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                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                                    FORM 10-K
(Mark One)

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
      SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]

For the fiscal year ended December 31, 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.

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<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.