================================================================================

                       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 1-4874


                         COLORADO INTERSTATE GAS COMPANY
             (Exact name of registrant as specified in its charter)


           Delaware                                            84-0173305
(State or other jurisdiction of                              I.R.S. Employer
 incorporation or organization)                            Identification No.)

         Two North Nevada Avenue
       Colorado Springs, Colorado                               80903-1727
(Address of principal executive offices)                        (Zip Code)


       Registrant's telephone number, including area code: (719) 473-2300

                           ---------------------------


Securities registered pursuant to Section 12(b) of the Act:

                                                      Name of each exchange
      Title of each class                              on which registered
      -------------------                            -----------------------

10% Senior Debentures, due 2005                       New York Stock Exchange

                           ---------------------------



     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 10 shares of common stock of
the Registrant,  $5.00 par value per share, its only class of common stock. None
of the voting stock of the Registrant is held by non-affiliates.

Documents incorporated by reference:  None



<PAGE>

                                TABLE OF CONTENTS

Item No.                                                                  Page

            Glossary......................................................(ii)

                                   PART I

     1.     Business......................................................   1
                Introduction..............................................   1
                Natural Gas System........................................   1
                    Operations............................................   1
                        General...........................................   1
                        Gas Sales, Storage and Transportation.............   2
                        Gas Gathering and Processing......................   2
                        Competition.......................................   3
                    Gas System Reserves...................................   3
                        General...........................................   3
                        Reserves..........................................   3
                        Reserves Dedicated to a Particular Customer.......   3
                    Regulations Affecting Gas System......................   4
                        General...........................................   4
                        Rate Matters......................................   4
                Gas and Oil Exploration and Production....................   5
                Environmental.............................................   7
     2.     Properties....................................................   7
     3.     Legal Proceedings.............................................   7
     4.     Submission of Matters to a Vote of Security Holders...........   8

                                   PART II

     5.     Market for the Registrant's Common Equity and Related
            Stockholder Matters...........................................   9
     6.     Selected Financial Data.......................................   9
     7.     Management's Discussion and Analysis of Financial
            Condition and Results of Operations...........................   9
     8.     Financial Statements and Supplementary Data...................   9
     9.     Changes in and Disagreements with Accountants on Accounting
            and Financial Disclosure......................................   9

                                  PART III

     10.    Directors and Executive Officers of the Registrant............  10
     11.    Executive Compensation........................................  11
     12.    Security Ownership of Certain Beneficial Owners and
            Management....................................................  19
     13.    Certain Relationships and Related Transactions................  22

                                   PART IV

     14.    Exhibits, Financial Statement Schedules, and Reports on
            Form 8-K......................................................  23



                                       (i)

<PAGE>

                                    GLOSSARY


"AICPA" means American Institute of Certified Public Accountants
"ANR" means American Natural Resources Company
"ANR Pipeline" means ANR Pipeline Company
"Bcf" means billion cubic feet
"CIGFS" means CIG Field Services Company
"Coastal" means The Coastal Corporation
"Coastal Natural Gas" means Coastal Natural Gas Company
"Colorado" or the "Company" means Colorado Interstate Gas Company
       and/or its subsidiaries
"FAS" means Statement of Financial Accounting Standards
"FASB" means Financial Accounting Standards Board
"FERC" means Federal Energy Regulatory Commission
"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
"NGL" means natural gas liquids
"Order 636" means FERC Order No. 636 which required significant changes in
       services provided by interstate natural gas pipelines, including the
       unbundling of services
"WIC" means Wyoming Interstate Company, Ltd.
"Working gas" means that volume of gas available for withdrawal and use by the
       Company's customers




NOTE:  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

     Colorado is a Delaware  corporation  organized in 1927.  All of  Colorado's
outstanding   common  stock  is  owned  by  Coastal  Natural  Gas,  which  is  a
wholly-owned  subsidiary  of Coastal.  Colorado  owns and operates an interstate
natural gas pipeline  system and also has gas and oil exploration and production
operations. At December 31, 1996, the Company had 979 employees.

     The revenues and  operating  profit of the Company by industry  segment for
each of the three years in the period ended  December 31, 1996,  and the related
identifiable  assets as of December  31, 1996,  1995 and 1994,  are set forth in
Note 12 of Notes to Consolidated Financial Statements included herein.



                               NATURAL GAS SYSTEM


OPERATIONS

General

     The  Company  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 purchases and produces natural gas and makes sales of such
gas at the wellhead principally to local gas distribution companies for resale.

     Public  Service  Company  of  Colorado  was  the  Company's  only  customer
accounting   for  revenue  that  equaled  or  exceeded  10%  of  the   Company's
consolidated revenues for the years 1996, 1995 and 1994 (See Note 12 of Notes to
Consolidated Financial Statements.)

     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. The Company's gas gathering
and processing  facilities are located  throughout the production areas adjacent
to its transmission  system. Most of the Company's gathering  facilities connect
directly to its transmission system, but some gathering systems are connected to
other pipelines.  The Company also has minor gathering facilities located in New
Mexico.  Colorado owns four  underground  gas storage  fields;  three located in
Colorado, and one in Kansas.

     The  Company's  principal  transmission  and storage  pipeline  facilities,
including  certain  facilities  in the  Panhandle  Field  of  Texas  ("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
facilities 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.



                                        1

<PAGE>

     On June 26, 1996,  the FERC  approved  Colorado's  request for authority to
transfer to its subsidiary, CIGFS, 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 CIGFS 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 CIGFS effective October 1, 1996.

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 the  Company'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, the Company
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,  the Company 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. The Company'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 the  Company is limited to charging  rates  between
minimum and maximum levels approved by the FERC. The gathering (and  processing)
that  Colorado's  subsidiary,  CIGFS,  provides  is not  regulated  by the FERC.
However, under the terms by which the Company obtained FERC approval to transfer
these facilities to CIGFS,  CIGFS offered  "default  contracts" to all gathering
customers  receiving  service at the date of the  transfer.  Under the  "default
contracts,"  CIGFS 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.

     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.

     The  Company  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 Company affiliates. The Company also operates two gas processing plants
for affiliates.


                                        2

<PAGE>

Competition

     Colorado has 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 its  service  areas.  On  October  1, 1993,  the  Company
implemented  Order  636 on its  system  and,  as a  consequence,  its gas  sales
contracts  have  been  "unbundled"  at the  producer  wellhead.  Order  636 also
mandated implementation of capacity release and secondary delivery point options
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 Colorado.


GAS SYSTEM RESERVES

General

     Colorado, primarily through its unincorporated Merchant Division, continues
to make natural gas sales to a number of customers. Colorado will meet its sales
commitments primarily with purchases from third parties under existing contracts
and with production of Company-owned reserves.  Colorado will also make spot gas
purchases, if needed.

Reserves

     The table below  represents  estimates of the Company's owned or controlled
reserves as of December 31, 1996,  1995,  and 1994,  as prepared by  Huddleston,
Colorado's independent engineers.

<TABLE>
<CAPTION>
                                                                                  1996          1995         1994
                                                                                  ----          ----         ----

      <S>                                                                          <C>           <C>          <C>
      Owned or controlled by Colorado (Bcf)....................................    307           346          383
</TABLE>

     The  estimates  of owned or  controlled  gas  reserves  include  quantities
economically  recoverable  over  the  productive  life  of  existing  wells  and
quantities estimated to be recoverable in the future, either from completions in
other  productive zones of existing wells or from additional wells to be drilled
in  proven  reservoirs  currently   controlled  by  Colorado.   The  independent
engineers' estimates of reserves are based upon new analyses or upon a review of
earlier  analyses  updated by  production  and field  performance.  The  reserve
volumes reported  represent those retained by Colorado as well as those assigned
to a subsidiary.

     At December 31, 1996,  Colorado maintained under its own account 2.7 Bcf of
natural gas in underground working storage for system balancing. The Company has
an  additional  37.8 Bcf of base gas in its four  owned  storage  fields.  These
amounts reflect actual balances at December 31, 1996, and vary slightly from the
Huddleston report which includes estimates for November and December 1996.

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.




                                        3

<PAGE>

REGULATIONS AFFECTING GAS SYSTEM

General

     Under the NGA,  the FERC has  jurisdiction  over  Colorado  as to rates and
charges for the  transportation  and storage of natural gas and the 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 sales rates.  Additionally,  the FERC has asserted rate-regulation (but
not  certificate  regulation)  over  gathering  services  provided by interstate
pipeline companies such as Colorado.

     Colorado is also subject to regulation with respect to safety  requirements
in the design,  construction,  operation and  maintenance  of its interstate gas
transmission  and  storage  facilities  by  the  Department  of  Transportation.
Additionally,  the Company is 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.

Rate Matters

     On January 31, 1996, the FERC issued a "Statement of Policy and Request for
Comments" ("Policy Statement") 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  Statement,  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 Statement, a pipeline must make an initial tariff filing with the FERC to
indicate that it intends to contract for services  under this Policy  Statement,
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.

     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 Statement.  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,  CIGFS 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 CIGFS 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 CIGFS effective October 1, 1996.

     Certain of the above regulatory  matters and other regulatory issues remain
unresolved  among the Company,  its  customers,  its suppliers and the FERC. The
Company has made provisions which represent management's assessment


                                        4

<PAGE>

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.



                     GAS AND OIL EXPLORATION AND PRODUCTION

      The Company has domestic  gas and oil  production  operations.  The gas is
delivered primarily to Colorado's interstate gas pipeline system while the crude
oil and  condensate  are sold at the  wellhead to oil  purchasing  companies  at
prevailing market prices. The production of gas and oil is subject to regulation
in states in which the Company operates.

     The  following  table shows gas,  oil,  condensate  and natural gas liquids
production  volumes of the Company,  including  quantities  attributable  to its
natural gas system, for the three years ended December 31, 1996:

<TABLE>
<CAPTION>
                                                                                   1996         1995         1994
                                                                                   ----         ----         ----

      <S>                                                                         <C>          <C>          <C>   
      Exploration and Production
           Gas (MMcf)......................................................       12,304       10,703       14,758
           Oil (000 barrels)...............................................            2            5            8
           Condensate (000 barrels)........................................           61           60           73
           Natural Gas Liquids (000 barrels)...............................           51            2            -

      Natural Gas System
           Gas (MMcf)......................................................       39,405       41,638       46,288
           Oil (000 barrels)...............................................           23           15            -
           Condensate (000 barrels)........................................            -            1            1
           Natural Gas Liquids (000 barrels)...............................            -            -            -
</TABLE>

     The following table summarizes sales price and unit cost information of the
Company's  exploration  and  production  operations  for the three  years  ended
December 31, 1996:

<TABLE>
<CAPTION>
                                                                                   1996         1995         1994
                                                                                   ----         ----         ----

      <S>                                                                        <C>          <C>         <C>     
      Average sales price:
           Gas - per Mcf...................................................      $  1.51      $  1.08     $   1.52
           Oil - per barrel................................................        19.91        16.47        14.80
           Condensate - per barrel.........................................        21.39        17.34        16.04
           Natural Gas Liquids - per barrel................................         8.19        10.22            -

      Average production cost per unit (equivalent Mcf)....................      $  0.35      $  0.45     $   0.37
</TABLE>



                                        5

<PAGE>

     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
      --------------------------------------------------------  -----------  -----------  -----------   -----------

      <S>                                                           <C>          <C>         <C>           <C>
      Exploration and Production..............................       65,734       16,791      103,880        48,149
      Natural Gas System......................................            -            -      264,712       261,363
                                                                -----------  -----------  -----------   -----------
                                                                     65,734       16,791      368,592       309,512
                                                                ===========  ===========  ===========   ===========
</TABLE>

     The net  developed  acreage is  concentrated  principally  in Texas  (79%),
Oklahoma  (7%),  Wyoming  (6%) and Utah  (6%).  The net  undeveloped  acreage is
principally in Wyoming (49%), Montana (24%), Utah (11%) and Texas (10%).

     Information on wells drilled in the three years ended December 31, 1996, is
summarized as follows:

<TABLE>
<CAPTION>
                                                1996                      1995                       1994
                                      ------------------------  ------------------------  -------------------------
                                         Gross         Net          Gross         Net         Gross         Net
                                      -----------  -----------  -----------  -----------  -----------   -----------

      <S>                             <C>          <C>          <C>          <C>          <C>           <C>        
      Exploration and Production
      --------------------------

      Development Wells
      -----------------
         Oil........................            -            -            -            -            -             -
         Gas........................            5         1.86            7         2.44           19          7.68
         Dry Holes..................            -            -            -            -            -             -
                                      -----------  -----------  -----------  -----------  -----------   -----------
                                                5         1.86            7         2.44           19          7.68
                                      -----------  -----------  -----------  -----------  -----------   -----------

      Natural Gas System
      ------------------

      Development Wells
      -----------------
         Oil........................            2         2.00            -            -            -             -
         Gas........................            8         8.00            1         1.00            3          3.00
         Dry Holes..................            -            -            -            -            -             -
                                      -----------  -----------  -----------  -----------  -----------   -----------
                                               10        10.00            1         1.00            3          3.00
                                      -----------  -----------  -----------  -----------  -----------   -----------

             Total..................           15        11.86            8         3.44           22         10.68
                                      ===========  ===========  ===========  ===========  ===========   ===========
</TABLE>

      Productive wells as of December 31, 1996 are as follows:
<TABLE>
<CAPTION>

                                         Type of Well                                         Gross         Net
      ----------------------------------------------------------------------------------  -----------   -----------

      <S>                                                                                 <C>           <C>        
      Exploration and Production
           Oil..........................................................................            1          0.09
           Gas..........................................................................          329        201.42
                                                                                          -----------   -----------
                  Total Exploration and Production......................................          330        201.51
                                                                                          -----------   -----------

      Natural Gas System
           Oil..........................................................................            9          8.25
           Gas..........................................................................          675        670.86
                                                                                          -----------   -----------
                  Total Natural Gas System..............................................          684        679.11
                                                                                          -----------   -----------

                              Total.....................................................        1,014        880.62
                                                                                          ===========   ===========
</TABLE>

     Information  on  Company-owned  reserves of oil and gas is included  herein
under "Supplemental Information on Oil and Gas Producing Activities (Unaudited)"
in Item 14(a)1 included herein.



                                        6

<PAGE>

     The Company  competes with major  integrated oil companies and  independent
oil  and  gas  companies  for  suitable  prospects  for  oil  and  gas  drilling
operations.  The  availability of a ready market for gas discovered and produced
depends on numerous  factors  frequently  beyond the  Company's  control.  These
factors  include the extent of gas discovery and production by other  producers,
crude oil  imports,  the  marketing of  competitive  fuels,  and the  proximity,
availability  and  capacity  of gas  pipelines  and  other  facilities  for  the
transportation  and marketing of gas. The  production and sale of oil and gas is
subject to a variety of federal and state regulations,  including  regulation of
production levels.



                                  ENVIRONMENTAL

     The Company's  operations  are subject to extensive  and evolving  federal,
state  and local  environmental  laws and  regulations  which  may  affect  such
operations and costs as a result of their effect on the construction, operation,
and maintenance of its pipeline facilities. The Company spent approximately $1.2
million  on  environmental  capital  projects  in 1996  and  anticipates  annual
environmental  capital  expenditures  of $1 to $2 million  over the next several
years  aimed  at  maintaining   compliance  with  such  laws  and   regulations.
Additionally,  appropriate  governmental  authorities  may  enforce the laws and
regulations with a variety of civil and criminal enforcement measures, including
monetary penalties and remediation requirements.

     The Comprehensive  Environmental Response,  Compensation and Liability Act,
also known as "Superfund", as reauthorized, imposes liability, without regard to
fault  or the  legality  of the  original  act,  for  disposal  of a  "hazardous
substance."  The  Company  is not  presently,  and has not been in the  past,  a
potentially  responsible  party ("PRP") in any "Superfund" waste disposal sites.
However, the Company has received notice from a committee formed from a group of
55 companies who are named as PRPs at one site  requesting  the Company pay a de
minimis share (approximately $36,000) of the associated clean-up costs.

     Future information and developments will require the Company to continually
reassess  the  expected  impact  of  all  applicable   environmental   laws  and
regulations.  Compliance with all applicable  environmental  protection laws and
regulations  is not expected to have a material  adverse impact on the Company's
liquidity, consolidated financial position or results of operations.

Item 2. Properties.

     Information  on properties  of Colorado is included in Item 1,  "Business,"
included herein.

     The real property owned by the Company in fee consists principally of sites
for compressor and metering stations and microwave and terminal facilities. With
respect to the four 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 may acquire by the  exercise of the right of eminent
domain,  through  proceedings  in  U.S.  District  Courts  or in  state  courts,
necessary  rights-of-way  to  construct,  operate  and  maintain  pipelines  and
necessary land or other property for compressor and other stations and equipment
necessary to the operation of pipelines.

Item 3. Legal Proceedings.

     In December  1992,  certain of  Colorado's  natural gas lessors in the West
Panhandle  Field filed a complaint in the U.S.  District  Court 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


                                        7

<PAGE>

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 lawsuit 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  Colorado,  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.  Colorado, together with the other pipeline defendants, has
filed a motion to dismiss.

     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.



                                        8

<PAGE>

                                     PART II


Item 5. Market for the Registrant's Common Equity and
        Related Stockholder Matters.

     All common  stock of Colorado is owned by Coastal  Natural Gas. At December
31, 1996,  $269.3  million of retained  earnings was  available for dividends on
common stock.  Additional  information  relating to dividends is set forth under
the "Statement of Consolidated Retained Earnings and Additional Paid-In Capital"
included herein.

     All of the remaining  outstanding  shares of preferred  stock at January 1,
1996 were redeemed on July 31, 1996 at par value.

Item 6. Selected Financial Data.

     The following  selected financial data (in thousands of dollars) is derived
from the  Consolidated  Financial  Statements  included herein and Item 6 of the
Company's  Annual  Report on Form 10-K for the year ended  December 31, 1995, as
adjusted  for  minor  reclassifications.  The  Notes to  Consolidated  Financial
Statements included herein contain information relating to this data.

<TABLE>
<CAPTION>
                                                                      Year Ended December 31,
                                                -----------------------------------------------------------------
                                                    1996*        1995          1994         1993          1992
                                                -----------   -----------  -----------   -----------   ----------

<S>                                             <C>           <C>          <C>           <C>           <C>       
Operating revenues...........................   $   412,477   $   382,200  $   386,553   $   438,890   $  402,998
Earnings before extraordinary item...........        82,058        87,716       78,507        73,178       84,075
Total assets.................................       908,922       861,448      962,111       901,627    1,097,178
Long-term debt, excluding current maturities.       229,373       179,299      179,225       179,145      195,278
Mandatory redemption preferred stock.........             -           556          556           556          556
Common stock and other stockholder's equity..       416,652       459,808       411,423       358,047     525,400

<FN>
----------------------

*     Effective  November 1, 1996, the Company  discontinued  the application of
      FAS 71. Additional information is set forth in Management's Discussion and
      Analysis of Financial  Condition and Results of Operations  and Note 10 of
      Notes to Consolidated Financial Statements included herein.
</FN>
</TABLE>

     All of the outstanding common stock of Colorado is owned by Coastal Natural
Gas;   therefore,   earnings  and  cash  dividends  per  common  share  have  no
significance and are not presented.

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-5 herein.

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) herein.

Item 9. Changes in and Disagreements with Accountants on Accounting and
        Financial Disclosure.

     None.



                                        9

<PAGE>

                                    PART III


Item 10. Directors and Executive Officers of the Registrant.

     The directors and executive officers of Colorado as of March 12, 1997, were
as follows:

   Name (Age), Year First Elected              Positions and Offices
       Director and/or Officer                  with the Registrant
----------------------------------    ---------------------------------------

Jon R. Whitney (52), 1987 and 1974    President, Chief Executive Officer and
                                        Director
Jeffrey A. Connelly (50), 1996        Director
David A. Arledge (52), 1981           Director
Harold Burrow (82), 1974              Director
C. Scott Hobbs (43), 1985             Executive Vice President, Chief Operating
                                        Officer and Director
Coby C. Hesse (49), 1986              Executive Vice President
Daniel F. Collins (55), 1986          Senior Vice President
Donald H. Gullquist (53),1994         Senior Vice President
Rebecca H. Noecker (45), 1988         Senior Vice President and General Counsel
Austin M. O'Toole (61), 1984          Senior Vice President and Secretary
Richard G. Smead (50), 1988           Senior Vice President
Donald J. Zinko (52), 1988            Senior Vice President
Steven J. Coffin (41), 1990           Vice President
Ronald A. Gillet (55), 1993           Vice President
Thomas E. Jackson, Jr. (57), 1989     Vice President
Ronald D. Matthews (49), 1994         Vice President and Treasurer
Robert O. Reid (50), 1985             Vice President
William H. Sparger (54), 1992         Vice President
Dan A. Homec (48), 1989               Assistant Vice President and Controller

     The above named persons bear no family  relationship  to each other.  Their
respective terms of office expire  coincident with Colorado's  Annual Meeting of
the Sole  Stockholder and Annual Meeting of the Board of Directors to be held in
May 1997.  Each of the directors or officers  named above have been directors or
officers of Colorado,  ANR Pipeline and/or Coastal for five years or more except
for the following:

     Mr.  Gullquist  was elected  Senior Vice  President  of Colorado in October
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. Sparger was elected a Vice  President of Colorado in June 1992.  Before
joining the Company, he served in various capacities with  Transcontinental  Gas
Pipe Line Corporation since 1967.



                                       10

<PAGE>

Item 11. Executive Compensation.

     Colorado is an indirectly,  wholly-owned subsidiary of Coastal. Information
concerning the cash compensation and certain other compensation of directors and
officers of Coastal is contained in this section.

     The  following  table sets forth  information  for the fiscal  years  ended
December 31, 1996, 1995 and 1994 as to cash compensation paid by Coastal and its
subsidiaries,  as well as certain other  compensation  paid or accrued for those
years,  to Coastal's  Chief  Executive  Officer  ("CEO") and its four other most
highly compensated executive officers (the "Named Executive Officers").

                           Summary Compensation Table

<TABLE>
<CAPTION>
                                                                             Long Term Compensation
                                                                         -------------------------------
                                     Annual Compensation<F1>                 Awards           Payouts
                             ----------------------------------          -------------     -------------
                                                                          Securities                          All Other
                                                                          Underlying          LTIP             Compen-
Name and                                                                   Options/          Payouts           sation
Principal Position           Year       Salary ($)    Bonus ($)<F2>        SARs (#)<F3>      ($)<F4>            $<F5>
------------------           ----       ----------    ---------          -------------     -------------    ---------

<S>                          <C>          <C>             <C>                    <C>                            <C>   
O. S. Wyatt, Jr.,            1996         849,093         300,000               -0-                             67,928
Chairman of the Board        1995         849,093         300,000               -0-                             67,928
                             1994         849,093         200,000               -0-                             67,928

David A. Arledge,            1996         707,194         300,000           150,000                             56,576
President, CEO               1995         622,867         300,000            50,000          85,875             49,829
and Director                 1994         553,873         150,000               -0-                             44,310

James F. Cordes,<F6>         1996         592,223             -0-               -0-                             12,000
Executive V.P.               1995         592,223         135,000            15,000          42,937             47,378
and Director                 1994         592,223         130,000               -0-                             47,378

James A. King,               1996         343,823          80,000            10,000                             13,572
Executive V.P.               1995         343,823          80,000            10,000                             10,141
                             1994         343,823          75,000               -0-                              6,877

Jerry D. Bullock,            1996         249,147         160,000            10,000                              6,383
Senior V.P.                  1995         249,147          75,000            10,000                              6,766
                             1994         249,147          65,000               -0-                              3,383

<FN>
------------------------

<F1> Does not  include  the value of  perquisites  and other  personal  benefits
     because the aggregate amount of such compensation,  if any, does not exceed
     the lesser of  $50,000  or 10  percent  of annual  salary and bonus for any
     named individual.

<F2> Bonuses are based on the following factors: the individual's  position; the
     individual's  responsibility;   and  the  individual's  ability  to  impact
     Coastal's financial success.

<F3> The options do not carry any stock appreciation rights.

<F4> During 1995, Messrs.  Arledge and Cordes received one-time cash payments in
     the  amounts  indicated  in  connection  with  awards  made in  1987  under
     Coastal's  Performance  Unit Plan.  No further  awards have been made under
     this Plan.



                                       11

<PAGE>

<F5> All Other  Compensation for 1996 consists of: (i) Coastal  contributions to
     the  Coastal  Thrift  Plan (O. S.  Wyatt,  Jr.  $12,000;  David A.  Arledge
     $12,000;  James F.  Cordes  $12,000;  James A.  King  $6,000;  and Jerry D.
     Bullock  $6,000);  and  (ii)  certain  payments  in  lieu  of  Thrift  Plan
     contributions (O. S. Wyatt, Jr. $55,927; David A. Arledge $44,576; James F.
     Cordes  $-0-;  James A. King  $7,572;  and Jerry D.  Bullock  $383);  these
     payments  are made to all  employees  of Coastal and its  subsidiaries  who
     participate  in the Thrift  Plan who must  discontinue  their  Thrift  Plan
     participation due to federal statutory limits.

<F6> Mr. Cordes retired as an officer of Coastal effective March 7, 1997.
</FN>
</TABLE>

Stock Options

     The following  table sets forth  information  with respect to stock options
granted on March 1, 1996 for the  fiscal  year ended  December  31,  1996 to the
Named Executive Officers.

                  Option/SAR Grants in Last Fiscal Year (1996)

<TABLE>
<CAPTION>
                                Number of       Percent of Total
                               Securities         Options/SARs
                               Underlying          Granted to          Exercise                      Grant Date
                              Options/SARs        Employees in           Price       Expiration        Present
           Name                 Granted<F1>      Fiscal Year<F2>        ($/Sh)          Date        Value ($)<F3>
           ----             ----------------- ---------------------   ----------   --------------  --------------

<S>                              <C>                    <C>             <C>             <C>           <C>      
O. S. Wyatt, Jr.                    -0-                  -0-              -0-              -0-              -0-

David A. Arledge                 150,000                22.6            36.56           2/28/06       1,848,108

James F. Cordes                     -0-                  -0-              -0-              -0-              -0-

James A. King                     10,000                 1.5            36.56           2/28/06         123,207

Jerry D. Bullock                  10,000                 1.5            36.56           2/28/06         123,207

<FN>
---------------------

<F1> Options  expire ten years from the date of issuance  and are granted at the
     fair  market  value of the  Common  Stock of  Coastal 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.

<F2> The options do not carry any stock appreciation rights.

<F3> Based on the Black-Scholes option pricing model expressed as a ratio .337 x
     exercise price x number of shares.  The actual value,  if any, an executive
     may realize  will depend on the excess of the stock price over the exercise
     price on the date the option is  exercised,  so that there is no  assurance
     the value realized by an executive  will be at or near the value  estimated
     by the Black-Scholes model. The estimated values under that model are based
     on  assumptions  that  include  (i) a  stock  price  volatility  of  .1925,
     calculated  using  monthly  stock  prices for the three  years prior to the
     grant date, (ii) an interest rate of 6.25%, (iii) a dividend yield of 1.40%
     and (iv) an expected  option holding period of eight years.  No adjustments
     were made for the non-transferability of the options or to reflect any risk
     of forfeiture  prior to vesting.  The  Securities  and Exchange  Commission
     ("S.E.C.") requires disclosure of the potential realizable value or present
     value of each grant.  Coastal's use of the Black-Scholes  model to indicate
     the present value of each grant is not an endorsement of this valuation.
</FN>
</TABLE>

                                                       12

<PAGE>

Option/SAR Exercises and Holdings

     The  following  table  sets  forth  information  with  respect to the Named
Executive  Officers,  concerning  the exercise of options during the last fiscal
year and  unexercised  options and SARs held as of the fiscal year ("FY")  ended
December 31, 1996.

               Aggregated Option/SAR Exercises In Last Fiscal Year
                       And FY-End Option/SAR Values (1996)

<TABLE>
<CAPTION>
                                                                           Number of
                                                                          Securities              Value of
                                                                          Underlying             Unexercised
                                                                          Unexercised           In-the-Money
                                                                         Options/SARs           Options/SARs
                                                                         at FY-End (#)        at FY-End ($)<F1>

                           Shares Acquired                               Exercisable/           Exercisable/
        Name               on Exercise (#)      Value Realized ($)       Unexercisable          Unexercisable
--------------------    -------------------    --------------------    ----------------    -----------------------
<S>                             <C>                     <C>             <C>        <C>         <C>           <C>
O. S. Wyatt, Jr.                 -0-                   -0-              -0-    /   -0-        -0-     /     -0-
David A. Arledge               55,000               1,118,737         187,373  / 228,000   3,943,307  /  3,595,560
James F. Cordes                30,000                 234,914           -0-    /  35,000      -0-     /    754,500
James A. King                  -0-                     -0-             26,000  /  24,000     599,800  /    432,200
Jerry D. Bullock                6,000                  69,920           2,000  /  27,000      41,760  /    491,860
<FN>
------------------
<F1>  $-based on the market  price of $49.44 at December 31, 1996.
</FN>
</TABLE>

                COMPENSATION AND EXECUTIVE DEVELOPMENT COMMITTEE
                        REPORT ON EXECUTIVE COMPENSATION

     The  following  report  has  been  provided  by The  Coastal  Corporation's
Compensation and Executive  Development Committee (the "Committee") of the Board
of Directors  in  accordance  with current  S.E.C.  proxy  statement  disclosure
requirements.  The members of the Committee include John M. Bissell  (Chairman),
Roy D. Chapin, Jr., and Jerome S. Katzin.

     This material states Coastal's current overall compensation  philosophy and
program objectives. Detailed descriptions of Coastal's compensation programs are
provided as well as the information on Coastal's 1996 pay levels for the CEO.

Overall Objectives of the Executive Compensation Program

     Coastal's  compensation  philosophy and program  objectives are directed by
two primary guiding principles.  First, the program is intended to provide fully
competitive  levels of  compensation  - at expected  levels of  performance - in
order to attract,  motivate and retain talented executives.  Second, the program
is intended to create an alignment of interests between Coastal's executives and
stockholders such that a significant portion of each executive's compensation is
directly linked to maximizing stockholder value.

     In  support  of this  philosophy,  the  executive  compensation  program is
designed to reward performance that is directly relevant to Coastal's short-term
and long-term success.  As such, Coastal attempts to provide both short-term and
long-term   incentive  pay  that  varies  based  on  corporate  and   individual
performance.



                                       13

<PAGE>

     To accomplish these objectives,  the Committee has structured the executive
compensation  program with three  primary  underlying  components:  base salary,
annual incentives, and long-term incentives (i.e., stock options). The following
sections  describe  Coastal's plans by element of  compensation  and discuss how
each component relates to Coastal's overall compensation philosophy.

     In  reviewing  this  information,  reference  is  often  made to the use of
competitive  market  data as criteria  for  establishing  targeted  compensation
levels.  Coastal targets the market 50th  percentile for its total  compensation
program  and  actual  total  compensation  rates in 1996  were at or  below  the
targeted  level.  (However,  Coastal's  competitive  pay  posture  varies by pay
element,  as described  below.) Several market data sources are used by Coastal,
including energy industry norms for the publicly traded peer companies  included
in  Coastal's  shareholder  return  performance  graph,  as  reflected  in these
companies' proxy statements.  In addition,  we utilize published survey data and
data  obtained  from  independent  consultants  that  are for  general  industry
companies  similar in size (i.e.,  revenues) to Coastal.  The published  surveys
include data on over 50 companies of comparable size to Coastal,  as measured by
revenues.  Greater  emphasis is placed on the  published  data and data obtained
from consultants than on the data for proxy peers,  since the published data and
consulting data are reflective of company size.

Base Salary Program

     Coastal's  base salary  program is based on a philosophy of providing  base
pay levels  that fall  between  the market  50th and 75th  percentiles.  Coastal
periodically  reviews its  executive pay levels to assure  consistency  with the
external  market.  Generally,  Coastal's  actual base salary levels for 1996 for
executives as a group were consistent with the targeted percentiles.  We believe
it is crucial to provide  strongly  competitive  salaries  over time in order to
attract and retain executives who are highly talented.

     Annual salary adjustments for Coastal are based on several factors: general
levels of market salary  increases,  individual  performance,  competitive  base
salary  levels,  and  Coastal's  overall  financial  results.   Coastal  reviews
performance  qualitatively  considering total shareholder  returns, the level of
earnings, return on equity, return on total capital and individual business unit
performance. These criteria are assessed qualitatively and are not weighted. All
base salary  increases  are based on a  philosophy  of  pay-for-performance  and
perceptions  of  an  individual's  long-term  value  to  Coastal.  As a  result,
employees  with higher levels of  performance  sustained  over time will be paid
correspondingly higher salaries.

The Annual Bonus Plan

     Coastal's  Annual Bonus Plan is intended to (1) reward key employees  based
on company/business unit and individual performance; (2) motivate key employees;
and  (3)  provide   competitive   cash   compensation   opportunities   to  plan
participants.  Under the plan,  target award  opportunities  vary by  individual
position and are expressed as a percent of base salary.  The  individual  target
award  opportunities,  which are slightly below market median  levels,  are then
aggregated  into a total target pool which is adjusted as described  below.  The
amount a particular executive may earn is directly dependent on the individual's
position, responsibility, and ability to impact our financial success.

     The actual bonus pool is established each year by modifying the target pool
based on Coastal's  overall  performance  against  measures  established  by the
Committee.  In fiscal year 1996,  the key  performance  measure  considered  was
earnings  before  interest and taxes  ("EBIT")  against  plan.  This measure was
weighted 50% of the total bonus program.  In 1996 Coastal's EBIT performance was
above  threshold  standards  (minimum  performance  level for bonus payment) but
below a very  aggressive  plan,  resulting in the EBIT portion of the bonus paid
being below target. The remaining 50% of the annual bonus opportunity in 1996 is
a discretionary  annual bonus pool. As a result, no formula performance measures
were used in  establishing  the size of awards  under this  portion of the plan.
However, in establishing the size of the discretionary bonus pool, the Committee
considered Coastal's Return on Equity relative to industry peers (using the same
peers  included  in the  shareholder  return  graph),  Return  on Total  Capital
compared to industry peers, the EBIT performance of each business unit, progress
made toward improving Coastal's operational and financial  performance,  and the
need to reward unique individual contributions. These measures were not formally
weighted by the Committee.  The size of the discretionary bonus pool element was
established above threshold but below target based on the


                                       14

<PAGE>

qualitative  performance  assessment described above. As a result,  actual bonus
payments for 1996 were below target and median market levels.

     Individual awards from the established bonus pool are recommended by senior
management,  with advice and consent from the Committee.  Individual awards from
the pool are based on business unit and individual employee performance,  future
potential,   and   competitive   considerations.   All  individual   performance
assessments  are  conducted  in a  non-formula  fashion  without  specific  goal
weightings.  The total  bonus  awards made may not exceed the amount of funds in
the bonus pool.

Long-Term Incentive Plan

     Coastal's  Long-Term Incentive Plan ("LTIP") is designed to focus executive
efforts on the  long-term  goals of Coastal and to maximize  total return to our
shareholders.  While  Coastal's  LTIP allows the  Committee  to use a variety of
long-term  incentive  devices,  the  Committee has relied solely on stock option
awards to provide long-term incentive opportunities in recent years.

     Stock  options  align  the  interests  of  employees  and  shareholders  by
providing  value to the executive  through stock price  appreciation  only.  All
stock options have a ten-year term before  expiration and are fully  exercisable
within 6 years of the grant date.

     Stock  options were granted to certain of the Named  Executive  Officers in
1996 and it is anticipated that stock option awards will be made periodically at
the discretion of the Committee in the future.  As in past years,  the number of
shares actually  granted to a particular  participant is also based on Coastal's
financial success, its future business plans, and the individual's  position and
level of  responsibility  within  Coastal.  All of these  factors  are  assessed
subjectively and are not weighted. Stock options granted by Coastal in 1996 were
overall below market median levels.

1996 Chief Executive Officer Pay

     As  previously  described,  the  Committee  considers  several  factors  in
developing  an  executive's  compensation  package.  For the CEO,  these include
competitive market practices (consistent with the philosophy described for other
executives),  experience,  achievement  of strategic  goals,  and the  financial
success of Coastal  (considering  the factors  described  under the annual bonus
plan above).

David A. Arledge

     Mr.  Arledge's annual salary was increased to $725,000 in 1996. This action
moved his salary closer to, but still below,  the market median levels of salary
for the CEO position in companies of comparable size.

     Mr. Arledge's bonus for 1996 was $300,000,  payable in 1997. This award was
below targeted levels (and below market median levels) since Coastal's aggregate
performance on the measures described in the annual bonus section of this report
were below the aggressive Coastal targets.

     The Committee  granted stock options for 150,000  shares to Mr.  Arledge in
1996 in  recognition  of his  performance  and as an  incentive  to continue his
efforts to increase  shareholder  value. These awards are tied to performance in
that the executive  only  realizes  income from stock options if the stock price
rises. The grant is below market median levels for the executive  positions held
by him.

$1 Million Pay Deductibility Cap

     Under Section  162(m) of the Internal  Revenue Code,  public  companies are
precluded  from  receiving a tax  deduction  on  compensation  paid to executive
officers  in excess of $1 million.  To address the $1 million pay  deductibility
cap issue,  Coastal's 1996 LTIP is structured so that stock option awards (which
are intended to be the primary long-term incentive vehicle for the present time)
qualify for an exemption from the $1 million pay deductibility limit.



                                       15

<PAGE>

     Also, at the present  time,  the Chairman of the Board of Directors and the
CEO are the only  executives  whose base  salary plus  target  bonus  exceeds $1
million. In order to preserve Coastal's tax deduction for base salary plus bonus
for  these  individuals,   Coastal  has  established  a  nonqualified   deferred
compensation program. Under this program, any annual incentive awards that bring
cash  compensation  to a level over $1 million may be deferred so that  payments
occur  after  the  individual  is no  longer  a Named  Executive  Officer,  thus
preserving the deductibility of the pay for Coastal.

                                Compensation and Executive Development Committee

                                John M. Bissell, Chairman
                                Roy D. Chapin, Jr.
                                Jerome S. Katzin



                                       16

<PAGE>

Pension Plan

     The following table shows for  illustration  purposes the estimated  annual
benefits  payable  currently  under the Pension Plan and  Coastal's  Replacement
Pension Plan described below upon retirement at age 65 based on the compensation
and years of credited service indicated.

                               Pension Plan Table

<TABLE>
<CAPTION>
                                                              Years of Credited Service
                                     ----------------------------------------------------------------------
      5-Year Final
      Average Pay                      15 Years       20 Years        25 Years       30 Years      35 Years
      -----------                    ----------------------------------------------------------------------

      <S>                            <C>             <C>            <C>             <C>           <C>      
      $    125,000.................  $   33,920      $  45,226      $   56,533      $  67,840     $  67,044
           150,000.................      41,420         55,226          69,033         82,840        82,044
           200,000.................      41,420         55,226          69,033         82,840        82,044
           250,000.................      41,420         55,226          69,033         82,840        82,044
           300,000.................      41,420         55,226          69,033         82,840        82,044
           350,000.................      41,420         55,226          69,033         82,840        82,044
           400,000.................      41,420         55,226          69,033         82,840        82,044
           500,000.................      41,420         55,226          69,033         82,840        82,044
           600,000.................      41,420         55,226          69,033         82,840        82,044
         1,000,000.................      41,420         55,226          69,033         82,840        82,044
         1,200,000.................      41,420         55,226          69,033         82,840        82,044

<FN>
(A)   Compensation  covered  under the Pension Plan for employees of Coastal and
      Coastal  Replacement  Pension Plan generally includes only base salary and
      is limited to $150,000 for 1996.

(B)  Federal  legislation  has reduced  the  benefit  which may be earned due to
     future service;  however, benefits previously earned may not be reduced. At
     December 31, 1996 each of the individuals named in the Summary Compensation
     Table had covered  salary for future  benefit  accrual of $150,000  and the
     following  years of  credited  service  and  pension  payable at age 65 (or
     current age, if over 65): Mr. Wyatt, 41 years,  $460,768;  Mr. Arledge,  16
     years,  $59,289;  Mr. Cordes, 19 years,  $81,059; Mr. King, 4 years $14,798
     (not vested);  and Mr. Bullock,  4 years,  $14,132 (not vested).  Mr. Wyatt
     reached  age  70 1/2 in  January,  1995  and  because  of IRS  requirements
     concerning  Coastal's  qualified  pension plan, he began receiving  pension
     payments in April 1996. These payments amounted to $282,775 in 1996.

(C)   The normal form of retirement income is a straight life annuity.  Benefits
      payable under the Pension Plan are subject to offset by 1.5% of applicable
      monthly  social  security  benefits  multiplied  by the number of years of
      credited service (up to 33 1/3 years).
</FN>
</TABLE>

     The  Employee  Retirement  Income  Security  Act of  1974,  as  amended  by
subsequent  legislation,  limits  the  retirement  benefits  payable  under  the
tax-qualified  Pension Plan. Where this occurs,  Coastal will provide to certain
executives,   including  persons  named  in  the  Summary   Compensation  Table,
additional  nonqualified retirement benefits under a Coastal Replacement Pension
Plan. These benefits,  plus payments under the Pension Plan, will not exceed the
maximum  amount  which  Coastal  would have been  required to provide  under the
Pension  Plan  before  application  of  the  legislative  limitations,  and  are
reflected in the above table and footnote (B).



                                       17

<PAGE>

             PERFORMANCE GRAPH - SHAREHOLDER RETURN ON COMMON STOCK

<TABLE>
<CAPTION>
                                            Five-Year Cumulative Values
                                              $100 Invested 12/31/91
                                               Dividends Reinvested

                                                      DOLLAR VALUE OF $100 INVESTMENT AT DECEMBER 31,
                                       -----------------------------------------------------------------------
                                        1991          1992         1993         1994         1995         1996
                                        ----          ----         ----         ----         ----         ----

<S>                                  <C>             <C>          <C>          <C>          <C>          <C> 
Coastal                              $   100         $  99        $ 118        $ 109        $ 157        $ 207
S&P 500                                  100           108          118          120          165          203
Index<F1><F2>                            100           112          132          119          128          196

<FN>
<F1> The  Index is based on Value  Line's  Diversified  Natural  Gas Group - the
     Performance Graph reflects total shareholder return weighted to reflect the
     market  capitalization  of the peer companies.  The peer group is comprised
     of:  Burlington  Res.,  Cabot,  Columbia,  Consolidated  Nat. Gas,  Eastern
     Enterprises,  Enron, Enserch,  Equitable Res., KN Energy,  Mitchell Energy,
     National  Fuel Gas,  Noram  Energy,  Panhandle  Eastern,  Questar,  Seagull
     Energy, Sonat, Southwestern Energy, Valero and Williams Cos.

<F2> Coastal is excluded from the Index.
</FN>
</TABLE>


Transactions with Management and Others

     In 1987,  Coastal Mart,  Inc.  ("Coastal  Mart"),  a subsidiary of Coastal,
entered into a ten-year  lease/purchase  agreement with Pester Marketing Company
("Pester Marketing") for 220 gasoline service stations  (subsequently reduced to
182 stations through  disposition of assets) located in the midwestern region of
the United States.  Jack Pester,  a principal  stockholder  and Chief  Executive
Officer  of Pester  Marketing,  subsequently  became an  employee,  officer  and
director of Coastal Mart and was elected a Senior Vice President of Coastal. Mr.
Pester is no longer active in the management of Pester Marketing,  and his stock
interest  in that  company  has  been  placed  in  trust.  In  1994,  the  lease
transaction  was  terminated  pursuant to an agreement  under which Coastal Mart
acquired  ownership  of and title to 175 of the  gasoline  service  stations and
Pester Marketing retained the seven remaining stations.

     During 1996, Coastal and/or its subsidiaries sold approximately  14,576,400
gallons of gasoline to Pester  Marketing at prevailing  market  prices  totaling
approximately $10,036,200.



                                       18

<PAGE>

     The following  table sets forth  ownership of units of limited  partnership
interests in the Coastal  1987  Drilling  Program,  Ltd.,  by directors  and all
directors and executive officers as a group.

Directors                                                                Units
---------                                                                -----

O. S. Wyatt, Jr. ..................................................        750
Harold Burrow .....................................................        100
David A. Arledge ..................................................          -
John M. Bissell ...................................................          -
George L. Brundrett, Jr. ..........................................          -
Roy D. Chapin, Jr. ................................................         20
James F. Cordes ...................................................          -
Roy L. Gates ......................................................          -
Kenneth O. Johnson ................................................          -
Jerome S. Katzin ..................................................          -
Thomas R. McDade...................................................          -
L. D. Wooddy, Jr...................................................          -
All directors and executive
  officers as a group (31 persons,
  including the above) ............................................        890

Item 12. Security Ownership of Certain Beneficial Owners and Management.

      (a)  Security ownership of certain beneficial owners.

     The following is information, as of March 12, 1997, on each person known or
believed by Colorado  to be the  beneficial  owner of 5% or more of any class of
its voting securities:

<TABLE>
<CAPTION>
                                                                                Amount and Nature
                                        Name and Address                          of Beneficial          Percent
Title of Class                         of Beneficial Owner                          Ownership           of Class
--------------                         -------------------                      -----------------       --------

<S>                              <C>                                            <C>                       <C>
Common Stock,                    Coastal Natural Gas Company                    10 shares direct          100%
$5 par value per share           Nine Greenway Plaza
                                 Houston, Texas 77046
</TABLE>

      (b)  Security ownership of management.

     Colorado is an indirectly,  wholly-owned subsidiary of Coastal. Information
concerning the security ownership of certain beneficial owners and management of
Coastal is contained in this section.

     The total number of shares of stock of Coastal  outstanding as of March 12,
1997 is 105,995,018 consisting of: 59,068 shares of $1.19 Cumulative Convertible
Preferred  Stock,  Series A (the "Series A Preferred  Stock"),  72,398 shares of
$1.83 Cumulative  Convertible Preferred Stock, Series B (the "Series B Preferred
Stock"),  and 31,940 shares of $5.00  Cumulative  Convertible  Preferred  Stock,
Series C (the "Series C Preferred Stock") (the Series A Preferred Stock,  Series
B  Preferred  Stock  and  Series  C  Preferred  Stock  are  referred  to  herein
collectively as the "Preferred Stock"),  105,451,513 shares of Common Stock, and
380,099 shares of Class A Common Stock.

     Each voting share of Common Stock or Preferred Stock entitles the holder to
one vote with  respect to all  matters to come  before a  shareholders'  meeting
while  each  share of Class A Common  Stock  entitles  the  holder to 100 votes.
However, 25% of Coastal's directors standing for election at each annual meeting
will be  determined  solely by holders of the Common Stock and voting  Preferred
Stock voting as a class.



                                       19

<PAGE>

     The  following  table sets forth  information,  as of March 12, 1997,  with
respect to each person known or believed by Coastal to be the beneficial  owner,
who has or  shares  voting  and/or  investment  power  (other  than as set forth
below), of more than five percent (5%) of any class of its voting securities.

<TABLE>
<CAPTION>
      Name and Address                                                                                 Percent (%)
     of Beneficial Owner                       Title of Class             Number of Shares            of Class (<F1>
     -------------------                       --------------             ----------------            ------------

<S>                                       <C>                               <C>                            <C> 
O. S. Wyatt, Jr.                            Class A Common Stock               154,577  <F2>               40.4
Chairman of the Board
of Coastal
Nine Greenway Plaza
Houston, Texas 77046-0995

Trustee/Custodian under the                     Common Stock                12,344,644  <F3>               11.7
Thrift Plan, ESOP and                       Class A Common Stock                64,429  <F3>               16.8
Pension Plan of Coastal
and its subsidiaries
Texas Commerce Bank
 National Association
600 Travis, 10th Floor
Houston, Texas  77002

FMR Corp.                                       Common Stock                 7,411,815                      7.0
82 Devonshire Street
Boston, Massachusetts 02109

Isabel H. Long                            Series A Preferred Stock              28,976                     49.1
485 S. Parkview Ave.,
Columbus, Ohio  43209-1075

The DeZurik Family                        Series C Preferred Stock              31,940  <F4>              100.0
c/o David DeZurik
2460 S.E. 8th St.
Pompano Beach, Florida 33062

<FN>
----------

<F1> Class includes  presently  exercisable  stock options held by directors and
     executive officers.

<F2> Includes 7,354 shares of Class A Common Stock owned by the spouse and a son
     of Mr. Wyatt, as to which shares beneficial ownership is disclaimed.

<F3> The  Trustee/Custodian is the record owner of these shares; and also is the
     record owner of 742 shares of the Series B Preferred  Stock,  each of which
     is convertible  into 3.6125 shares of Common Stock and 0.1 share of Class A
     Common Stock.  Voting  instructions  are requested from each participant in
     the  Thrift  Plan and ESOP and from the  trustees  under a  Pension  Trust.
     Absent timely voting instructions,  the Trustee is permitted to vote Thrift
     Plan and ESOP shares on any matter,  but has no  authority  to vote Pension
     Plan shares. Nor does the  Trustee/Custodian  have any authority to dispose
     of shares  except  pursuant to  instructions  of the  administrator  of the
     Thrift Plan and ESOP or pursuant to  instructions  from the trustees  under
     the Pension Trust.

<F4> Members of the DeZurik  family  acquired  the Series C  Preferred  Stock in
     connection  with a 1972  Agreement of Merger  involving the  acquisition of
     Colorado, a subsidiary of Coastal.
</FN>
</TABLE>

                                       20

<PAGE>

     The following table sets forth information, as of March 12, 1997, regarding
each of the  current  directors,  including  Class  II  directors  standing  for
election, and all directors and executive officers as a group. Each director has
furnished  the  information  with  respect  to  age,  principal  occupation  and
ownership of shares of stock of Coastal. Messrs. Arledge,  Brundrett, Wooddy and
Wyatt are Class II directors whose terms expire in 1997; Messrs.  Cordes, Gates,
Johnson  and McDade are Class III  directors  whose  terms  expire in 1998;  and
Messrs.  Bissell,  Burrow,  Chapin and Katzin are Class I directors  whose terms
expire in 1999.

<TABLE>
<CAPTION>
                                                                                                  Number of Shares
   Name, (Age), Year          Offices with Coastal                                                  Beneficially         Percent (%)
 First Became Director     and/or Principal Occupation                    Title of Class              Owned<F1>           of Class*
 ---------------------     ---------------------------                    --------------          ----------------      -----------

<S>                       <C>                                             <C>                        <C>                    <C> 
O. S. Wyatt, Jr.          Chairman of the Board                           Common Stock               2,858,863  <F2>         2.7
(72), 1955                                                                Class A Common Stock         154,577  <F2>        40.4

Harold Burrow             Vice Chairman of the Board;                     Common Stock                 137,127  <F2>
(82), 1973                Chairman of Colorado and ANR                    Class A Common Stock          13,601               3.6

David A. Arledge          President and                                   Common Stock                 181,112
(52), 1988                Chief Executive Officer                         Class A Common Stock           2,352

John M. Bissell           Chairman of the Board                           Common Stock                   5,080
(66), 1985                of Bissell Inc.                                 Class A Common Stock             -0-

George L. Brundrett, Jr.  Attorney                                        Common Stock                   4,910
(75), 1973                                                                Class A Common Stock           2,290

Roy D. Chapin, Jr.        Former Chairman and                             Common Stock                   3,250  <F2>
(81), 1988                Chief Executive Officer                         Class A Common Stock             -0-
                          of American Motors Corporation

James F. Cordes           Retired; former Executive Vice                  Common Stock                  18,708
(56), 1985                President of Coastal                            Class A Common Stock             -0-

Roy L. Gates              Ranching and Investments                        Common Stock                   4,095
(68), 1969                                                                Class A Common Stock           2,736

Kenneth O. Johnson        Senior Vice President                           Common Stock                  40,020
(76), 1988                                                                Class A Common Stock           9,604               2.5

Jerome S. Katzin          Retired Investment Banker                       Common Stock                  41,803
(78), 1983                                                                Class A Common Stock             -0-

Thomas R. McDade          Senior Partner, Law Firm of McDade,             Common Stock                     500
(64), 1993                Fogler, Maines & Lohse L.L.P., Houston          Class A Common Stock             -0-

L. D. Wooddy, Jr.         Retired; Former President of Exxon              Common Stock                   3,000
(70), 1992                Pipeline Company                                Class A Common Stock             -0-

All directors and executive officers as a group                           Common Stock               3,711,260  <F3>         3.5
(33 persons, including the above)                                         Class A Common Stock         186,568  <F3>        48.8

                        (See footnotes on following page)
<FN>
      *    Less than one percent  unless  otherwise  indicated.  Class  includes
           outstanding  shares and presently  exercisable  stock options held by
           directors and executive  officers.  Excluding  presently  exercisable
           stock options,  directors and executive officers as a group would own
           184,288 shares of Class A Common Stock,  which would constitute 48.5%
           of the shares of such class.

      <F1> Except for the  shares  referred  to in Notes 2 and 3 below,  and the
           shares  represented  by  presently  exercisable  stock  options,  the
           holders are  believed  by Coastal to have sole voting and  investment
           power as to the shares  indicated.  Amounts include shares in Coastal
           ESOP and Thrift Plan, and presently exercisable stock options held by
           Messrs.  Arledge  (162,093 shares of Common Stock and 2,280 shares of
           Class A Common  Stock),  Cordes (8,000 shares of Common  Stock),  and
           Johnson (7,848 shares of Common Stock).

                                       21

<PAGE>

      <F2> Includes  shares owned by the spouse and a son of Mr. Wyatt  (266,895
           shares of Common Stock and 7,354 shares of Class A Common Stock),  by
           the spouse of Mr.  Burrow  (5,000  shares of Common Stock) and by the
           spouse of Mr.  Chapin  (1,000  shares of Common  Stock),  as to which
           shares beneficial ownership is disclaimed.

      <F3> Includes  presently  exercisable  stock  options to purchase  453,829
           shares of Common Stock and 2,280 shares of Class A Common Stock; also
           includes  280,928  shares of Common Stock and 7,354 shares of Class A
           Common  Stock  owned by  spouses  and  children,  as to which  shares
           beneficial  ownership  is  disclaimed.  In  addition,  one  executive
           officer owns 8 shares of Series B Preferred  Stock,  each of which is
           convertible into 3.6125 shares of Common Stock and 0.1 share of Class
           A Common Stock.
</FN>
</TABLE>

     No incumbent director is related by blood,  marriage or adoption to another
director  or to  any  executive  officer  of  Coastal  or  its  subsidiaries  or
affiliates.

     Except as  hereafter  indicated,  the above table  includes  the  principal
occupation  of each of the  directors  during  the past five  years.  The listed
executive officers have held various executive positions with Coastal,  ANR, ANR
Pipeline and/or Colorado during the five-year period.

     Mr.  Bissell is a member of the Boards of Directors  of Old Kent  Financial
Corporation and Batts Inc.

     Mr. Cordes is a member of the Board of Directors of Comerica Inc.

     Mr. Katzin is a member of the Board of Directors of Qualcomm Incorporated.

     Mr. McDade is a trial lawyer and the founding senior partner of the Houston
law firm of McDade,  Fogler,  Maines & Lohse  L.L.P.  Prior to  forming  McDade,
Fogler,  Maines & Lohse L.L.P.,  he was a senior partner in the Houston law firm
of  Fulbright &  Jaworski.  He is a member of the Board of  Directors  of Equity
Corporation International.

     Messrs. Arledge and Burrow are directors of Colorado and ANR Pipeline. Both
of these  subsidiaries  of Coastal are subject to the reporting  requirements of
the Securities Exchange Act of 1934, as amended.

Item 13. Certain Relationships and Related Transactions.

      (a)  Transactions with management and others.

     The  Company  participates  in a  program  which  matches  short-term  cash
excesses and  requirements of  participating  affiliates,  thus minimizing total
borrowings from outside  sources.  At December 31, 1996 the Company had advanced
$139.4 million to associated companies at a market rate of interest. Such amount
is repayable on demand.

     Additional  information called for by this item is set forth under Item 11,
"Executive  Compensation" and Notes 8 and 13 of Notes to Consolidated  Financial
Statements included herein.

      (b)  Certain business relationships.

           None.

      (c)  Indebtedness of management.

           None.

      (d)  Transactions with promoters.

           Not applicable.


                                       22

<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 Colorado 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-6
           Consolidated Balance Sheet at December 31, 1996 and 1995........................................  F-7
           Statement of Consolidated Earnings for the Years Ended December 31, 1996, 1995 and 1994.........  F-9
           Statement of Consolidated Retained Earnings and Additional Paid-In Capital for the Years
              Ended December 31, 1996, 1995 and 1994.......................................................  F-9
           Statement of Consolidated Cash Flows for the Years Ended December 31, 1996, 1995 and 1994.......  F-10
           Notes to Consolidated Financial Statements......................................................  F-11
           Supplemental Information on Oil and Gas Producing Activities (Unaudited)........................  F-24
</TABLE>

      2.   Financial Statement Schedules.

                 Schedules 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)+     Certificate of  Incorporation of the Company (Exhibit to
                        the Company's  Annual Report on Form 10-K for the fiscal
                        year ended December 31, 1980).

             (3.2)+     By-laws of  the Company (Filed  as  Module CIGBY-LAWS on
                        March 29, 1994).

             (3.3)+     Certificate   of   Amendment   of    Certification    of
                        Incorporation   of  the  Company  (Exhibit  3.1  to  the
                        Company'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 Company will furnish to
                        the Securities and Exchange Commission any such document
                        on request.

             (10)+      Agreement  for  Consulting   Services  between  Colorado
                        Interstate  Gas Company and Harold  Burrow dated January
                        1, 1996  (Exhibit 10 to the  Company's  Annual Report on
                        Form 10 for the fiscal year ended December 31, 1995).

             (21)*   Subsidiaries of the Company.

             (23)*   Consent of Deloitte & Touche LLP.

             (24)*   Power of Attorney (included on signature pages herein).

             (27)*   Financial Data Schedule.

----------------------

      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.


                                       23

<PAGE>

                                POWER OF ATTORNEY

     Each person whose signature appears below hereby appoints David A. Arledge,
Dan A. Homec 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.

      COLORADO INTERSTATE GAS COMPANY
      (Registrant)


By:  JON R. WHITNEY
     --------------------------------------
     Jon R. Whitney
     President and Chief Executive Officer
     March 27, 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:  JEFFREY A. CONNELLY
     --------------------------------------
     Jeffrey A. Connelly
     Director
     March 27, 1997


By:  HAROLD BURROW
     --------------------------------------
     Harold Burrow
     Director
     March 27, 1997


By:  JON R. WHITNEY
     --------------------------------------
     Jon R. Whitney
     Director
     March 27, 1997


By:  DAVID A. ARLEDGE
     --------------------------------------
     David A. Arledge
     Principal Financial Officer and Director
     March 27, 1997


                                       24

<PAGE>

By:  DAN A. HOMEC
     --------------------------------------
     Dan A. Homec
     Principal Accounting Officer
     March 27, 1997


By:  C. SCOTT HOBBS
     --------------------------------------
     C. Scott Hobbs
     Director
     March 27, 1997



                                       25

<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  natural gas  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> 
      Cash flow from operating activities to capital expenditures and debt
      service requirements...................................................      133.4%      147.5%       374.5%

      Total debt to total capitalization.....................................       35.5%       28.0%        30.3%

      Times interest earned (before tax and extraordinary item)..............        7.5         8.3          7.4
</TABLE>

     The  Company's  primary  needs for cash are capital  expenditures  and debt
service  requirements.  Capital  expenditures,  debt  retirements and other cash
needs in each of the years 1994  through 1996 and the sources of capital used to
finance these  expenditures are summarized in the Statement of Consolidated Cash
Flows.  Management believes the Company's stable financial position and earnings
ability will enable it to continue to generate and obtain  capital for financing
needs in the foreseeable future.

     Cash flow from  operating  activities  amounted to $127.6  million in 1996,
$86.6  million in 1995 and  $195.7  million in 1994.  The 1996  increase  can be
attributed  primarily to decreases for working capital  requirements.  Liquidity
needs  were  met in 1996  by  internally  generated  funds  and a $50.0  million
borrowing under a term loan.

     The Company has adopted a capital expenditure budget of approximately $76.0
million for 1997,  a decrease  from the capital  additions  of $95.6  million in
1996. The anticipated decrease in 1997 is the result of a $17.7 million decrease
for natural  gas  projects  and a $1.9  million  decrease  for  exploration  and
production projects. Alternatives to finance capital expenditures and other cash
needs  are  primarily  limited  by  the  terms  of one  of  the  Company's  debt
instruments.  As of December 31,  1996,  the Company  could incur  approximately
$403.9 million of additional indebtedness.

     In December  1996,  the Company  invested $41.0 million in a new affiliate,
Coastal Medical Services,  Inc. The affiliate has assumed the responsibility for
facilitating the funding and management of a portion of the medical  obligations
of the Company and other Coastal subsidiaries.

     The  Company  participates  in a  program  which  matches  short-term  cash
excesses  and   requirements  of  participating   affiliates,   thus  minimizing
borrowings from outside sources.  At December 31, 1996, the Company had advanced
$139.4 million to associated companies at a market rate of interest. Such amount
is repayable on demand.

     The  Company is  responding  to the  extensive  changes in the  natural gas
industry by continuing to take steps to operate its  facilities at their maximum
efficient capacity, renegotiating the remaining gas purchase contracts which are
above  market  in an  effort  to  lower  its  cost of gas,  pursuing  innovative
marketing strategies and applying strict cost-cutting measures.



                                       F-1

<PAGE>

     The Company's  operations  are subject to extensive  and evolving  federal,
state  and local  environmental  laws and  regulations  which  may  affect  such
operations and costs as a result of their effect on the construction, operation,
and maintenance of its pipeline facilities. The Company spent approximately $1.2
million  on  environmental  capital  projects  in 1996  and  anticipates  annual
environmental  capital  expenditures  of $1 to $2 million  over the next several
years  aimed  at  maintaining   compliance  with  such  laws  and   regulations.
Additionally,  appropriate  governmental  authorities  may  enforce the laws and
regulations with a variety of civil and criminal enforcement measures, including
monetary penalties and remediation requirements.

     The Comprehensive  Environmental Response,  Compensation and Liability Act,
also known as "Superfund", as reauthorized, imposes liability, without regard to
fault  or the  legality  of the  original  act,  for  disposal  of a  "hazardous
substance."  The  Company  is not  presently,  and has not been in the  past,  a
potentially  responsible  party ("PRP") in any "Superfund" waste disposal sites.
However, the Company has received notice from a committee formed from a group of
55 companies who are named as PRPs at one site  requesting  the Company pay a de
minimis share (approximately $36,000) of the associated clean-up costs.

     Future information and developments will require the Company to continually
reassess  the  expected  impact  of  all  applicable   environmental   laws  and
regulations.  Compliance with all applicable  environmental  protection laws and
regulations  is not expected to have a material  adverse impact on the Company's
liquidity, consolidated financial position or results of operations.

                              Results of Operations

Operating Revenues

     The following table reflects the increase  (decrease) in operating revenues
experienced by segment during the past two years (millions of dollars):

<TABLE>
<CAPTION>
                                                                                           Increase (Decrease)
                                                                                             From Prior Year
                                                                                           -------------------
                                                                                            1996        1995
                                                                                           ------      ------

      <S>                                                                                 <C>          <C>   
      Natural gas....................................................................     $    26      $    6
      Exploration and production.....................................................           7         (13)
      Adjustments and eliminations...................................................          (3)          3
                                                                                          -------      ------
                                                                                          $    30      $   (4)
                                                                                          =======      ======
</TABLE>

Natural Gas

     1996 Versus 1995.  Revenues from natural gas  operations  increased in 1996
due to a $30  million  increase  related to  average  gas sales  prices,  an $11
million increase related to increased gas transportation  volumes, an $8 million
increase  resulting  from  increased gas sales  volumes and increased  extracted
product  revenues of $6 million offset by a $24 million  change in  reservations
and other decreases of $5 million.

     1995 Versus 1994.  Revenues from natural gas  operations  increased in 1995
due to changes in reservations  of $61 million offset by a $17 million  decrease
resulting from reduced average gas sales prices,  a $17 million decrease related
to reduced sales volumes, decreased transportation and gathering revenues of $14
million and other decreases of $7 million.

     The daily average  volumes of natural gas sold were 244 MMcf,  229 MMcf and
259 MMcf for 1996,  1995 and 1994,  respectively.  However,  it is expected that
customers  will  reduce  their  contractual  sales  entitlement  pursuant to the
provisions of Order 636. Transportation volumes increased by 7% in 1996 over the
1995 level and the 1997  transportation  volumes  are  estimated  to be slightly
higher than in 1996.



                                       F-2

<PAGE>

Exploration and Production

     1996 Versus 1995.  Revenues from  exploration  and production  increased in
1996 as a result of higher  natural  gas sales  prices  generating  a $5 million
increase and $2 million from increased natural gas volumes.

     1995 Versus 1994.  Revenues from  exploration  and production  decreased in
1995 as a result of natural gas sales volumes  generating a $6 million decrease,
natural gas sales  prices  decreasing  $4 million and other net  decreases of $3
million.

Other Income - Net

     The decrease in 1996 and the increase in 1995 primarily  reflect changes in
interest income resulting from loans to affiliated companies.

Cost of Gas Sold

     1996 Versus  1995.  The  increase is due  primarily  to higher  average gas
purchase  rates  of  $31  million  and  $5  million  in  net  system   balancing
requirements.

     1995 Versus  1994.  The decrease is due  primarily  to reduced  average gas
purchase rates of $20 million and other decreases of $1 million partially offset
by increased gas used costs of $9 million and increased  purchase  volumes of $3
million.

Operation and Maintenance

     1996 Versus  1995.  Operation  and  maintenance  expense  decreased in 1996
primarily due to a $3 million  decrease in payroll and employee  benefits due to
an early retirement incentive program in 1995.

     1995 Versus 1994.  Operation and maintenance  expense increased in 1995 due
primarily  to the  discontinuance  of a production  incentive  fee credit in the
amount of $5 million partially offset by other net decreases of $2 million.

Depreciation, Depletion and Amortization

     1996 Versus  1995.  The  increase in 1996 is due  primarily to a $2 million
increase as a result of increased  depreciable  plant in the natural gas segment
and  a  $1  million  increase  related  to  higher  production  volumes  in  the
exploration and production segment.

     1995 Versus 1994. The decrease in 1995 of  approximately  $3 million is due
primarily to a $4 million decrease related to reduced  production  volumes and a
$1 million decrease due to a lower depreciation, depletion and amortization rate
in the exploration and production  segment offset by a $2 million  increase as a
result of increased depreciable plant in the natural gas segment.

Operating Profit

     The following  table reflects the increase  (decrease) in operating  profit
experienced by segment during the past two years (millions of dollars):

<TABLE>
<CAPTION>
                                                                                           Increase (Decrease)
                                                                                             From Prior Year
                                                                                          --------------------
                                                                                            1996        1995
                                                                                          --------    --------

      <S>                                                                                 <C>          <C>   
      Natural gas....................................................................     $   (12)     $   11
      Exploration and production.....................................................           7          (7)
                                                                                          -------      ------
                                                                                          $    (5)     $    4
                                                                                          =======      ======
</TABLE>


                                       F-3

<PAGE>

Natural Gas

     1996 Versus 1995. The natural gas segment's  operating  profit  decrease in
1996 is due to a $36 million  increase in the cost of gas sold and $2 million in
other items offset by a $26 million increase in operating revenues.

     1995 Versus 1994. The natural gas segment's  operating  profit  increase in
1995 is due to increased operating revenues of $6 million, decreased gas related
costs of $9 million and other increases of $2 million  partially  offset by a $4
million increase in operation and maintenance expenses and a $2 million increase
in depreciation, depletion and amortization expense.

Exploration and Production

     1996 Versus 1995. The exploration and production segment's operating profit
increase in 1996 is due to increased revenues of $7 million.

     1995 Versus 1994. The exploration and production segment's operating profit
decrease in 1995 is due to decreased revenues of $13 million partially offset by
decreased  depreciation,  depletion and  amortization  expense of $5 million and
other decreases of $1 million.

Interest Expense

     1996 Versus 1995.  The increase in 1996 is due to interest on a $50 million
senior term loan, due 1999, which was entered into August 27, 1996.

     1995 Versus  1994.  The slight  decrease  in 1995 is due to a reduction  in
interest on provisions for rate refunds.

Taxes on Income

     Income taxes fluctuated  primarily as a result of changing levels of income
before taxes and changes in the effective income tax rate. The effective federal
income tax rate for the Company was 32% in 1996, 32% in 1995 and 33% in 1994.

Extraordinary Item - Loss from Discontinuance of FAS 71

     The Company is subject to the regulations and accounting  procedures of the
FERC and has historically followed the reporting and accounting  requirements of
FAS No. 71  "Accounting  for the Effects of Certain Types of  Regulation"  ("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  is no longer  consistent  with the form of  regulation
contemplated by FAS 71. Accordingly, effective November 1, 1996, the Company has
ceased to apply the provisions of FAS 71 to its transactions and balances, which
accounting change has been implemented pursuant to the guidance contained in FAS
101,  "Regulated  Enterprises - Accounting for the Discontinuance of Application
of FASB  Statement  No.  71." The  Company  does not expect the change to have a
material  adverse impact on financial  results in future  periods,  and believes
this accounting change will result in financial  reporting which better reflects
the results of operations in the economic  environment  in which the Company now
operates. See Note 10 of the Notes to Consolidated Financial Statements.

     This  accounting   change  has  resulted  in  the   elimination   from  the
Consolidated  Balance Sheet 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 $6.3 million,  net of related income taxes of $(1.5)
million,  and is shown as an extraordinary item in the Statement of Consolidated
Earnings.


                                       F-4

<PAGE>

The  charge to  earnings  was  noncash  and will  have no  direct  effect on the
Company's  ability to include  the  underlying  deferred  items in future  rates
proceedings or on its ability to collect the rates set thereby.

Recent Pronouncements

     The FASB has issued FAS 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  financial
position, results of operations 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.




                                       F-5

<PAGE>






                          INDEPENDENT AUDITORS' REPORT



Board of Directors and Stockholder
Colorado Interstate Gas Company
Colorado Springs, Colorado


     We have audited the  accompanying  consolidated  balance sheets of Colorado
Interstate  Gas Company (an  indirect,  wholly-owned  subsidiary  of The Coastal
Corporation)  and subsidiaries as of December 31, 1996 and 1995, and the related
consolidated  statements of earnings,  retained earnings and additional  paid-in
capital and cash flows for each of the three years in the period ended  December
31, 1996.  These financial  statements are the  responsibility  of the Company's
management.  Our  responsibility  is to express  an  opinion on these  financial
statements 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 financial position of Colorado Interstate Gas Company
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.




DELOITTE & TOUCHE LLP




Denver, Colorado
January 31, 1997



                                       F-6

<PAGE>

                COLORADO INTERSTATE GAS COMPANY AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEET
                             (Thousands of Dollars)
<TABLE>
<CAPTION>
                                                                                              December 31,
                                                                                      ---------------------------
                                ASSETS                                                    1996           1995
                                                                                      ------------   ------------

<S>                                                                                   <C>            <C>         
Plant, Property and Equipment, at cost:
   Gas pipeline...................................................................    $  1,134,592   $  1,061,497
   Gas and oil properties, at full-cost...........................................         125,024        138,067
                                                                                      ------------   ------------
                                                                                         1,259,616      1,199,564

   Accumulated depreciation, depletion and amortization...........................         676,873        658,327
                                                                                      ------------   ------------
                                                                                           582,743        541,237
                                                                                      ------------   ------------

Current Assets:
   Cash...........................................................................             539            883
   Notes receivable from affiliates...............................................         139,390        209,449
   Receivables....................................................................          51,961         44,518
   Receivables from affiliates....................................................          51,056         12,335
   Inventories....................................................................           9,671          9,494
   Prepaid expenses...............................................................             417            280
   Current portion of deferred income taxes.......................................          26,782         25,359
                                                                                      ------------   ------------
                                                                                           279,816        302,318
                                                                                      ------------   ------------

Other Assets:
   Investments in affiliates......................................................          41,056            114
   Other deferred charges.........................................................           5,307         17,779
                                                                                      ------------   ------------
                                                                                            46,363         17,893
                                                                                      ------------   ------------

                                                                                      $    908,922   $    861,448
                                                                                      ============   ============
</TABLE>


                 See Notes to Consolidated Financial Statements.


                                       F-7

<PAGE>

                COLORADO INTERSTATE GAS COMPANY AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEET
                             (Thousands of Dollars)
<TABLE>
<CAPTION>
                                                                                              December 31,
                                                                                      ---------------------------
                 STOCKHOLDER'S EQUITY AND LIABILITIES                                     1996           1995
                                                                                      ------------   ------------

<S>                                                                                   <C>            <C>         
Common Stock and Other Stockholder's Equity:
   Common stock, $5 par value, authorized 10,000 shares; issued and
      outstanding 10 shares at stated value.......................................    $     27,561   $     27,561
   Additional paid-in capital.....................................................          19,037         19,035
   Retained earnings..............................................................         370,054        413,212
                                                                                      ------------   ------------
                                                                                           416,652        459,808
                                                                                      ------------   ------------

Mandatory Redemption Preferred Stock, $100 par value, authorized 550,000 shares:
      5.50% Series................................................................               -            556
                                                                                      ------------   ------------

Debt:
   Long-term debt.................................................................         229,373        179,299
                                                                                      ------------   ------------

Current Liabilities:
   Accounts payable and accrued expenses..........................................         132,641        115,599
   Accounts payable to affiliates.................................................          25,356         11,352
   Taxes on income................................................................          13,162          1,594
                                                                                      ------------   ------------
                                                                                           171,159        128,545
                                                                                      ------------   ------------

Deferred Credits:
   Deferred income taxes..........................................................          85,849         88,298
   Other..........................................................................           5,889          4,942
                                                                                      ------------   ------------
                                                                                            91,738         93,240
                                                                                      ------------   ------------

                                                                                      $    908,922   $    861,448
                                                                                      ============   ============
</TABLE>


                 See Notes to Consolidated Financial Statements.


                                       F-8

<PAGE>

                COLORADO INTERSTATE GAS COMPANY AND SUBSIDIARIES
                       STATEMENT OF CONSOLIDATED EARNINGS
                             (Thousands of Dollars)
<TABLE>
<CAPTION>
                                                                                     Year Ended December 31,
                                                                              ----------------------------------
                                                                                 1996        1995         1994
                                                                              ----------  ----------   ---------

<S>                                                                           <C>         <C>          <C>      
Revenues:
   Operating revenues:
      Nonaffiliates.......................................................    $  338,824  $  332,963   $ 324,765
      Affiliates..........................................................        73,653      49,237      61,788
                                                                              ----------  ----------   ---------
                                                                                 412,477     382,200     386,553
   Other income-net.......................................................        12,987      14,331       8,735
                                                                              ----------  ----------   ---------
                                                                                 425,464     396,531     395,288
                                                                              ----------  ----------   ---------
Costs and Expenses:
   Cost of gas sold:
      Nonaffiliates.......................................................        75,129      39,540      46,729
      Affiliates..........................................................         5,102       4,591       6,292
                                                                              ----------  ----------   ---------
                                                                                  80,231      44,131      53,021
   Operation and maintenance..............................................       160,708     163,832     160,487
   Depreciation, depletion and amortization...............................        42,301      39,037      41,655
   Interest expense.......................................................        18,861      18,092      18,932
   Taxes on income........................................................        41,305      43,723      42,686
                                                                              ----------  ----------   ---------
                                                                                 343,406     308,815     316,781
                                                                              ----------  ----------   ---------

Earnings before Extraordinary Item........................................    $   82,058  $   87,716   $  78,507
Extraordinary Item - Loss from Discontinuance of FAS 71,
   Net of Income Taxes....................................................        (6,301)          -           -
                                                                              ----------  ----------   ---------
Net Earnings..............................................................    $   75,757  $   87,716   $  78,507
                                                                              ==========  ==========   =========
</TABLE>


                 STATEMENT OF CONSOLIDATED RETAINED EARNINGS AND
                           ADDITIONAL PAID-IN CAPITAL
                             (Thousands of Dollars)

<TABLE>
<CAPTION>
                                                                                     Year Ended December 31,
                                                                              ----------------------------------
                                                                                 1996        1995         1994
                                                                              ----------  ----------   ---------

<S>                                                                           <C>         <C>          <C>      
Retained Earnings:
Beginning balance.........................................................    $  413,212  $  364,827   $ 311,451
   Net earnings...........................................................        75,757      87,716      78,507

   Less dividends:
      Preferred stock:
         5.50% Series.....................................................            15          31          31
      Common stock........................................................       118,900      39,300      25,100
                                                                              ----------  ----------   ---------
                                                                                 118,915      39,331      25,131
                                                                              ----------  ----------   ---------

Ending balance............................................................    $  370,054  $  413,212   $ 364,827
                                                                              ==========  ==========   =========

Additional Paid-In Capital:
Beginning balance.........................................................    $   19,035  $   19,035   $  19,035
   Gain on redemption of preferred stock..................................             2           -           -
                                                                              ----------  ----------   ---------

Ending balance............................................................    $   19,037  $   19,035   $  19,035
                                                                              ==========  ==========   =========
</TABLE>

                 See Notes to Consolidated Financial Statements.


                                       F-9

<PAGE>

                COLORADO INTERSTATE GAS COMPANY AND SUBSIDIARIES
                      STATEMENT OF CONSOLIDATED CASH FLOWS
                             (Thousands 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.....................................    $   82,058  $   87,716   $  78,507
   Add (subtract) items not requiring (providing) cash:
      Depreciation, depletion and amortization............................        42,301      39,037      41,655
      Deferred income taxes...............................................           216      21,602     (17,002)
      Producer contract reformation cost recoveries.......................           135         140       3,056
      Other...............................................................         6,716       3,821       8,511
   Working capital and other  changes,  excluding  changes  relating to cash and
    non-operating activities:
      Receivables.........................................................        (7,443)     73,835      54,434
      Receivables from affiliates.........................................       (38,721)     13,571      14,821
      Inventories.........................................................          (177)       (340)        391
      Prepaid expenses....................................................          (137)        348         351
      Accounts payable and accrued expenses...............................        17,042    (132,688)     14,485
      Accounts payable to affiliates......................................        14,004      (3,029)    (21,203)
      Taxes on income.....................................................        11,568     (17,419)     17,738
                                                                              ----------  ----------   ---------

                                                                                 127,562      86,594     195,744
                                                                              ----------  ----------   ---------

Cash Flow from Investing Activities:
   Purchases of plant, property and equipment.............................       (95,597)    (58,716)    (52,263)
   Proceeds from sale of plant, property and equipment....................         7,934       1,756       1,187
   Investments in affiliates..............................................       (40,942)     (1,341)      1,226
   Net (increase) decrease in notes receivable from affiliates............        70,059      11,254    (113,250)
   Gas supply prepayments and settlements.................................             -         (12)        (28)
   Recovery of gas supply prepayments.....................................           109         314         375
                                                                              ----------  ----------   ---------

                                                                                 (58,437)    (46,745)   (162,753)
                                                                              ----------  ----------   ---------

Cash Flow from Financing Activities:
   Redemption of preferred stock..........................................          (556)          -           -
   Gain on redemption of preferred stock..................................             2           -           -
   Proceeds from long-term debt issue.....................................        50,000           -           -
   Preferred dividends paid...............................................           (15)        (38)        (23)
   Common dividends paid..................................................      (118,900)    (39,300)    (33,300)
                                                                              ----------  ----------   ---------

                                                                                 (69,469)    (39,338)    (33,323)
                                                                              ----------  ----------   ---------

Net Increase (Decrease) in Cash...........................................          (344)        511        (332)

Cash at Beginning of Year.................................................           883         372         704
                                                                              ----------  ----------   ---------

Cash at End of Year.......................................................    $      539  $      883   $     372
                                                                              ==========  ==========   =========
</TABLE>


                 See Notes to Consolidated Financial Statements.


                                      F-10

<PAGE>


                COLORADO INTERSTATE GAS COMPANY AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1. Summary of Significant Accounting Policies

- Basis of Presentation

     Colorado is a subsidiary of Coastal Natural Gas, a wholly-owned  subsidiary
of  Coastal.  The stock of the  Company  was  contributed  by Coastal to Coastal
Natural  Gas  effective  April 30,  1982.  The  financial  statements  presented
herewith are  presented on the basis of  historical  cost and do not reflect the
basis of cost to Coastal Natural Gas. 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.

     The Company is regulated by, and subject to, the regulations and accounting
procedures  of  the  FERC  and  has  historically  followed  the  reporting  and
accounting  requirements  of FAS No. 71,  "Accounting for the Effects of Certain
Types  of  Regulation"  ("FAS  71").   Effective  November  1,  1996,   Colorado
discontinued the application of FAS 71.  Additional  information is set forth in
Note 10 of Notes to Consolidated Financial Statements included herein.

- Principles of Consolidation

     The Consolidated  Financial  Statements include the accounts of the Company
and  its   subsidiaries   after   eliminating   all   significant   intercompany
transactions.

- 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,
net of amounts capitalized, of $18.6 million, $19.3 million and $17.5 million in
1996,  1995 and 1994,  respectively.  Cash payments for income taxes amounted to
$29.1  million,  $39.5  million  and  $41.9  million  in 1996,  1995  and  1994,
respectively.

- Inventories

     Materials and supplies inventories are carried principally at average cost.

- Plant, Property and Equipment

     Property  additions and  betterments are capitalized at cost. In accordance
with  accounting  requirements of the FERC, an allowance for equity and borrowed
funds used during construction  ("AFUDC") is included in the cost of the natural
gas segment's additions and betterments. This cost amounted to $1.2 million, $.9
million  and $1.9  million  in  1996,  1995 and  1994,  respectively.  Effective
November 1, 1996,  the Company  discontinued  the  application  of FAS 71 and no
longer  capitalizes  equity  costs.  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.

     The Company  generally  provides for depreciation on a straight-line  basis
with rates that vary by type of property.  The depreciation rates for production
and gathering,  products  extraction,  storage and transmission plant are 1.55%,
3.85%, 2.90% and 2.60%, respectively.  Depreciation,  depletion and amortization
of gas and oil properties are provided on the  unit-of-production  basis whereby
the unit rate for  depreciation,  depletion  and  amortization  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


                                      F-11

<PAGE>

equivalent  unit of a  thousand  cubic  feet of gas  production  for oil and gas
operations  was $.88 for the year 1996,  $.89 for the year 1995 and $.96 for the
year 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
depreciation, depletion and amortization expense. No such charge was required in
the periods presented.

     The cost of minor property units  replaced or retired,  net of salvage,  is
credited to plant  accounts and charged to accumulated  depreciation,  depletion
and amortization. Since provisions for depreciation,  depletion and amortization
expense  are  made  on  a  composite   basis,   no  adjustments  to  accumulated
depreciation, depletion and amortization are made in connection with retirements
or other dispositions occurring in the ordinary course of business. 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  financial  position,  results of
operations or cash flows.

- Income Taxes

     The Company follows the liability method of accounting for deferred federal
income  taxes as required by the  provisions  of FAS No.  109,  "Accounting  for
Income  Taxes."  The Company is a member of a  consolidated  group which files a
consolidated  federal income tax return.  Members of the consolidated group with
taxable  income 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.

- Revenue Recognition

     The  Company  recognizes  revenues  for the sale of their  products  in the
period of  delivery.  Revenue  for  services  are  recognized  in the period the
services are provided.

- New Accounting Standards

     The FASB has issued FAS 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  financial
position, results of operations 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.

- Reclassification of Prior Period Statements

     Certain minor  reclassifications  of prior period statements have been made
to conform with current reporting practices. The effect of the reclassifications
was not material to the Company's  consolidated  financial position,  results of
operations or cash flows.



                                      F-12

<PAGE>

2. Long-Term Debt

     Balances at December 31 were as follows (thousands of dollars):

<TABLE>
<CAPTION>
                                                                                               1996        1995
                                                                                            ---------    --------

      <S>                                                                                   <C>         <C>      
      10% Senior Debentures, due 2005...................................................    $ 179,373   $ 179,299
      Senior Term Loan, due 1999........................................................       50,000           -
                                                                                            ---------   ---------
                                                                                            $ 229,373   $ 179,299
                                                                                            =========   =========
</TABLE>

     The 10% Senior  Debentures,  due 2005, are not redeemable prior to maturity
and have no sinking fund provisions.

     On August 27, 1996, the Company entered into a $50 million senior term loan
agreement  with a commercial  bank which  expires on August 30,  1999.  The loan
carries a variable  interest rate equal to the  corporate  base rate or a margin
over the London  Interbank  Offered Rate, with the interest rate option selected
by the Company.

     Alternatives  to  finance  capital  expenditures  and other  cash needs are
primarily limited by the terms of one of the Company's debt  instruments.  As of
December 31,  1996,  the Company  could incur  approximately  $403.9  million of
additional indebtedness.

3. Common Stock and Other Stockholders' Equity

     All of the Company's common stock is owned by Coastal Natural Gas.

     At December 31, 1996,  $269.3  million of retained  earnings were available
for dividends on common stock.

4. Mandatory Redemption Preferred Stock

     All of the remaining shares of the Company's mandatory Redemption Preferred
Stock were redeemed on July 31, 1996 at par value.

5. 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 could be realized in a current market exchange.

<TABLE>
<CAPTION>
                                                             December 31, 1996              December 31, 1995
                                                        --------------------------      -------------------------
                                                        Carrying           Fair         Carrying          Fair
                                                         Amount            Value         Amount           Value
                                                        --------         ---------      --------        ---------
                                                                          (Thousands of Dollars)

      <S>                                              <C>             <C>            <C>              <C>       
      Financial assets:
         Cash.......................................   $       539     $       539    $       883      $      883
         Notes receivable from affiliates...........       139,390         139,390        209,449         209,449
      Financial liabilities:
         Long-term debt.............................       229,373         264,600        179,299         223,819
         Mandatory redemption preferred stock.......             -               -            556             556
</TABLE>

     The  carrying  values  of cash and notes  receivable  from  affiliates  are
reasonable  estimates of their fair values. The estimated value of the Company's
long-term  debt and mandatory  redemption  preferred  stock is based on interest
rates at December 31, 1996 and 1995,  respectively,  for new issues with similar
remaining maturities.



                                      F-13

<PAGE>

6. Taxes On Income

     Provisions  for  income  taxes  (benefits)  before  extraordinary  item are
composed of the following (thousands of dollars):

<TABLE>
<CAPTION>
                                                                                      Year Ended December 31,
                                                                                   1996        1995        1994
                                                                                 --------    --------    --------

      <S>                                                                        <C>         <C>         <C>
      Current Income Taxes:
         Federal.............................................................    $ 39,127    $ 22,406    $ 54,194
         State...............................................................       1,962        (285)      5,494
                                                                                 --------    --------    --------
                                                                                   41,089      22,121      59,688
                                                                                 --------    --------    --------

      Deferred Income Taxes:
         Federal.............................................................          87      19,328     (15,439)
         State...............................................................         129       2,274      (1,563)
                                                                                 --------    --------    --------
                                                                                      216      21,602     (17,002)
                                                                                 --------    --------    --------

      Taxes on Income........................................................    $ 41,305    $ 43,723    $ 42,686
                                                                                 ========    ========    ========
</TABLE>

     Coastal  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.  Coastal's
federal  income  tax  returns  filed for the years 1988  through  1990 have been
examined by the IRS and Coastal has received  notice of proposed  adjustments to
the returns for each of those years.  Coastal currently is contesting certain of
these adjustments with the IRS Appeals Office.  Examination of Coastal'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 Company's consolidated financial statements.

     Provisions for federal income taxes were different from the amount computed
by applying the statutory U.S.  federal income tax rate to earnings  before tax.
The reasons for these differences are (thousands of dollars):

<TABLE>
<CAPTION>
                                                                                      Year Ended December 31,
                                                                                 --------------------------------
                                                                                   1996        1995        1994
                                                                                 --------    --------    --------

      <S>                                                                        <C>         <C>         <C>     
      Tax expense computed by applying the U.S. federal income
         tax rate of 35%.....................................................    $ 43,177    $ 45,992    $ 42,407

      Increases (reductions) in taxes resulting from:
         State income tax cost...............................................       1,359       1,293       2,556
         Tight sands gas credit..............................................      (2,586)     (2,896)     (4,344)
         Other...............................................................        (645)       (666)      2,067
                                                                                  -------    --------    --------

      Taxes on Income........................................................    $ 41,305    $ 43,723    $ 42,686
                                                                                 ========    ========    ========
</TABLE>



                                      F-14

<PAGE>



     Deferred tax  liabilities  (assets)  which are recognized for the estimated
future tax effects  attributable  to temporary  differences  are  (thousands  of
dollars):

<TABLE>
<CAPTION>
                                                                                                  December 31,
                                                                                             ---------------------
                                                                                               1996        1995
                                                                                             --------    ---------

      <S>                                                                                    <C>         <C>      
      Excess of book basis over tax basis of plant, property and equipment...............    $ 88,417    $  86,920
      AFUDC equity income tax gross-up pursuant to FAS No. 109...........................           -        1,786
      Other..............................................................................      (2,568)        (408)
                                                                                             --------    ---------
          Deferred tax liabilities.......................................................      85,849       88,298
                                                                                             --------    ---------

      Provisions for rate refunds and contested claims...................................     (19,756)     (20,413)
      Accrued expenses...................................................................      (4,236)      (4,714)
      Other..............................................................................      (2,790)        (232)
                                                                                             --------    ---------
          Deferred tax assets............................................................     (26,782)     (25,359)
                                                                                             --------    ---------

          Deferred income taxes..........................................................    $ 59,067    $  62,939
                                                                                             ========    =========
</TABLE>

7. Benefit Plans

     The Company  participates in the  non-contributory  pension plan of Coastal
(the  "Plan")  which  covers  substantially  all  employees.  The Plan  provides
benefits based on final average monthly compensation and years of service. As of
December  31,  1996,  the  Plan  did not have an  unfunded  accumulated  benefit
obligation.  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.  Colorado made no  contributions to the
Plan for 1996, 1995 or 1994. Assets of the Plan are not segregated or restricted
by  participating  subsidiaries  and pension  obligations for Company  employees
would remain the obligation of the Plan if the Company were to withdraw.

     In 1995, the Company offered an early retirement  incentive  program to all
of its  eligible  employees,  (age 55 before  January 1, 1996 and having five or
more years of  service  before  January  1,  1996),  who were  employed  through
December 31, 1995. All benefits  provided under this program are being funded by
the Plan and did not have a material impact on the Company's  consolidated  cash
flow or financial position.

     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  approximately  $2.5 million for each of the years 1996 and 1995 and
$2.8 million for 1994.

     The Company  provides  certain health care and life insurance  benefits for
retired  employees.  The estimated costs of retiree benefit payments are accrued
during  the  years the  employee  provides  services.  Certain  costs  have been
deferred and were fully amortized as of October 31, 1996.  Effective November 1,
1996,  such  costs  will no longer  be  deferred  as a result  of the  Company's
discontinuing application of FAS 71.



                                      F-15

<PAGE>

     The following tables set forth the accumulated postretirement benefit asset
recognized  in the  Company's  Consolidated  Balance  Sheet for the years  ended
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......................................................................   $  (10.9)    $  (11.3)
           Fully eligible plan participants..............................................          -          (.3)
           Other active plan participants................................................       (3.9)        (6.4)
                                                                                            --------     --------
                                                                                               (14.8)       (18.0)

      Plan assets at fair value..........................................................        5.9          5.9
                                                                                            --------     --------

      Accumulated postretirement benefit obligation in excess of plan assets.............       (8.9)       (12.1)
      Unrecognized net transition obligation.............................................       13.9         15.4
      Unrecognized net gain from past experience different from that assumed.............       (4.0)        (2.5)
                                                                                            --------     --------
      Postretirement benefit asset included in consolidated balance sheet................   $    1.0     $     .8
                                                                                            ========     ========
</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    $     .3    $     .3
         Interest cost on accumulated postretirement benefit obligation......         1.0         1.2         1.2
         Amortization of transition obligation...............................          .9          .9          .9
         Return on assets, net of deferrals..................................         (.4)        (.3)        (.2)
         Deferred regulatory amount..........................................          .6         1.1         1.0
                                                                                 --------    --------    --------
         Net postretirement benefit cost.....................................    $    2.3    $    3.2    $    3.2
                                                                                 ========    ========    ========
</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 3.2% and the net postretirement  health
care cost by  approximately  3.0%. The assumed discount rate used in determining
the accumulated postretirement benefit obligation was 7.50%.

8. Commitments

     The Company and its subsidiaries  had rental expense of approximately  $4.7
million,  $5.0  million and $7.3  million in 1996,  1995 and 1994,  respectively
(excluding  leases  covering  natural  resources).  The aggregate  minimum lease
payments under existing noncapitalized long-term leases are estimated to be $3.3
million, $3.1 million, $3.0 million, $2.9 million and $2.8 million for the years
1997-2001, respectively, and $7.2 million thereafter.



                                      F-16

<PAGE>

     The  Company  has  executed a service  agreement  with WIC,  an  affiliate,
providing  for the  availability  of pipeline  transportation  capacity  through
December 31, 2003. Under the service agreement,  the Company is required to make
minimum  payments on a monthly  basis.  The estimated  amounts of minimum annual
payments are as follows (thousands of dollars):

             1997........................................  $  4,200
             1998........................................     3,700
             1999........................................     3,700
             2000........................................     3,600
             2001........................................     3,700
             Later years.................................     7,400

     The Company  expensed  approximately  $4.7  million  related to the minimum
payments under this agreement in 1996.

     Colorado has executed  precedent  agreements with WIC and with  Trailblazer
Pipeline  Company for 99 thousand  and 10  thousand  dekatherms  per day of firm
transportation  capacity,  respectively.  Both  agreements have a ten-year term.
Colorado has undertaken  these  commitments in order to: 1) provide  current and
future customers of Colorado with direct access to points of delivery from these
pipeline  systems  without the customer  having to contract  separately  for and
administer  contracts on multiple pipeline systems; and 2) to enhance Colorado's
own  operational  reliability  across the portion of its  pipeline  system which
generally parallels the WIC system. Colorado made the appropriate filings at the
FERC to hold this  capacity  in late  March  1996 and  approval  was  granted on
September 11, 1996.

9. Litigation and Regulatory Matters

- Litigation Matters

     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
lawsuit 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  Colorado,  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. Colorado, together with the other pipeline defendant's, has
filed a motion to dismiss.

     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.


                                      F-17

<PAGE>

- Rate Matters

     On January 31, 1996, the FERC issued a "Statement of Policy and Request for
Comments" ("Policy Statement") 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  Statement,  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 Statement, a pipeline must make an initial tariff filing with the FERC to
indicate that it intends to contract for services  under this Policy  Statement,
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.

     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 Statement.  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,  CIGFS 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 CIGFS 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 CIGFS effective October 1, 1996.

     Certain of the above regulatory  matters and other regulatory issues remain
unresolved  among the Company,  its  customers,  its 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.

10. Extraordinary Item

     The Company is subject to the regulations and accounting  procedures of the
FERC and has 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  is no longer  consistent  with the form of  regulation
contemplated by FAS 71. Accordingly, effective November 1, 1996, the Company has
ceased to apply the provision of FAS 71 to its transactions and balances,  which
accounting change has been implemented pursuant to the guidance contained in FAS
101, "Regulated Enterprises - Accounting for the


                                      F-18

<PAGE>

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 the Company now
operates.

     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 $6.3 million,  net of related  income
taxes of $(1.5) million,  and is shown as an extraordinary item in the Statement
of  Consolidated  Earnings.  The charge to earnings was noncash and will have no
direct effect on the Company's ability to include the underlying  deferred items
in future rates proceedings or on its ability to collect the rates set thereby.

11. Quarterly Results of Operations (Unaudited)

     The results of operations by quarter for the years ended  December 31, 1996
and 1995 were (thousands of dollars):

<TABLE>
<CAPTION>
                                                                                 1996 Quarter Ended
                                                                  ----------------------------------------------
                                                                  March 31,     June 30,   Sept. 30,    Dec. 31,
                                                                  ---------     --------   ---------    --------

      <S>                                                         <C>         <C>         <C>          <C>      
      Revenues.................................................   $ 116,575   $   92,427  $  106,392   $ 110,070
      Cost of gas sold.........................................      18,375       10,785      20,736      30,335
                                                                  ---------    ---------  ----------   ---------
         Revenues less cost of gas sold........................      98,200       81,642      85,656      79,735
      Other costs and expenses.................................      66,235       63,233      68,297      65,410
                                                                  ---------    ---------  ----------   ---------
      Earnings before extraordinary item.......................      31,965       18,409      17,359      14,325
      Extraordinary item-loss from discontinuance of
         FAS 71................................................           -            -           -      (6,301)
                                                                  ---------    ---------  ----------   ---------
         Net earnings..........................................   $  31,965   $   18,409  $   17,359   $   8,024
                                                                  =========   ==========  ==========   =========
</TABLE>


<TABLE>
<CAPTION>
                                                                                 1995 Quarter Ended
                                                                  ----------------------------------------------
                                                                  March 31,     June 30,   Sept. 30,    Dec. 31,
                                                                  ---------     --------   ---------    --------

      <S>                                                         <C>         <C>         <C>          <C>      
      Revenues.................................................   $ 106,984   $   92,944  $   92,557   $ 104,046
      Cost of gas sold.........................................      10,975        9,576       9,652      13,928
                                                                  ---------    ---------  ----------   ---------
         Revenues less cost of gas sold........................      96,009       83,368      82,905      90,118
      Other costs and expenses.................................      67,748       66,648      64,482      65,806
                                                                  ---------    ---------  ----------   ---------
         Net earnings..........................................   $  28,261   $   16,720  $   18,423   $  24,312
                                                                  =========   ==========  ==========   =========
</TABLE>

12. Segment Reporting

     Natural gas system  operations and gas and oil  exploration  and production
are the two segments of the Company's operations.

     Natural gas system operations involve the production,  purchase, gathering,
storage,  transportation and sale of natural gas,  principally to and for public
utilities,  industrial customers,  other pipelines,  and other gas customers, as
well as the operation of natural gas liquids extraction plants.

     Gas and oil exploration  and production  operations  involve  primarily the
development and production of natural gas, crude oil, condensate and natural gas
liquids.  Sales are made to affiliated companies,  industrial users,  interstate
pipelines  and  distribution  companies  in  the  Rocky  Mountain,  Central  and
Southwest United States.

     Operating revenues by segment include both sales to unaffiliated customers,
as  reported  in  the  Company's   statement  of  consolidated   earnings,   and
intersegment  sales,  which are accounted for on the basis of contract,  current
market, or internally  established  transfer prices.  The intersegment sales are
from the exploration and production segment to the natural gas segment.


                                      F-19

<PAGE>

     Operating profit is total revenues less interest income from affiliates and
operating expenses.  Operating expenses exclude income taxes,  corporate general
and administrative expenses and interest.

     Identifiable  assets  by  segment  are  those  assets  that are used in the
Company's operations in each segment.

     The Company's  operating revenues and operating profit (loss) 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 below (thousands of dollars):

<TABLE>
<CAPTION>
                                                                                  Operating
                                                               Operating           Profit          Identifiable
                                                               Revenues            (Loss)             Assets
                                                            --------------     --------------     --------------

<S>                                                         <C>                <C>                <C>           
1996
----

   Natural gas............................................  $      400,423     $      131,645     $      880,807
   Exploration and production.............................          20,273              3,001             28,115
   Adjustments and eliminations...........................          (8,219)                 -                  -
                                                            --------------     --------------     --------------
      Segment totals......................................         412,477            134,646            908,922
   Other income-net.......................................          12,987             12,988                  -
   Corporate general and administrative expenses..........               -             (5,410)                 -
   Interest...............................................               -            (18,861)                 -
   Income taxes...........................................               -            (41,305)                 -
   Extraordinary item.....................................               -             (6,301)                 -
                                                            --------------     --------------     --------------
      Consolidated Totals.................................  $      425,464     $       75,757     $      908,922
                                                            ==============     ==============     ==============

1995
----

   Natural gas............................................  $      374,273     $      143,598     $      823,013
   Exploration and production.............................          13,064             (3,524)            38,435
   Adjustments and eliminations...........................          (5,137)                 -                  -
                                                            --------------     --------------     --------------
      Segment totals......................................         382,200            140,074            861,448
   Other income-net.......................................          14,331             14,331                  -
   Corporate general and administrative expenses..........               -             (4,874)                 -
   Interest...............................................               -            (18,092)                 -
   Income taxes...........................................               -            (43,723)                 -
                                                            --------------     --------------     --------------
      Consolidated Totals.................................  $      396,531     $       87,716     $      861,448
                                                            ==============     ==============     ==============

1994
----

   Natural gas............................................  $      368,604     $      132,355     $      914,195
   Exploration and production.............................          26,198              4,086             47,916
   Adjustments and eliminations...........................          (8,249)                 -                  -
                                                            --------------     --------------     --------------
      Segment totals......................................         386,553            136,441            962,111
   Other income-net.......................................           8,735              8,735                  -
   Corporate general and administrative expenses..........               -             (5,051)                 -
   Interest...............................................               -            (18,932)                 -
   Income taxes...........................................               -            (42,686)                 -
                                                            --------------     --------------     --------------
      Consolidated Totals.................................  $      395,288     $       78,507     $      962,111
                                                            ==============     ==============     ==============
</TABLE>



                                      F-20

<PAGE>

     Capital  expenditures and depreciation,  depletion and amortization expense
by segment for the years ended December 31, 1996, 1995 and 1994, were (thousands
of dollars):

<TABLE>
<CAPTION>
                                                                                          Depreciation,
                                                                                          Depletion and
                                                                        Capital           Amortization
              Segment                                                Expenditures            Expense
              -------                                                ------------         -------------

      <S>                                                              <C>                  <C>      
      1996
      ----

      Natural gas.................................................     $   90,392           $  30,851
      Exploration and production..................................          5,205              11,450

      1995
      ----

      Natural gas.................................................     $   55,017           $  29,182
      Exploration and production..................................          3,699               9,855

      1994
      ----

      Natural gas.................................................     $   45,218           $  26,980
      Exploration and production..................................          7,045              14,675
</TABLE>

     Revenues  from  sales  and  transportation  of  natural  gas to  individual
customers amounting to 10% or more of the Company's  consolidated  revenues were
as indicated below:

<TABLE>
<CAPTION>
                                                                                     Year Ended December 31,
                                                                               ----------------------------------
                                                                                  1996        1995         1994
                                                                               ----------   ---------   ---------

      <S>                                                                      <C>          <C>         <C>      
      Public Service Company of Colorado

         Amount (thousands of dollars).......................................  $  167,222   $ 160,523   $ 198,002
                                                                               ==========   =========   =========

         Percent.............................................................         39%         40%         50%
                                                                               ==========   =========   =========
</TABLE>

     Revenues from sales and  transportation  of natural gas to any other single
customer did not amount to 10% or more of the  Company's  consolidated  revenues
for the years ended December 31, 1996,  1995 and 1994. The Company does not have
any foreign operations.

     Gas sales are made  primarily to public  utilities  which resell the gas to
residential,  commercial and  industrial  customers and to end-users in Colorado
and southeastern Wyoming. Deliveries from the Company's field system are made to
markets in the Texas Panhandle region.  Transportation services are provided for
brokers, producers, marketers, distributors,  end-users and other pipelines. The
Company extends credit for sales and transportation services provided to certain
qualifying companies.



                                      F-21

<PAGE>

13. Transactions with Affiliates

     The  Statement  of  Consolidated  Earnings  includes  the  following  major
transactions with affiliates (thousands of dollars):

<TABLE>
<CAPTION>
                                                           1996                  1995                  1994
                                                    ------------------    ------------------    -----------------
                                                               Percent               Percent              Percent
                                                    Amount    of Total    Amount    of Total    Amount   of Total
                                                    ------    --------    ------    --------    ------   --------

<S>                                                 <C>          <C>      <C>          <C>      <C>         <C>  
Revenues
   Gathering and Transportation -
      Coastal Chem, Inc..........................   $  2,281      1.2%    $  2,005      1.0%    $  2,522     1.3%
      Coastal Gas Marketing Company..............      8,268      4.2        9,257      4.6       10,582     5.4
      Coastal Oil & Gas Corporation .............      2,521      1.3        2,439      1.2        6,753     3.5
      CIG Resources Company<F1>..................      3,440      1.8            -        -            -       -

   Gas Sales -
      Coastal Gas Marketing Company..............   $  7,295      4.5%    $  6,348      5.1%    $  9,607     7.0%
      CIG Resources Company<F2>..................      9,429      5.9          323      0.3            -       -

   Extracted Products and Gas Processing -
      Coastal Refining & Marketing, Inc..........   $ 24,791     92.5%    $ 26,047     97.6%    $ 28,991    96.0%
      Coastal States Trading, Inc.<F3>...........          -        -          351      1.3          923     3.1
      Coastal Field Services Company<F4>.........      1,461      5.4            -        -            -       -

   Incidental Gasoline, Oil and Condensate
   Sales -
      Coastal Refining & Marketing, Inc..........   $  1,473     29.1%    $  1,348     35.0%    $    857    23.5%
      Coastal States Trading, Inc................      1,294     25.5        1,342     34.8        1,185    32.5

   Contract Storage -
      Coastal Gas Marketing Company<F5>..........   $      -        -%    $      -        -%    $    456     4.6%

   Natural Gas Production -
      Coastal Gas Marketing Company..............   $  6,878     33.9%    $  5,671     43.4%    $  9,100    34.7%
      Coastal States Trading, Inc................        268      1.3          241      1.8           16     0.1

   Miscellaneous -
      Coastal Refining & Marketing, Inc..........   $    210     10.6%    $    285     11.2%    $    194    10.3%

Costs and Expenses
   Gas Purchases -
      Coastal Gas Marketing Company..............   $    258       .2%    $  1,345      1.9%    $  1,582     1.7%
      Coastal Limited Ventures, Inc.<F6>.........        290       .2            -        -          205      .2
      Coastal Oil & Gas Corporation..............      6,077      5.8        3,156      4.5        4,505     4.9

   Gathering, Transportation and Compression -
      WIC........................................   $  4,778     67.3%    $  4,425     55.6%    $  4,934    55.3%
      ANR Pipeline Company<F7>...................        766     10.8          178      2.2            -       -

<FN>

    <F1>  The 1995 amount was immaterial and 1994 had no activity.
    <F2>  1994 had no activity.
    <F3>  The 1996 amount was immaterial.
    <F4>  1995 and 1994 had no activity.
    <F5>  The 1996 and 1995 amounts were immaterial.
    <F6>  The 1995 amount was immaterial.
    <F7>  The 1994 amount was immaterial.
</FN>
</TABLE>

                                      F-22

<PAGE>

     Services provided by the Company at cost for affiliated companies were $7.0
million  for 1996,  $5.9  million for 1995 and $8.3  million for 1994.  Services
provided by  affiliated  companies for the Company at cost were $8.2 million for
1996, $7.6 million for 1995 and $7.7 million for 1994. The services  provided by
the Company to affiliates,  and by affiliates to the Company,  primarily reflect
the  allocation of costs  relating to the  sharing/operating  of facilities  and
general and  administrative  functions.  Such costs are allocated  using a three
factor  formula  consisting of revenue,  property and payroll,  or other methods
which have been applied on a reasonable and consistent basis.

     In 1989, the Company entered into two separate  five-year lease  agreements
with ANR  Western  Storage  Company,  an  affiliate,  for the  rental of certain
pipeline facilities. Under the conditions of the lease agreements, the terms are
automatically  extended  at  the  option  of  the  Company.  Rental  expense  of
approximately  $.9 million for 1996,  $1.3  million in 1995 and $1.4  million in
1994 was recorded in  conjunction  with the terms of the lease  agreements.  The
lease was  terminated in 1996 and the related  facilities  were purchased by the
Company.

     The  Company  participates  in a  program  which  matches  short-term  cash
excesses and  requirements of  participating  affiliates,  thus minimizing total
borrowings from outside sources.  At December 31, 1996, the Company had advanced
$139.4 million to associated companies at a market rate of interest. Such amount
is repayable on demand.



                                      F-23

<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 system reserves and the related
standardized   measure  of  discounted  future  net  cash  flows  are  presented
separately  for natural gas  operations.  All reserves are located in the United
States.  Most of the  Company-owned  gas  reserves are  dedicated to  Colorado's
system.

<TABLE>
<CAPTION>
Estimated Quantities of Proved Reserves
                                                             Natural Gas           Exploration
      Company-Owned Reserves                                   System            and Production
      ----------------------                                 -----------   --------------------------
                                                              Developed    Developed      Undeveloped     Total
                                                             -----------   ---------      -----------     -----

      <S>                                                      <C>             <C>          <C>           <C>
      Natural Gas (MMcf):
      -----------------

           1996.............................................   267,927         74,963       39,803        382,693
           1995.............................................   302,420         66,282        7,090        375,792
           1994.............................................   334,597         76,917        2,598        414,112

      Oil, Condensate and Natural Gas Liquids (000 barrels):
      -----------------------------------------------------

           1996.............................................       391            427          282          1,100
           1995.............................................       126            323           36            485
           1994.............................................        11            409            3            423
</TABLE>

     Changes in proved reserves since the end of 1993 are shown in the following
table:

<TABLE>
<CAPTION>
                                                           Natural Gas                 Oil, Condensate and NGL
                                                             (MMcf)                         (000 barrels)
                                                     --------------------------       -------------------------
                                                     Natural        Exploration       Natural       Exploration
                                                       Gas              and             Gas             and
Total Proved Reserves                                System         Production        System        Production
---------------------                                -------        ----------        -------       -----------

<S>                                                  <C>             <C>               <C>           <C>
Total, end of 1993..............................     379,795           95,993               7             411
                                                     -------          -------         -------         -------
Production during 1994..........................     (46,288)         (14,758)             (1)            (81)
Extensions and discoveries......................           -            5,304               -              58
Acquisitions....................................           -                -               -               -
Revisions of previous quantity estimates and
 other..........................................       1,090           (7,024)              5              24
                                                     -------          -------         -------         -------
Total, end of 1994..............................     334,597           79,515              11             412
                                                     -------          -------         -------         -------
Production during 1995..........................     (41,638)         (10,703)            (16)            (67)
Extensions and discoveries......................           -            2,749               -              45
Acquisitions....................................           -              522             118               2
Revisions of previous quantity estimates and
 other..........................................       9,461            1,289              13             (33)
                                                     -------          -------         -------         -------
Total, end of 1995..............................     302,420           73,372             126             359
                                                     -------          -------         -------         -------
Production during 1996..........................     (39,405)         (12,304)            (23)           (115)
Extensions and discoveries......................         264           38,714             265             320
Acquisitions....................................           -            1,100               -              10
Sales of reserves in-place......................           -           (1,580)              -             (21)
Revisions of previous quantity estimates and
 other..........................................       4,648           15,464              23             156
                                                     -------          -------         -------         -------
Total, end of 1996..............................     267,927          114,766             391             709
                                                     =======          =======         =======         =======
</TABLE>



                                      F-24

<PAGE>

     Total proved  reserves for the natural gas system  exclude  storage gas and
liquids volumes.  The natural gas system storage gas volumes are 38,842,  39,215
and 39,984 MMcf and storage liquids volumes are approximately  192,000,  138,000
and 172,000 barrels at December 31, 1996, 1995 and 1994,  respectively.  Volumes
are based on  Huddleston's  report and include  estimates  which differ slightly
from actuals.

<TABLE>
<CAPTION>

Capitalized Costs Relating to Exploration and Production Activities
(thousands of dollars)

                                                                                               December 31,
                                                                                         -------------------------
                                                                                            1996          1995
                                                                                         ----------    -----------

Proved and Unproved Properties
------------------------------

<S>                                                                                     <C>            <C>        
Proved Properties...................................................................    $   124,368    $   137,606
Unproved Properties.................................................................            656            461
                                                                                        -----------    -----------
                                                                                            125,024        138,067
Accumulated depreciation, depletion and amortization................................       (101,080)      (104,249)
                                                                                        -----------    -----------
                                                                                        $    23,944    $    33,818
                                                                                        ===========    ===========
</TABLE>

     The Company  follows the  full-cost  method of  accounting  for oil and gas
properties.


<TABLE>
<CAPTION>
Costs Excluded from Amortization
(thousands of dollars)

      The following table summarizes the costs related to unevaluated properties
which are excluded from amounts  subject to  amortization  at December 31, 1996.
The Company regularly  evaluates these costs to determine whether impairment has
occurred.

                                                                            Years Costs Incurred
                                             ---------------------------------------------------------------------
                                                                                                          Prior
                                                 Total         1996           1995          1994         to 1994
                                             -----------    -----------   -----------   -----------    -----------

<S>                                          <C>            <C>           <C>           <C>            <C>        
Property Acquisition......................   $         2    $         2   $         -   $         -    $         -
Exploration...............................            84             65            19             -              -
                                             -----------    -----------   -----------   -----------    -----------
                                             $        86    $        67   $        19   $         -    $         -
                                             ===========    ===========   ===========   ===========    ===========
</TABLE>

<TABLE>
<CAPTION>

Costs Incurred in Oil and Gas Acquisition, Exploration and Development Activities
(thousands of dollars)

                                                                                      Year Ended December 31,
                                                                                 --------------------------------
                                                                                   1996        1995        1994
                                                                                 --------    --------    --------

<S>                                                                              <C>         <C>         <C>     
Property acquisition costs:
      Proved.................................................................    $     51    $    436    $      5
      Unproved...............................................................           2           -           -
Exploration costs............................................................         107          40         323
Development costs............................................................       5,040       3,200       6,717
</TABLE>



                                      F-25

<PAGE>

<TABLE>
<CAPTION>
Results of Operations for Exploration and Production Activities
(thousands of dollars)

                                                                                      Year Ended December 31,
                                                                                 --------------------------------
                                                                                   1996        1995        1994
                                                                                 --------    --------    --------

<S>                                                                              <C>         <C>         <C>     
Revenues:
   Sales.....................................................................    $  1,994    $  2,313    $  4,167
   Transfers.................................................................      17,256      10,799      21,984
                                                                                 --------    --------    --------
      Total..................................................................      19,250      13,112      26,151

Production costs.............................................................      (4,606)     (5,022)     (5,627)
Operating expenses...........................................................      (1,215)     (1,710)     (1,810)
Depreciation, depletion and amortization.....................................     (11,450)     (9,855)    (14,675)
                                                                                 --------    --------    --------
                                                                                    1,979      (3,475)      4,039

Income tax benefit ..........................................................       1,893       4,112       2,930
                                                                                 --------    --------    --------

Results of operations for producing activities (excluding corporate
   overhead and interest costs)..............................................    $  3,872    $    637    $  6,969
                                                                                 ========    ========    ========
</TABLE>

      The average  amortization rate per equivalent Mcf was $0.88 in 1996, $0.89
in 1995 and $0.96 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  at 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.

     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 (thousands of dollars):

<TABLE>
<CAPTION>
                                                               Year Ended December 31,
                                ---------------------------------------------------------------------------------
                                         1996                         1995                        1994
                                ------------------------     -----------------------      -----------------------
                                 Natural     Exploration     Natural     Exploration      Natural     Exploration
                                   Gas           and           Gas           and            Gas           and
                                 System      Production      System      Production       System      Production
                                --------     -----------     -------     ------------     -------     -----------

<S>                            <C>           <C>           <C>           <C>           <C>           <C>        
Future cash inflows..........  $   430,290   $   440,567   $   286,853   $   104,369   $   235,101   $   133,850
Future production and
   development costs.........      (85,619)     (139,864)      (82,282)      (49,586)      (65,388)      (51,623)
Future income tax expenses...     (117,047)      (93,337)      (68,163)       (6,872)      (57,958)      (13,339)
                               -----------   -----------   -----------    ----------    ----------   -----------
Future net cash flows........      227,624       207,366       136,408        47,911       111,755        68,888
10% annual discount for
   estimated timing of cash
   flows.....................      (87,979)      (88,165)      (61,368)      (14,278)      (43,983)      (22,358)
                                -----------   -----------   -----------    ----------    ----------   -----------
Standardized measure of
   discounted future net
   cash flows................  $   139,645   $   119,201   $    75,040   $    33,633   $    67,772   $    46,530
                               ===========   ===========   ===========   ===========   ===========   ===========
</TABLE>



                                      F-26

<PAGE>

     Principal  sources  of change in the  standardized  measure  of  discounted
future net cash flows during each year are as follows (thousands of dollars):

<TABLE>
<CAPTION>
                                                               Year Ended December 31,
                               ----------------------------------------------------------------------------------
                                         1996                         1995                        1994
                               -------------------------   -------------------------    -------------------------
                                 Natural     Exploration     Natural     Exploration      Natural     Exploration
                                   Gas           and           Gas           and            Gas           and
                                 System      Production      System      Production       System      Production
                               -----------   -----------   -----------    ----------    ----------   -----------

<S>                            <C>           <C>           <C>           <C>            <C>          <C>        
Sales and transfers, net of
   production costs..........  $   (44,992)  $   (14,644)  $   (30,580)  $    (7,726)  $   (39,272)  $   (18,115)
Net changes in prices and
   production costs..........       94,990        73,599        45,874       (10,302)      (15,493)      (31,746)
Extensions and discoveries...        3,548        48,073             -         1,149             -         3,597
Acquisitions.................            -         2,169           941           388             -             -
Sales of reserves in-place...            -        (1,668)            -             -             -             -
Development costs incurred
   during the period that
   reduced estimated future
   development costs.........            -           167             -           496             -         3,750
Revisions of previous quantity
   estimates, timing and other      38,935        22,054       (15,449)       (4,573)        1,449       (17,781)
Accretion of discount........        6,680         2,142         7,325         4,497        10,793         8,718
Net change in income taxes...      (34,556)      (46,324)         (843)        3,174        15,489        13,581
                               -----------   -----------   -----------   -----------   -----------   -----------
     Net change..............  $    64,605   $    85,568   $     7,268   $   (12,897)  $   (27,034)  $   (37,996)
                               ===========   ===========   ===========   ===========   ===========   ===========
</TABLE>

     None of the amounts include any value for storage gas and liquids  volumes,
which were approximately 38.8 Bcf and 192 thousand barrels, respectively, at the
end of 1996.  Volumes are based on  Huddleston's  report and  include  estimates
which differ slightly from actuals.



                                      F-27

<PAGE>

                                  EXHIBIT INDEX


Exhibit
Number                                 Document
------        -----------------------------------------------------------------

  (3.1)+      Certificate  of  Incorporation  of  the  Company  (Exhibit  to the
              Company's  Annual  Report on Form 10-K for the  fiscal  year ended
              December 31, 1980).

  (3.2)+      By-laws of  the  Company (Filed as  Module CIGBY-LAWS on March 29,
              1994).

  (3.3)+      Certificate of Amendment of Certification of Incorporation of the
              Company (Exhibit 3.1 to the Company'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 Company will furnish to the  Securities  and
              Exchange Commission any such document on request.

  (10)+       Agreement for Consulting  Services between Colorado Interstate Gas
              Company and Harold Burrow dated January 1, 1996 (Exhibit 10 to the
              Company's  Annual  Report on Form 10-K for the  fiscal  year ended
              December 31, 1995).

  (21)*       Subsidiaries of the Company.

  (23)*       Consent of Deloitte & Touche LLP.

  (24)*       Power of Attorney (included on signature pages herein).

  (27)*       Financial Data Schedule.

----------------------------------

Note:
      +    Indicates documents incorporated by reference from prior filing
           indicated.
      *    Indicates documents filed herewith.