company, alleges that the defendants' methods of
measuring the heating content and volume of natural gas purchased from
federally-owned or Indian properties have caused underpayment of royalties to
the U.S. government. The Company's subsidiaries, together with the other
pipeline defendants, have filed a motion to dismiss.
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.
F-33
<PAGE>
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,
results of operations or cash flows.
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 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, and subsequent
tariff filings will indicate each time the pipeline negotiates a rate for
service which exceeds the recourse rate. The FERC is also considering comments
on whether this "negotiated rate" program should be extended to other terms and
conditions of pipeline transportation services.
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.
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 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) and
remanded to the FERC, for further consideration, certain limited aspects of the
Order , such as the basis for its determination of the recovery by the pipelines
of the full level of their prudently incurred transition costs. Several persons,
including ANR Pipeline, have appealed the rate and other aspects of the FERC's
orders approving ANR Pipeline's Order 636 restructuring filings and those
appeals are the subject of further proceedings before the Court.
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 an $85.7 million increase in
the cost of service underlying that approved and 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, which rates are currently in effect, subject to refund.
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 will file exceptions as to some of the negative findings in
the Initial Decision.
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
F-34
<PAGE>
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
has filed with the FERC to increase its discount recovery adjustment in its
pending rate proceeding. ANR Pipeline has sought judicial review of these orders
before the United States Court of Appeals for the D.C. Circuit.
Claims were filed in 1990 in the United States District Court in North
Dakota by Dakota Gasification Company ("Dakota") and the United States
Department of Energy regarding ANR Pipeline's obligations under certain gas
purchase and transportation contracts with the Great Plains Coal Gasification
Plant (the "Plant"). In February 1994, ANR Pipeline, Dakota and the Department
of Energy executed a Settlement Agreement which, subject to FERC approval,
resolves the litigation and disputes among the parties, amends the gas purchase
agreement between ANR Pipeline and Dakota and terminates the transportation
contract with the Plant. In August 1994, ANR Pipeline filed a petition with the
FERC requesting: (i) approval of the Settlement Agreement; (ii) an order
approving ANR Pipeline's proposed tariff mechanism to recover the costs incurred
to implement the Settlement Agreement; and (iii) an order dismissing a then
pending FERC proceeding wherein certain of ANR Pipeline's customers challenged
Dakota's pricing under the original gas supply contract. In December 1996, the
FERC issued an Opinion and Order Reversing Initial Decision in which it found
that the pipelines, including ANR Pipeline, were prudent in entering into the
Settlement Agreement. No appeals were taken of the FERC's decision and it has
become final.
On June 26, 1996, the FERC approved CIG's request for authority to transfer
to its subsidiary, CIG Field Services Company ("CFS"), all of CIG's gathering
facilities except for those in the Panhandle Field. The transferred facilities
had a net book value of approximately $42 million. The June 26, 1996 order
further confirmed that the facilities transferred to CFS would be considered
non-jurisdictional. The FERC issued a related order on September 26, 1996,
accepting CIG's filing under Section 4 of the Natural Gas Act of 1938, as
amended, confirming that CIG no longer offered gathering services through the
transferred facilities. The FERC orders accepting CIG's spin-down and related
Section 4 filings were not appealed and are now final.
On March 29, 1996, CIG filed with the FERC under Docket No. RP96-190 to
increase its rates by approximately $30 million annually and to realign certain
transportation services. On April 25, 1996, the FERC accepted the filing to
become effective October 1, 1996, subject to refund. In the event that the case
cannot be settled, a hearing before a FERC Administrative Law Judge is currently
scheduled for late 1997.
The FERC April 25, 1996 order also accepted tariff sheets filed by CIG to
establish its rights to enter into negotiated rates consistent with the
negotiated rate Policy. CIG's tariff sheets became effective May 1, 1996, and
continue to be effective despite the fact that certain parties have sought
judicial review of the FERC's actions with respect to CIG's negotiated rate
provisions.
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, results of operations or cash flows. 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 $37 million in 1996 on environmental capital
projects and anticipates capital expenditures of approximately $42 million in
1997 in order to comply with such laws and regulations. The majority of the 1997
expenditures is attributable to construction projects at the Company's refining,
chemical and terminal facilities. The Company currently anticipates capital
expenditures for environmental compliance for the years 1998 through 2000 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.
F-35
<PAGE>
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
$333 million, and the Company estimates its pro-rata exposure, to be paid over a
period of several years, is approximately $7.4 million and has made appropriate
provisions. At 4 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 is 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 subsidiaries' 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
$40,000, 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 liquidity, consolidated financial
position or results of operations.
Note 15. Quarterly Results of Operations (Unaudited)
Results of operations by quarter for the years ended December 31, 1996 and
1995 were (millions of dollars except per share):
<TABLE>
<CAPTION>
Quarter Ended
-----------------------------------------------------------------------
March 31, 1996 June 30, 1996 Sept. 30, 1996 Dec. 31, 1996
-------------- ------------- -------------- -------------
<S> <C> <C> <C> <C>
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
========== =========== ========== =========
Earnings (Loss) Per Share:
Before extraordinary items.............. $ .74 $ .58 $ .51 $ 2.71*
Extraordinary items..................... - (.11) - (.81)
---------- ---------- ---------- --------
Net earnings per common and
common equivalent share................. $ .74 $ .47 $ .51 $ 1.90
========== =========== ========== =========
<FN>
* Amounts for 1996 include $177 million, or $1.66 per share, relating to the sale of the Utah coal mining operations.
</FN>
</TABLE>
<TABLE>
<CAPTION>
Quarter Ended
----------------------------------------------------------------------
March 31, 1995 June 30, 1995 Sept. 30, 1995 Dec. 31, 1995
-------------- ------------- -------------- -------------
<S> <C> <C> <C> <C>
Operating revenues......................... $ 2,620.5 $ 2,615.8 $ 2,548.7 $ 2,672.6
Less purchases............................. 1,897.2 1,880.6 1,862.2 1,914.2
---------- ----------- ---------- ---------
723.3 735.2 686.5 758.4
Other income and expenses.................. 665.7 678.0 642.3 647.0
---------- ----------- ---------- ---------
Net earnings............................... $ 57.6 $ 57.2 $ 44.2 $ 111.4
========== =========== ========== =========
Net earnings per common and
common equivalent share................. $ .51 $ .50 $ .38 $ 1.01
========== =========== ========== =========
</TABLE>
F-36
<PAGE>
Note 16. Subsequent Events (Unaudited)
On January 29, 1997, Coastal offered to purchase certain of its debt issues
with a total principal amount outstanding of $1.2 billion. None of these issues
were eligible for redemption and the purchase offer included payment of
premiums. In February 1997, Coastal purchased and retired the following notes
and debentures (millions of dollars):
Principal
Amount
Purchased
---------
10-3/8% Senior Notes, due 2000......................... $ 128.7
10% Senior Notes, due 2001............................. 215.9
9-3/4 Senior Debentures, due 2003...................... 197.7
10-1/4% Senior Debentures, due 2004.................... 162.3
10-3/4% Senior Debentures, due 2010.................... 93.4
---------
$ 798.0
Coastal will incur an after-tax extraordinary charge in the first quarter
of 1997 of approximately $90.0 million in connection with the repurchase of
these debt securities.
In February 1997, the Company issued $200.0 million of 6.7% 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
notes and debentures referred to above.
F-37
<PAGE>
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
Reserves, capitalized costs, costs incurred in oil and gas acquisition,
exploration and development activities, results of operations and the
standardized measure of discounted future net cash flows are presented for the
exploration and production segment. Natural gas systems reserves and the related
standardized measure of discounted future net cash flows are separately
presented for natural gas operations. Substantially all of the Company's
properties are located in the United States.
<TABLE>
<CAPTION>
Estimated Quantities of Proved Reserves
Natural Gas Exploration
Systems and Production
----------- -------------------------
Developed Developed Undeveloped Total
----------- --------- ----------- ---------
<S> <C> <C> <C> <C>
Natural Gas (MMcf):
1996 ................................................. 267,927 757,117 431,488 1,456,532
1995 ................................................. 302,420 543,509 307,555 1,153,484
1994 ................................................. 334,597 479,660 144,157 958,414
Oil, Condensate and Natural Gas Liquids (000 barrels):
1996 ................................................. 391 30,328 13,743 44,462
1995 ................................................. 126 30,400 5,764 36,290
1994 ................................................. 11 28,030 5,636 33,677
</TABLE>
Changes in proved reserves since the end of 1993 are shown in the following
table:
<TABLE>
<CAPTION>
Oil, Condensate and
Natural Gas Natural Gas Liquids
(MMcf) (000 barrels)
---------------------------- ----------------------------
Natural Exploration Natural Exploration
Gas and Gas and
Total Proved Reserves Systems Production Systems Production
- --------------------- ----------- ------------- ----------- ------------
<S> <C> <C> <C> <C>
Total, end of 1993.............................. 379,795 545,734 7 28,786
-------- ---------- ------- ---------
Production during 1994.......................... (46,288) (79,485) (1) (4,466)
Extensions and discoveries...................... - 106,985 - 3,932
Acquisitions.................................... - 36,924 - 5,010
Sales of reserves in-place...................... - (4,031) - (931)
Revisions of previous quantity estimates and
other......................................... 1,090 17,690 5 1,335
-------- ---------- ------- ---------
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
======== ========== ======= =========
</TABLE>
F-38
<PAGE>
Total proved reserves for natural gas systems exclude storage gas and
liquids volumes. The natural gas systems storage gas volumes are 153,276,
143,134 and 153,781 million cubic feet and storage liquids volumes are
approximately 192,000, 138,000 and 172,000 barrels at December 31, 1996, 1995
and 1994, respectively. Total proved reserves include approximately 90,000,
90,000 and 27,000 MMcf equivalents associated with volumetric production
payments sold by the Company for the years 1996, 1995 and 1994, 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 and results of operations contain certain capitalized and expense
transactions attributable to start-up activities connected with international
operations. These capitalized and expensed international transactions are not
material in nature.
<TABLE>
<CAPTION>
Capitalized Costs Relating to Exploration and Production Activities
(Millions of dollars)
December 31,
--------------------
1996 1995
-------- --------
<S> <C> <C>
Proved and Unproved Properties
- ------------------------------
Proved................................................................................... $ 1,488 $ 1,332
Unproved................................................................................. 117 63
-------- --------
1,605 1,395
Accumulated depreciation, depletion and amortization..................................... (627) (604)
-------- --------
$ 978 $ 791
======== ========
</TABLE>
The Company follows the full-cost method of accounting for oil and gas
properties.
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, 1996. 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 3 years.
<TABLE>
<CAPTION>
Costs Excluded from Amortization
(Millions of Dollars)
Year Costs Incurred
--------------------------------------------------------------
Prior to
Total 1996 1995 1994 1994
--------- --------- -------- -------- ---------
<S> <C> <C> <C> <C> <C>
Property acquisition............................. $ 29 $ 25 $ 4 $ - $ -
Exploration...................................... 35 24 11 - -
Development...................................... 5 4 1 - -
--------- --------- -------- -------- ---------
$ 69 $ 53 $ 16 $ - $ -
--------- --------- -------- -------- ---------
</TABLE>
F-39
<PAGE>
<TABLE>
<CAPTION>
Costs Incurred in Oil and Gas Acquisition, Exploration and Development
Activities
(Millions of dollars)
Year Ended December 31,
--------------------------------
1996 1995 1994
-------- -------- --------
<S> <C> <C> <C>
Property acquisition costs:
Proved................................................................. $ 42 $ 65 $ 20
Unproved............................................................... 27 16 5
Exploration costs............................................................ 48 33 29
Development costs............................................................ 255 112 91
</TABLE>
<TABLE>
<CAPTION>
Results of Operations for Exploration and Production Activities
(Millions of dollars)
Year Ended December 31,
--------------------------------
1996 1995 1994
-------- -------- --------
<S> <C> <C> <C>
Revenues:
Sales..................................................................... $ 113 $ 112 $ 115
Transfers................................................................. 282 112 118
-------- -------- --------
Total.................................................................. 395 224 233
-------- -------- --------
Production costs............................................................. (81) (85) (71)
Operating expenses........................................................... (24) (27) (29)
Depreciation, depletion and amortization..................................... (155) (103) (104)
-------- -------- --------
135 9 29
Income tax (expense) benefit................................................. (40) 5 1
-------- -------- --------
Results of operations for producing activities (excluding corporate
overhead and interest costs).............................................. $ 95 $ 14 $ 30
======== ======== ========
</TABLE>
The average domestic amortization rate per equivalent Mcf was $0.88 in
1996, $0.89 in 1995 and $0.96 in 1994. Depreciation, depletion and amortization
includes provisions for the impairment of international projects of $14.6
million in 1996, $0.8 million in 1995 and $1.1 million in 1994.
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-40
<PAGE>
The standardized measure is not intended to represent the market value of
reserves and, in view of the uncertainties involved in the reserve estimation
process, including the instability of energy markets as evidenced by recent
declines in both natural gas and crude oil prices, may be subject to material
future revisions (millions of dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------------------------------------------------------------
1996 1995 1994
------------------------- ------------------------- --------------------------
Natural Exploration Natural Exploration Natural Exploration
Gas and Gas and Gas and
Systems Production Systems Production Systems Production
---------- ----------- --------- ----------- --------- -----------
<S> <C> <C> <C> <C> <C> <C>
Future cash inflows.......... $ 430 $ 5,384 $ 286 $ 2,281 $ 235 $ 1,617
Future production and development
costs....................... (85) (1,432) (82) (964) (65) (717)
Future income tax expenses... (117) (1,141) (68) (294) (58) (176)
----------- ----------- ----------- ----------- ----------- -----------
Future net cash flows........ 228 2,811 136 1,023 112 724
10% annual discount for estimated
timing of cash flows........ (88) (851) (61) (304) (44) (196)
----------- ----------- ------------ ----------- ----------- ------------
Standardized measure of discounted
future net cash flows....... $ 140 $ 1,960 $ 75 $ 719 $ 68 $ 528
=========== =========== =========== =========== =========== ===========
</TABLE>
Future cash inflows include $245 million for 1996, $111 million for 1995 and $29
million for 1994 related to volumes dedicated to volumetric production payments
sold by the Company.
Principal sources of change in the standardized measure of discounted future net
cash flows during each year are (millions of dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------------------------------------------------------------
1996 1995 1994
------------------------- ------------------------- --------------------------
Natural Exploration Natural Exploration Natural Exploration
Gas and Gas and Gas and
Systems Production Systems Production Systems Production
----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Sales and transfers, net of
production costs............ $ (45) $ (304) $ (31) $ (136) $ (39) $ (148)
Net changes in prices and
production costs............ 95 874 46 88 (15) (183)
Extensions and discoveries... 4 941 - 187 - 119
Acquisitions................. - 188 1 109 - 43
Sales of reserves in-place... - (27) - - - (4)
Development costs incurred
during the period that
reduced estimated future
development costs........... - 36 - 21 - 24
Revisions of previous quantity
estimates, timing and other. 39 26 (15) (70) 1 23
Accretion of discount........ 7 57 7 49 11 55
Net change in income taxes... (35) (550) (1) (57) 15 37
----------- ----------- ----------- ----------- ----------- -----------
Net change................... $ 65 $ 1,241 $ 7 $ 191 $ (27) $ (34)
=========== =========== =========== =========== =========== ===========
</TABLE>
None of the amounts include any value for natural gas systems storage gas and
liquids volumes, which was approximately 39 Bcf for CIG, 114 Bcf for ANR
Pipeline and 192,000 barrels of liquids for CIG at the end of 1996.
F-41
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT
THE COASTAL CORPORATION
BALANCE SHEET
(Millions of Dollars)
<TABLE>
<CAPTION>
December 31,
------------------------
1996 1995
--------- ---------
ASSETS
<S> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents......................................................... $ 15.6 $ 3.3
Receivables....................................................................... 32.6 56.2
Receivables from subsidiaries..................................................... 1,553.9 1,745.1
Prepaid expenses and other........................................................ 5.7 1.5
--------- ---------
Total Current Assets........................................................... 1,607.8 1,806.1
--------- ---------
PROPERTY, PLANT AND EQUIPMENT - at cost, net......................................... .9 1.1
--------- ---------
INVESTMENTS IN SUBSIDIARIES AND OTHER ASSETS:
Investment in subsidiaries at cost plus equity in undistributed earnings since
acquisition.................................................................... 3,625.6 3,294.9
Due from subsidiaries............................................................. 324.8 541.6
Deferred federal income taxes..................................................... 18.2 110.0
Other assets...................................................................... 275.3 253.5
--------- ---------
4,243.9 4,200.0
--------- ---------
$ 5,852.6 $ 6,007.2
========= =========
</TABLE>
See Notes to Condensed Financial Statements.
S-1
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT
THE COASTAL CORPORATION
BALANCE SHEET
(Millions of Dollars)
<TABLE>
<CAPTION>
December 31,
------------------------
1996 1995
--------- ---------
LIABILITIES AND STOCKHOLDERS' EQUITY
<S> <C> <C>
CURRENT LIABILITIES:
Notes payable..................................................................... $ 105.0 $ 73.2
Accounts payable and accrued expenses............................................. 57.7 133.9
Payable to subsidiaries........................................................... 756.5 260.8
Current maturities on long-term debt.............................................. - 121.5
--------- ---------
Total Current Liabilities...................................................... 919.2 589.4
--------- ---------
DEBT:
Long-term debt.................................................................... 1,896.6 2,610.9
--------- ---------
DEFERRED CREDITS AND OTHER........................................................... .3 128.1
--------- ---------
COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY.......................................... 3,036.5 2,678.8
--------- ---------
$ 5,852.6 $ 6,007.2
========= =========
</TABLE>
See Notes to Condensed Financial Statements.
S-2
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT
THE COASTAL CORPORATION
STATEMENT OF OPERATIONS
(Millions of Dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------
1996 1995 1994
--------- --------- ---------
<S> <C> <C> <C>
OPERATING REVENUES..................................................... $ - $ - $ .2
OPERATING COSTS AND EXPENSES........................................... - - -
--------- --------- ---------
OPERATING PROFIT....................................................... - - .2
--------- --------- ---------
OTHER INCOME:
Equity in net earnings of subsidiaries.............................. 465.5 384.2 334.8
Interest income from subsidiaries - net............................. 119.2 152.7 125.3
Other income - net.................................................. 28.3 17.1 14.0
--------- --------- ---------
613.0 554.0 474.1
--------- --------- ---------
OTHER EXPENSES (BENEFITS):
General and administrative.......................................... 6.6 10.4 10.1
Interest and debt expense........................................... 245.4 305.8 306.9
Taxes on income..................................................... (53.6) (32.6) (75.3)
--------- --------- ---------
198.4 283.6 241.7
--------- --------- ---------
EARNINGS BEFORE EXTRAORDINARY ITEM..................................... 414.6 270.4 232.6
--------- --------- ---------
EXTRAORDINARY ITEM, NET OF INCOME TAXES:
Loss on early extinguishment of debt................................ (12.0) - -
--------- --------- ---------
NET EARNINGS........................................................... $ 402.6 $ 270.4 $ 232.6
========= ========= =========
</TABLE>
See Notes to Condensed Financial Statements.
S-3
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT
THE COASTAL CORPORATION
STATEMENT OF CASH FLOWS
(Millions of Dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------
1996 1995 1994
--------- --------- ---------
<S> <C> <C> <C>
Net Cash Flow From Operating Activities:
Earnings before extraordinary item.................................. $ 414.6 $ 270.4 $ 232.6
Items not requiring (providing) cash:
Depreciation, depletion and amortization......................... .1 .1 .3
Deferred income taxes............................................ 44.8 (22.0) 14.1
Undistributed subsidiary earnings................................ (340.9) (260.9) (266.9)
Working capital and other changes, excluding changes relating to
cash and non-operating activities:
Receivables................................................... 30.1 (29.5) (9.2)
Prepaid expenses and other.................................... (.3) 1.2 (1.3)
Accounts payable and accrued expenses......................... (76.2) 25.7 46.7
Other......................................................... (24.2) (11.1) (54.2)
--------- --------- ---------
48.0 (26.1) (37.9)
--------- --------- ---------
Cash Flow from Investing Activities:
Purchases of property, plant and equipment.......................... (.1) (.1) (.1)
Proceeds from sale of property, plant and equipment ................ - - 4.9
Net change in accounts with subsidiaries............................ 903.8 12.4 260.8
Investments in subsidiaries......................................... (77.2) - -
Proceeds from investments........................................... - 19.3 -
--------- --------- ---------
826.5 31.6 265.6
--------- --------- ---------
Cash Flow from Financing Activities:
Increase (decrease) in short-term notes............................. (268.2) 322.7 (203.0)
Proceeds from issuing common stock.................................. 14.7 10.5 5.4
Proceeds from long-term debt issues................................. - 218.5 -
Payments to retire long-term debt................................... (549.1) (500.6) (79.4)
Dividends paid...................................................... (59.6) (59.3) (59.3)
--------- ---------- ---------
(862.2) (8.2) (336.3)
--------- --------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents................... 12.3 (2.7) (108.6)
Cash and Cash Equivalents at Beginning of Year......................... 3.3 6.0 114.6
--------- --------- ---------
Cash and Cash Equivalents at End of Year............................... $ 15.6 $ 3.3 $ 6.0
========= ========= =========
</TABLE>
See Notes to Condensed Financial Statements.
S-4
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT
THE COASTAL CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS
Note 1. Summary of Significant Accounting Policies
Principles of Consolidation -- The financial statements of the Company
reflect the investment in wholly-owned subsidiaries using the equity method.
Statement of Cash Flows -- For purposes of this statement, cash equivalents
include time deposits, certificates of deposit and all highly liquid instruments
with original maturities of three months or less. The Company made cash payments
for interest and financing fees of $279.0 million, $333.5 million and $340.6
million in 1996, 1995 and 1994, respectively. Cash payments (refunds - primarily
from subsidiaries) for income taxes amounted to $(41.9) million, $(44.5) million
and $(62.2) million for 1996, 1995 and 1994, 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 $81.8 million of guaranteed
long-term debt of subsidiaries was outstanding at December 31, 1996, 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 1996 are (millions of dollars):
1997................. $ - 2000........... $ 250.0
1998................. - 2001........... 300.0
1999................. 150.1
Note 4. Dividends Received
Cash dividends received from consolidated subsidiaries were as follows:
1996 - $124.6 million, 1995 - $123.3 million and 1994 - $67.9 million.
S-5
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(Millions of Dollars)
<TABLE>
<CAPTION>
Additions
Balance at Charged to Balance
Beginning Costs and at End
Description of Year Expenses Other of Year
- ----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Year Ended December 31, 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
===== ===== ===== =======
Year Ended December 31, 1994
Allowance for doubtful accounts.................... $16.1 $ 6.2 $(3.3)(A) $ 19.0
===== ===== ===== =======
<FN>
- --------
(A) Accounts charged off net of recoveries.
</FN>
</TABLE>
S-6
<PAGE>
EXHIBIT INDEX
Exhibit
Number Document
- -------- --------------------------------------------------------------------
3.1+ Restated Certificate of Incorporation of Coastal, as restated on
March 22, 1994. (Filed as Module TCC- Artl-Incorp on March 28, 1994).
3.2+ By-Laws of Coastal, as amended on January 16, 1990 (Exhibit 3.4 to
Coastal's Annual Report on Form 10-K for the fiscal year ended
December 31, 1989).
4 (With respect to instruments defining the rights of holders of long-
term debt, the Registrant will furnish to the Commission, on request,
any such documents).
10.1+ 1984 Stock Option Plan (Appendix B to Coastal's Proxy Statement for
the 1984 Annual Meeting of Stockholders, dated May 14, 1984).
10.2+ 1985 Stock Option Plan (Appendix A to Coastal's Proxy Statement for
the 1986 Annual Meeting of Stockholders, dated March 27, 1986).
10.3+ The Coastal Corporation Performance Unit Plan effective as of
January 1, 1987 (Exhibit 10.5 to Coastal's Annual Report on Form
10-K for the fiscal year ended December 31, 1987).
10.4+ The Coastal Corporation Replacement Pension Plan effective as of
November 1, 1987 (Exhibit 10.6 to Coastal's Annual Report on Form
10-K for the fiscal year ended December 31, 1987).
10.5+ Description of Coastal's Key Employees Bonus Plan (Exhibit 10.7 to
Coastal's Annual Report on Form 10-K for the fiscal year ended
December 31, 1987).
10.6+ The Coastal Corporation Stock Purchase Plan, as restated on
January 1, 1994 (Appendix B to Coastal's Proxy Statement for the
1994 Annual Meeting of Stockholders dated March 29, 1994).
10.7+ The Coastal Corporation Stock Grant Plan, effective December 1,
1988 (Exhibit 10.12 to Coastal's Annual Report on Form 10-K for
the fiscal year ended December 31, 1988).
10.8+ The Coastal Corporation Deferred Compensation Plan for Directors
(Exhibit 10.13 to Coastal's Annual Report on Form 10-K for the
fiscal year ended December 31, 1988).
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+ Employment Agreement between The Coastal Corporation and James F.
Cordes dated April 12, 1990 (Exhibit 10.13 to Coastal's Annual
Report on Form 10-K for the fiscal year ended December 31, 1990).
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).
<PAGE>
EXHIBIT INDEX
Exhibit
Number Document
- ------- --------------------------------------------------------------------
10.14+ Pension Plan for Employees of The Coastal Corporation as of
January 1, 1993, as further amended by the Fourth Amendment dated
May 20, 1994, Fifth Amendment dated August 17, 1994, Sixth
Amendment dated August 30, 1994, Seventh Amendment dated October
30, 1995, Eighth Amendment dated December 29, 1995 and Ninth
Amendment dated December 29, 1995 (Exhibit 10.14 to Coastal's
Annual Report on Form 10-K for the fiscal year ended December 31,
1995).
10.15+ Pension Plan for Employees of The Coastal Corporation as of
January 1, 1993, as further amended by the Tenth Amendment dated
March 25, 1996 (Exhibit 10.15 to Coastal's Quarterly Report on
Form 10-Q for the period ended March 31, 1996).
10.16+ Pension Plan for Employees of The Coastal Corporation as of
January 1, 1993, as further amended by the Twelfth Amendment dated
August 29, 1996 and the Thirteenth Amendment dated September 16,
1996 (Exhibit 10.16 to Coastal's Quarterly Report on Form 10-Q for
the period ended September 30, 1996).
10.17* Pension Plan for Employees of The Coastal Corporation as of
January 1, 1993, as further amended by the Eleventh Amendment
dated December 6, 1996.
11* Statement re Computation of Per Share Earnings.
21* Subsidiaries of Coastal.
23* Consent of Deloitte & Touche LLP.
24* Powers of Attorney (included on signature pages herein).
27* Financial Data Schedule.
99+ Indemnity Agreement revised and updated as of April, 1988 (Exhibit
28 to Coastal's Annual Report on Form 10-K for the fiscal year ended
December 31, 1990).
- -------------------------
Note:
+ Indicates documents incorporated by reference from the prior
filing indicated.
* Indicates documents filed herewith.
Exhibit 10.17
ELEVENTH AMENDMENT TO THE PENSION PLAN
FOR EMPLOYEES OF THE COASTAL CORPORATION
THIS AMENDMENT is made the 6th day of December, 1996, by The Coastal
Corporation, a Delaware corporation (hereinafter referred to as the "Company").
WITNESSETH:
WHEREAS, the Company wishes to amend The Pension Plan for Employees of The
Coastal Corporation (the "Plan") to clarify various provisions in order to
obtain a determination letter from the Internal Revenue Service and to maintain
the Plan as a qualified Plan;
NOW, THEREFORE, the Plan is amended as follows:
1. Section 1.2A is amended by adding at the end of the second paragraph:
"For purposes of applying the Code Section 401(a)(17) limit to
Average Annual Compensation, if any Employee is a family member (spouse
and lineal descendants who have not attained the age of 19 before the
end of the Plan Year) of either (a) a five percent owner or (b) a
Highly Compensated Employee who is one of the ten most Highly
Compensated Employees ranked on the basis of Compensation paid by the
Employer during such Plan Year, then the Average Annual Compensation
with respect to such Employees shall be aggregated with all other
members of such family unit. If applicable, the Code Section 401
(a)(17) limit will be allocated among the members of the family unit in
proportion to the Average Annual Compensation of each family member
that is combined to determine the aggregate."
2. Section 1.2B is amended by adding a second paragraph:
"In no event shall Basic Compensation of a Participant taken
into account under the Plan for any Plan Year exceed $150,000 (or such
greater amount provided pursuant to Section 401(a)(17) of the Code. For
purposes of applying the Code Section 401(a)(17) limit to Basic
Compensation, if any Employee is a family member (spouse and lineal
descendants who have not attained the age of 19 before the end of the
Plan Year) of either (a) a five percent owner or (b) a Highly
Compensated Employee who is one of the ten most Highly Compensated
Employees ranked on the basis of Compensation paid by the Employer
during such Plan Year, then the Basic Compensation with respect to such
Employees shall be aggregated with all other members of such family
unit. If applicable, the Code Section 401 (a)(17) limit will be
allocated among the members of the family unit in proportion to the
Basic Compensation of each family member that is combined to determine
the aggregate."
3. Item 7 of the Fourth Amendment, dated May 20, 1994 is deleted.
4. Section 1.14 is amended in its entirety to read as follows:
"1.14 (a) "Hour of Service" means a period of time consisting
of an individual's period of employment with the Company, a Subsidiary
or a Related Employer and for all purposes except vesting means (i)
each hour for which an individual is paid, or entitled to payment, for
the performance of duties during a period of employment with the
Company, a Subsidiary or a Related Employer; and (ii) each hour for
which an individual is directly or indirectly paid by the Company, a
Subsidiary or a Related Employer or is entitled to payment from the
Company, a Subsidiary or a Related Employer during which no duties are
performed by reason of vacation, holiday, illness, incapacity
(including disability), layoff, jury duty, military duty or leave of
absence. Each Hour of Service for which back pay, irrespective of
mitigation of damages, is either awarded or agreed to by the Company, a
Subsidiary or a Related Employer shall be included under either (i) or
(ii) as may be appropriate. Hours of Service shall be credited:
1
<PAGE>
(A) in the case of hours referred to in clause (i) of
the first sentence of this subsection, for the computation
period in which the duties are performed;
(B) in the case of hours referred to in clause (ii)
of the first sentence of this subsection, for the computation
period or periods in which the period during which no duties
are performed occurs; and
(C) in the case of hours for which back pay is
awarded or agreed to by the Company, a Subsidiary or a Related
Employer for the computation period or periods to which the
award or agreement pertains rather than to the computation
period in which the award, agreement or payment is made.
(b) In determining Hours of Service an individual who is
employed by the Company, a Subsidiary or a Related Employer on other
than an hourly rated basis shall be credited with ten Hours of Service
per day for each day the individual would, if hourly rated, be credited
with service pursuant to clause (i) of the first sentence of subsection
(a). If an individual is paid for reasons other than the performance of
duties pursuant to clause (ii) of the first sentence of subsection (a):
(i) in the case of a payment made or due that is calculated on the
basis of units of time, an individual shall be credited with the number
of regularly scheduled working hours included in the units of time on
the basis of which the payment is calculated; and (ii) an individual
without a regular work schedule shall be credited with eight Hours of
Service per day (to a maximum of forty Hours of Service per week) for
each day that the individual is so paid. Hours of Service shall be
calculated in accordance with Department of Labor Regulations Section
2530.200b-2 or any future legislation or regulation that amends,
supplements or supersedes that section.
(c) Hour of Service includes each hour for which an individual
is disabled and eligible to receive disability income benefits under a
disability plan maintained by the Company, a Subsidiary or a Related
Employer. Hours of Service during such disability periods shall be
determined pursuant to the procedure in subsection (b) for an
individual without a regular work schedule. Provided, however, that if
the cause of the disability of such disabled individual is
nonoccupational, Hours of Service credited pursuant to this provision
shall not exceed the greater of the number of Hours of Service equal to
three Years of Service or the number of Hours of Service such
individual had credited under the Plan prior to the time such
individual became disabled.
(d) Hour of Service for purposes of vesting only, means an
hour for which an individual is paid, or entitled to payment, by the
Company, a Subsidiary or a Related Employer for the performance of
duties for the Company, a Subsidiary or a Related Employer and an hour
for which an individual is disabled and eligible to receive disability
income benefits under a disability plan maintained by the Company, a
Subsidiary, or a Related Employer. Provided, however, that if the cause
of the disability of such disabled individual is nonoccupational, Hours
of Service credited pursuant to this provision shall not exceed the
greater of the number of Hours of Service equal to three Years of
Service or the number of Hours of Service such individual had credited
under the Plan prior to the time such individual became disabled. Hours
of Service during such disability periods shall be determined pursuant
to the procedure in subsection (b) for an individual without a regular
work schedule.
(e) For purposes of eligibility to participate in the Plan and
vesting, Hour of Service shall include hours during an approved leave
of absence granted by the Company to an individual on or after August
5, 1993 pursuant to the Family and Medical Leave Act, if the individual
returns to employment with the Company at the end of such leave of
absence.
(f) Hours of Service credited for a period of time during
which an individual is absent from service for any reason other than
disability, jury duty or military leave may not exceed six months. This
limitation applies only for purposes of determining eligibility to
participate in the Plan and Retirement Income since vesting is
determined based on the elapsed time method."
2
<PAGE>
5. Section 1.28 is amended to read in its entirety as follows:
"1.28 "Years of Service" means a period of time consisting of
an individual's period of employment with the Company, a Subsidiary or
a Related Employer determined as follows. Years of Service is defined
differently for purposes of eligibility to participate, vesting and
determination of Retirement Income.
(a) Eligibility. (i) For purposes of eligibility to
participate in the Plan, Years of Service shall be based upon the
twelve-consecutive-month period commencing upon an individual's date of
employment or reemployment, as is appropriate, with the Company, a
Subsidiary or a Related Employer for the initial year and for
subsequent periods (including the Plan Year which includes the first
anniversary of the individual's date of employment or reemployment, as
is appropriate) shall be based upon the calendar year.
(ii) For Plan Years before 1990, Years of Service for
purposes of eligibility are measured based upon the
individual's employment or reemployment date and anniversaries
thereof in lieu of the calendar year. The amendment adopting
the calendar year provision for years after 1989 with respect
to eligibility was dated February 6, 1990. With respect to the
period of time beginning on January 1, 1990 and ending on
February 6, 1990, an individual shall receive the greater of
the Years of Service calculated using the provisions in effect
prior to 1990 and the provisions which became effective
January 1, 1990 for purposes of determining eligibility to
join the Plan.
(b) Vesting. For purposes of determining the vesting of a
Participant under the Plan, Years of Service means an aggregated period
of time commencing with an individual's first day of employment or
reemployment by the Company, a Subsidiary or a Related Employer and
ending on the first day of a Period of Severance. An individual shall
also receive credit for any Period of Severance of less than twelve
consecutive months. Fractional periods of less than a year shall be
expressed in terms of days. Notwithstanding the foregoing provisions of
this Section, if an individual separates from the service of the
Company, a Subsidiary or a Related Employer for any reason other than a
termination, retirement or discharge (such as vacation, holiday,
sickness, disability, leave of absence or layoff) and subsequently
quits, retires or is discharged, such individual will not receive more
than one Year of Service after such individual first separates from
service; provided, however, that an individual may receive more than
one Year of Service if such individual is credited with Hours of
Service pursuant to provisions relating to Hours of Service while such
individual is disabled.
(c) Retirement Income. (i) For purposes of determining a
Participant's Retirement Income pursuant to Article V of the Plan,
Years of Service shall be measured in completed months based on Plan
Years.
(ii) For purposes of determining a Participant's
Retirement Income pursuant to Article V, a Participant's Years
of Service shall only include Plan Years in which he completes
at least 1,000 Hours of Service as a Participant. For this
purpose, a Participant who was required to complete a Year of
Service to be eligible to participate in the Plan shall
receive credit for such Year of Service. However, no
Retirement Income is due to an individual who has not met the
eligibility requirements to become a Participant. If a
Participant has fewer than 1,000 Hours of Service in his first
or last Year of Service, or both, his Years of Service for
purposes of determining his Retirement Income shall be
combined to reflect the number of months in such individual's
first and last Years of Service in which such individual
completes Hours of Service as a Participant.
(iii) For purposes of determining eligibility to
participate and Retirement Income under the Plan, Years of
Service shall only include Plan Years, or periods commencing
on an individual's date of employment or reemployment by the
Company, a Subsidiary or a Related Employer in which such
individual completes at least 1,000 Hours of Service with the
Company, any Subsidiary and any Related Employer.
3
<PAGE>
(iv) Years of Service for purposes of determining a
Participant's Retirement Income shall not include any complete
calendar month during which the individual was not credited
with an Hour of Service.
(v) Years of Service for purposes of determining a
Participant's Retirement Income shall not include any period
of an individual's employment with the Company, a Subsidiary
or Related Employer prior to January 1, 1976 during a period
of time when such individual's customary employment was for
less than five months per year or for less than 20 hours per
week.
(vi) For purposes of determining a Participant's
Retirement Income under this Plan, including the reemployment
provisions of the Plan, Years of Service shall not include any
period of a Participant's employment prior to the date as of
which the accrued benefit of such Participant was transferred
from this Plan to a qualified pension plan maintained by an
entity which is not the Company, a Subsidiary or a Related
Employer; provided, however, that such Years of Service shall
include such period if such Participant is reemployed and such
accrued benefit is transferred back to this Plan.
(vii) Years of Service credited for a period of time
during which an individual is absent from service for any
reason other than disability, jury duty or military leave may
not exceed six months. This limitation applies only for
purposes of determining Retirement Income since vesting is
determined based on the elapsed time method.
(d) All Purposes. (i) Years of Service shall include any
period in which an individual is absent to serve in the armed forces of
the United States under circumstances whereby such individual is
entitled to reemployment rights under applicable law, if such
individual returns or offers to return to work prior to the expiration
of such reemployment rights; provided that during such period of
absence, hours shall be deemed to have been worked and paid for at the
usual and customary rate for the individual preceding the absence.
(ii) Years of Service shall not include any period of
an individual's employment for an organization prior to the
date that it became a Subsidiary or a Related Employer and
shall not include any period of an individual's employment for
an organization whose business and assets are acquired by the
Company, a Subsidiary or a Related Employer, unless specific
provision to the contrary is included in the Plan.
(iii) If an individual who has had a Break in Service
is reemployed by the Company, a Subsidiary or a Related
Employer, his Years of Service shall include the Years of
Service to his credit at the time the Break in Service began,
unless such individual had no vested interest in his Accrued
Benefit prior to such Break in Service and the length of the
Break in Service equals or exceeds the greater of five Years
of Service or the Years of Service to such individual's credit
at the time such Break in Service began; provided, however,
that Years of Service for periods of time before 1976 shall be
added to Years of Service after 1975 only for individuals who
were active employees or on approved leave of absence as of
January 1, 1976. For individuals with Years of Service under
the ANR Plan, the preceding sentence shall be applied by
substituting 1975, 1974, and January 1, 1975 for 1976, 1975
and January 1, 1976, respectively.
(iv) Years of Service shall include a period of time
for which an individual is credited with an Hour of Service."
6. Clause (b) of Section 11.1 is amended to read in its entirety as
follows:
"(b) directly or indirectly affecting the schedule set forth
in Section 5.4 used to determine the vested interest of a Participant
on the effective date of the amendment unless (i) the conditions of
Section 411(a)(10) of the Code are satisfied and (ii) each Participant
whose nonforfeitable percentage of his accrued benefit is determined
under Section 5.4 and who has completed three Years of Service with the
Employer, may
4
<PAGE>
elect, during the election period, to have the nonforfeitable percentage
determined under the old vesting schedule."
7. The introductory paragraph of Section 13.5 is amended to add at the end:
"; provided, however, that the following formula for vesting of Top-Heavy
Participants shall be at least as favorable at all points in time as the
formula set forth in Section 5.4:"
8. Except for the preceding, all of the terms of the Plan shall remain in
full force and effect.
IN WITNESS WHEREOF, the Company has caused this instrument to be executed
by its duly authorized officers and their corporate seals to be affixed hereto
as of the date indicated above.
ATTEST: THE COASTAL CORPORATION
(Seal)
AUSTIN M. O'TOOLE By: DAVID A. ARLEDGE
- ------------------------- -------------------------
Austin M. O'Toole David A. Arledge
Senior Vice President and President and Chief
Secretary Executive Officer
5
Exhibit 11
THE COASTAL CORPORATION AND SUBSIDIARIES
STATEMENT RE COMPUTATION OF PER SHARE EARNINGS
(Millions of Dollars, Except Per Share Amounts, and Thousands of Shares)
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------
1996 1995 1994
--------- --------- ---------
<S> <C> <C> <C>
COMMON STOCK AND EQUIVALENTS:
- ----------------------------
Net earnings applicable to common stock and common
stock equivalents................................................... $ 385.2 $ 253.0 $ 215.2
========= ========= =========
Average number of common shares outstanding............................ 105,103 104,478 104,266
Class A common shares.................................................. 390 411 421
Common share equivalent:
$1.19 Cumulative Convertible Preferred, Series A*................... 221 228 235
Dilutive effect of outstanding stock options after application of
treasury stock method*.............................................. 621 318 285
--------- --------- ---------
Average common and common equivalent shares............................ 106,335 105,435 105,207
========= ========= =========
Net earnings per average common and common equivalent shares outstanding:
Earnings before extraordinary items................................. $ 4.54 $ 2.40 $ 2.05
Extraordinary items................................................. (.92) - -
--------- --------- ---------
Net earnings ....................................................... $ 3.62 $ 2.40 $ 2.05
========= ========= =========
ASSUMING FULL DILUTION:
- ----------------------
Net earnings applicable to common stock and common
stock equivalents................................................... $ 385.2 $ 253.0 $ 215.2
Dividends applicable to dilutive preferred stock:
Series B............................................................ .1 .2 .2
Series C............................................................ .2 .2 .2
--------- --------- ---------
Adjusted net earnings assuming full dilution........................... $ 385.5 $ 253.4 $ 215.6
========= ========= =========
Average number of common shares outstanding............................ 105,103 104,478 104,266
Class A common shares.................................................. 390 411 421
Common share equivalents:
Series A Preferred Stock*........................................... 221 228 235
Equivalent common shares from:
Series B and C Preferred Stock*..................................... 508 536 564
Dilutive effect of outstanding stock options after application of
treasury stock method*.............................................. 848 553 293
--------- --------- ---------
Fully diluted shares................................................... 107,070 106,206 105,779
========= ========= =========
Fully diluted earnings per share**:
Earnings before extraordinary items................................. $ 4.52 $ 2.39 $ 2.04
Extraordinary items................................................. (.92) - -
--------- --------- ---------
Net earnings ....................................................... $ 3.60 $ 2.39 $ 2.04
========= ========= =========
<FN>
_______________________
* Convertible securities and options are not considered in the calculations if the effect of the conversion is anti-
dilutive.
** Reporting not required by generally accepted accounting principles
because of small variance from earnings on average common and common
equivalent shares.
</FN>
</TABLE>
Exhibit 21
SUBSIDIARIES OF THE COASTAL CORPORATION
<TABLE>
<CAPTION>
State or Other Jurisdiction of
Incorporation or Organization
------------------------------
<S> <C>
Coastal Capital Corporation .......................................................... Delaware
Coastal Finance Corporation................................................... Delaware
Coastal Financial B.V......................................................... The Netherlands
Coastal Financial Antilles N.V........................................ Netherlands Antilles
Coastal Netherlands Financial B.V............................................. The Netherlands
Coastal Offshore Insurance Ltd................................................ Bermuda
Coastal Coal, Inc..................................................................... Delaware
Coastal Gas Services Company.......................................................... Delaware
ANR Gas Supply Company........................................................ Delaware
ANR Transportation Services Company........................................... Delaware
Coastal Electric Services Company............................................. Delaware
Coastal Field Services Company................................................ Delaware
CIG Merchant Company.................................................. Delaware
Coastal Gas Gathering and Processing Company.......................... Delaware
Coastal Dauphin Island Company, L.L.C...................... Delaware
Blacks Fork Gas Processing Company (50%)**................... Wyoming*
Coastal Gas International Company..................................... Delaware
Coastal Gas International Ltd................................................. Cayman Islands
Coastal Gas Australia Proprietary Ltd................................. Australia
Coastal Gas International Ventures, Inc....................................... Delaware
Coastal Gas Marketing Company................................................. Delaware
Coastal Halcon Pipeline I Ltd................................................. Cayman Islands
Coastal Halcon Pipeline II Ltd................................................ Cayman Islands
Coastal Gas de Mexico S. de R. L. de C.V.............................. Mexico
Coastal Horsham Pipeline I Ltd................................................ Cayman Islands
Coastal Horsham Pipeline II Ltd............................................... Cayman Islands
Coastal Gas Pipelines Victoria, L.L.C................................. Delaware
Coastal Multi-Fuels, Inc...................................................... Delaware
Coastal Pan American Corporation.............................................. Delaware
Coastal Cape Horn Ltd................................................. Cayman Islands
Coastal Southern Pipeline Company............................................. Delaware
Coastal States Gas Transmission Company....................................... Delaware
Starr-Zapata Pipe Line (50%)**........................................ Texas*
Engage Energy US, L.P. (50%)**................................................ Delaware
Coastal Health Management Corporation (97%)........................................... Delaware
Coastal Holding Corporation........................................................... Delaware
CIC Industries, Inc........................................................... Delaware
Coastal Chem, Inc..................................................... Delaware
Coastal Crude Pipeline Corporation.................................... Delaware
Coastal Transportation Investors, L.P......................... Delaware*
Coastal Pipeline Company.............................................. Delaware
Coastal Refining & Marketing, Inc..................................... Delaware
Coastal Refined Products Corporation.......................... Delaware
Coastal States Crude Gathering Company........................ Texas
Coastal Crude Transportation Corporation.............. Delaware
Coastal Liquids Transportation L.P.................... Delaware*
Coastal Liquids Partners, L.P (35%) **........ Delaware*
Distribuidora Coastal, S.A. de C.V............................ El Salvador
Lube & Wax Ventures, L.L.C. (50%)............................. Delaware
Coastal Catalyst Technology, Inc.............................................. Delaware
Coastal Cat Process Marketing, Inc............................................ Delaware
BAR-Co Processes Joint Venture (50%)**................................ Texas*
Coastal Eagle Point Oil Company............................................... Delaware
</TABLE>
-1-
<PAGE>
SUBSIDIARIES OF THE COASTAL CORPORATION
<TABLE>
<CAPTION>
State or Other Jurisdiction of
Incorporation or Organization
------------------------------
<S> <C>
Coastal Energy Corporation.................................................... Delaware
Coastal Mobile Refining Company............................................... Delaware
Coastal Petrochemical International A.V.V..................................... Aruba
Coastal Petrochemical International (L) Limited....................... Labuan (Malaysia)
Coastal West Ventures, Inc.................................................... Delaware
Coastal Limited Ventures, Inc......................................................... Texas
Coastal Mart, Inc..................................................................... Delaware
Coastal Markets Ltd........................................................... Texas*
Coastal Mart Holdings, Inc.................................................... Delaware
TND Beverage Corporation...................................................... Texas
Coastal Midland, Inc.................................................................. Delaware
Coastal Natural Gas Company........................................................... Delaware
American Natural Resources Company............................................ Delaware
ANR Coal Company, LLC................................................. Delaware
ANR Credit Corporation................................................ Delaware
ANR Development Corporation........................................... Delaware
ANRFS Holdings, Inc................................................... Delaware
ANR Advance Holdings, Inc. (50%)**........................... Delaware
ANR Advance Transportation Company, Inc............... Delaware
Transport USA, Inc.................................... Pennsylvania
ANR Intrastate Gas Company, Inc....................................... Delaware
ANR One Woodward Corp................................................. Delaware
ANR Pipeline Company.................................................. Delaware
ANR Atlantic Pipeline Company................................. Delaware
ANR Energy Conversion Company................................. Michigan
ANR Field Services Company.................................... Delaware
ANR Iroquois, Inc............................................. Delaware
ANR New England Pipeline Company...................... Delaware
ANR Mayflower Company......................................... Delaware
ANR Southern Pipeline Company................................. Delaware
American Natural Offshore Company............................. Delaware
Texas Offshore Pipeline System, Inc................... Delaware
Unitex Offshore Transmission Company.................. Delaware
ANR Production Company................................................ Delaware
ANRPC Holdings, Inc........................................... Delaware
Coastal Shuttle Corporation................................... Delaware
ANR Ren-Cen, Inc...................................................... Connecticut
ANR Storage Company................................................... Michigan
ANR Blue Lake Company......................................... Delaware
Blue Lake Gas Storage Company (75%)**................. Michigan*
ANR Cold Springs Company...................................... Delaware
ANR Eaton Company............................................. Michigan
Eaton Rapids Gas Storage System (50%)**............... Michigan*
ANR Jackson Company........................................... Delaware
ANR Northeastern Gas Storage Company.......................... Delaware
Steuben Gas Storage Company (50%)**................... New York*
ANR Western Storage Company................................... Delaware
ANR Venture Eagle Point Company....................................... Delaware
Eagle Point Cogeneration Partnership (50%)**.................. New Jersey*
ANR Venture Fulton Company............................................ Delaware
Fulton Cogeneration Associates................................ New York*
ANR Venture Management Company........................................ Delaware
Capitol District Energy Center Cogeneration
Associates (50%)**.......................................... Connecticut*
</TABLE>
-2-
<PAGE>
SUBSIDIARIES OF THE COASTAL CORPORATION
<TABLE>
<CAPTION>
State or Other Jurisdiction of
Incorporation or Organization
----------------------------
<S> <C>
ANR Western Coal Development Company.................................. Delaware
Coastal Great Lakes, Inc.............................................. Delaware
Great Lakes Gas Transmission Limited Partnership (34%)**...... Delaware*
Empire State Pipeline Company, Inc.................................... New York
Mid Michigan Gas Storage Company...................................... Michigan
CIC Stock Corporation......................................................... Delaware
CIG Gas Storage Company............................................... Delaware
CIG Resources Company................................................. Delaware
CIG-Nitrotec Joint Venture (50%).............................. Colorado*
CIG Production Company, L.P................................... Delaware*
Johnstown Cogeneration Company, LLC (50%)**................... Colorado
Keyes Helium Company LLC (75%)................................ Colorado
Colorado Solar-Tech, Inc.............................................. Delaware
CIG-Canyon Compression Company................................................ Delaware
CIG Gas Supply Company........................................................ Delaware
Wyoming Interstate Company, Ltd....................................... Colorado*
CIG Overthrust, Inc........................................................... Delaware
Colorado Interstate Gas Company............................................... Delaware
CIG Exploration, Inc.................................................. Delaware
CIG Field Services Company............................................ Delaware
Great Divide Gas Services, LLC (73%)**........................ Colorado
Colorado Water Supply Company......................................... Delaware
Colorado Interstate Production Company........................ Delaware
Great Lakes Gas Transmission Company (50%)**.................................. Delaware
Wyoming Gas Supply, Inc....................................................... Delaware
Coastal Oil Chelsea, Inc.............................................................. Texas
Coastal Oil & Gas Corporation......................................................... Delaware
COGC Resale Company........................................................... Delaware
Coastal China Ltd............................................................. Cayman Islands
Coastal Colombia Ltd.......................................................... Cayman Islands
CoastalDril, Inc.............................................................. Delaware
Coastal Javelina, Inc......................................................... Delaware
Coastal Indonesia Bangko Ltd.................................................. Cayman Islands
Coastal Hungary Ltd........................................................... Hungary
Coastal Oil & Gas Holdings, Inc............................................... Delaware
Coastal Oil & Gas U.S.A., L.P................................................. Delaware*
Coastal Peru Ltd.............................................................. Cayman Islands
Coastal Power Company................................................................. Delaware
Coastal Bangchak Power Ltd.................................................... Cayman Islands
Coastal Clark Investor Ltd.................................................... Cayman Islands
Coastal Clark Manager Ltd..................................................... Cayman Islands
Coastal Manager Ltd. ...................................................... Cayman Islands
Coastal Nanjing Investor Ltd.................................................. Cayman Islands
Coastal Nanjing Power Ltd............................................. Cayman Islands
Nanjing Coastal Xingang Cogeneration Power Plant (80%)**...... Jiangsu Province, China
Coastal Nanjing Manager Ltd................................................... Cayman Islands
Coastal Peenya Investor Ltd................................................... Cayman Islands
Coastal Peenya Power Ltd.............................................. Mauritius
Coastal Peenya Manager Ltd.................................................... Cayman Islands
Coastal Power Guatemala Ltd................................................... Cayman Islands
Coastal Power International Ltd............................................... Cayman Islands
Coastal Power International II Ltd............................................ Cayman Islands
Quetta Power Holding Company I Ltd. (50%)**........................... Cayman Islands
Quetta Power Holding Company II Ltd........................... Cayman Islands
</TABLE>
-3-
<PAGE>
SUBSIDIARIES OF THE COASTAL CORPORATION
<TABLE>
<CAPTION>
State or Other Jurisdiction of
Incorporation or Organization
------------------------------
<S> <C>
Habibullah Coastal Power (Private) Company.................... Pakistan
Coastal Saba Investor Ltd..................................................... Cayman Islands
Coastal Saba Manager Ltd...................................................... Cayman Islands
Coastal Saba Investor II Ltd.......................................... Cayman Islands
Coastal Saba Power Ltd........................................ Mauritius
Coastal Saba Power Company (Private) Limited.......... Pakistan
Coastal Saba Manager II Ltd........................................... Cayman Islands
Coastal Salvadoran Power Ltd.................................................. Cayman Islands
Coastal Nejapa Ltd. (90%)............................................. Cayman Islands
Coastal Suzhou Investor Ltd................................................... Cayman Islands
Coastal Suzhou Manager Ltd.................................................... Cayman Islands
Coastal Gusu Heat & Power Ltd......................................... Cayman Islands
Coastal Suzhou Power Ltd.............................................. Cayman Islands
Suzhou New District Cogeneration Company (60%)**.............. Jiangsu Province, China
Coastal Wuxi Investor Ltd..................................................... Cayman Islands
Coastal Wuxi New District Ltd......................................... Cayman Islands
Wuxi Shunda Gas Turbine Company (60%)**....................... China
Coastal Wuxi Manager Ltd...................................................... Cayman Islands
Coastal Wuxi Power Ltd................................................ Cayman Islands
Wuxi Huada Gas Turbine Electric Power Company (60%)**......... Jiangsu Province, China
Coastal States Management Corporation................................................. Colorado
ABCO Aviation, Inc............................................................ Delaware
ABCO Leasing, Inc............................................................. Delaware
ANR Media Company............................................................. Michigan
Coastal Travel Mart, Inc...................................................... Delaware
Coastal States Trading, Inc........................................................... Delaware
Coastal Technology, Inc............................................................... Delaware
Coastal Technology Dominicana S.A............................................. Dominican Republic
Coastal Technology Ltd........................................................ Cayman Islands
Coastal Technology Pakistan (Private) Limited................................. Pakistan
Coastal Technology Salvador, S.A. de C.V...................................... El Salvador
Coastal Unilube, Inc. ............................................................. Tennessee
Coastal Unilube of Iowa L.C........................................................... Iowa
Cosbel Petroleum Corporation.......................................................... Delaware
Coastal Canada Petroleum, Inc................................................. New Brunswick, Canada
Coastal Fuels Marketing, Inc.................................................. Florida
Coastal Fuels of Puerto Rico, Inc..................................... Delaware
Coastal Offshore Fuels, Inc........................................... Liberia
Coastal Terminals, Inc................................................ Florida
Coastal Tug and Barge, Inc............................................ Florida
Manatee Towing Company....................................... Florida
Coastal Oil New England, Inc.................................................. Massachusetts
Coastal Oil New York, Inc..................................................... Delaware
Engage Energy Canada, L.P. (50%)**............................................ Canada
Coscol Petroleum Corporation.......................................................... Delaware
Coastal CFC Ltd............................................................... Cayman Islands
Coastal Baltica Holding Company Ltd. (50%)**.......................... Cayman Islands
EOS Limited.................................................. Estonia
Coastal Baltica Marketing Company Ltd. (50%)**........................ Cayman Islands
Coastal Coker Corporation Aruba N.V........................................... Aruba
Coastal Securities Company Limited............................................ Bermuda
Coastal Aruba Holding Company N.V..................................... Aruba
Coastal Aruba Fuels Company N.V.............................. Aruba
Coastal Aruba Maintenance/Operations Company N.V............. Aruba
</TABLE>
-4-
<PAGE>
SUBSIDIARIES OF THE COASTAL CORPORATION
<TABLE>
<CAPTION>
State or Other Jurisdiction of
Incorporation or Organization
------------------------------
<S> <C>
Coastal Aruba Refining Company N.V........................... Aruba
Coastal Petroleum Overseas N.V........................ Aruba
Coastal Energy of Panama, Inc......................... Panama
Coastal Petroleum N.V................................. Aruba
Coastal Petroleum Argentina, S.A.............. Argentina
Coastal Petroleum N.V. Chile
Limitada (99%)........................... Chile*
Subic Bay Distribution, Inc. (99%).................... Philippines
Coastal Belcher Petroleum Pte. Ltd.................................... Singapore
Coastal (Bermuda) Petroleum Limited................................... Bermuda
Same as Coastal Stock Company Limited
Coastal Cayman Finance Ltd.................................... Cayman Islands
Coastal Management Services (Singapore) Pte. Ltd...................... Singapore
Coastal Petroleum (Far East) Pte Ltd.................................. Singapore
Coastal (Rotterdam) B.V............................................... The Netherlands
Coastal (Subic Bay) Petroleum, Inc............................................ Texas
Coastal Subic Bay Terminal, Inc....................................... Philippines
Coastal Stock Company Limited................................................. Bermuda
Coastal Europe Limited................................................ England
Coastal States Petroleum (U.K.) Limited....................... England
Coastal States Tankers (U.K.) Limited......................... England
Colbourne Insurance Company Limited........................... England
Coastal Tankships U.S.A., Inc................................................. Delaware
Coscol Marine Corporation..................................................... Texas
Coastal Mart of Oklahoma, Inc......................................... Oklahoma
Coastal Interstate Corporation................................ Delaware
Golden Carriers Corporation................................................... Liberia
Holborn Oil Trading Limited................................................... Bermuda
Jade Carriers Corporation..................................................... Liberia
Texas Tank Ship Agency, Inc................................................... Delaware
<FN>
The above subsidiaries, with the exception of those indicated with a double
asterisk (**) are included in the Consolidated Financial Statements of The
Coastal Corporation. Great Lakes Gas Transmission Company has a 32.14% limited
partnership interest in Great Lakes Gas Transmission Limited Partnership. The
names of certain subsidiaries have been omitted from the above listing because
such subsidiaries, considered in the aggregate as a single subsidiary, would not
constitute a significant subsidiary. The voting stock of each corporation is
owned 100% by its immediate parent or by its immediate parent together with an
affiliate of such parent, unless otherwise indicated above.
* Partnership
** Not consolidated
</FN>
</TABLE>
-5-
Exhibit 23
CONSENT OF DELOITTE & TOUCHE LLP
We consent to the incorporation by reference in Registration Statements No.
33-21095, 33-40263, 33-53952, 33-5214, 2-97766, 33-5218 and 33-42696 of The
Coastal Corporation on Forms S-8 and Registration Statements No. 33-48435 and
333-10995 of The Coastal Corporation on Forms S-3 of our report dated January
31, 1997, appearing in this Annual Report on Form 10-K of The Coastal
Corporation for the year ended December 31, 1996.
DELOITTE & TOUCHE LLP
Houston, Texas
March 25, 1997
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND> THE SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION
EXTRACTED FROM THE COASTAL CORPORATION FORM 10-K ANNUAL
REPORT FOR THE PERIOD ENDED DECEMBER 31, 1996 AND IS
QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH
FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> DEC-31-1996
<CASH> 106
<SECURITIES> 0
<RECEIVABLES> 1,801
<ALLOWANCES> 0
<INVENTORY> 1,144
<CURRENT-ASSETS> 3,196
<PP&E> 9,962
<DEPRECIATION> 3,307
<TOTAL-ASSETS> 11,613
<CURRENT-LIABILITIES> 2,947
<BONDS> 3,526
0
3
<COMMON> 37
<OTHER-SE> 2,997
<TOTAL-LIABILITY-AND-EQUITY> 11,613
<SALES> 12,167
<TOTAL-REVENUES> 12,252
<CGS> 8,980
<TOTAL-COSTS> 11,156
<OTHER-EXPENSES> 65
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 368
<INCOME-PRETAX> 663
<INCOME-TAX> 163
<INCOME-CONTINUING> 500
<DISCONTINUED> 0
<EXTRAORDINARY> (97)
<CHANGES> 0
<NET-INCOME> 403
<EPS-PRIMARY> 3.62
<EPS-DILUTED> 3.60
</TABLE>
