COLORADO INTERSTATE GAS CO, 10-K, 1996-03-29

COLORADO INTERSTATE GAS CO
10-K, 1996-03-29
NATURAL GAS TRANSMISSION

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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K
(Mark One)

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED]

For the fiscal year ended December 31, 1995 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 (I.R.S. Employer
of 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

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

Name of each exchange
Title of each class on which registered
------------------- ---------------------
10% Senior Debentures, due 2005 New York Stock Exchange

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

Title of each class
-------------------
Cumulative Preferred Stock, $100 par value, 5.50% Series

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

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 13, 1996, 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
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<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.................... 1
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.................................................... 6
Other Developments............................................... 6
2. Properties........................................................... 7
3. Legal Proceedings.................................................... 7
4. Submission of Matters to a Vote of Security Holders.................. 7

PART II

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

PART III

10. Directors and Executive Officers of the Registrant................... 9
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

"ANR" means American Natural Resources Company
"ANR Pipeline" means ANR Pipeline Company
"Bcf" means billion cubic feet
"CFS" 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
"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 is more fully described in Item 1,
"Business, Regulations Affecting Gas System - General"
"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, 1995, the Company had 1,072 employees.

The revenues and operating profit of the Company by industry segment for
each of the three years in the period ended December 31, 1995, and the related
identifiable assets as of December 31, 1995, 1994 and 1993, 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 purchases and produces
natural gas and makes sales of such gas at the wellhead principally to local gas
distribution companies for resale. Separately, Colorado contracts to gather,
process, transport and store natural gas owned by third parties.

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 1995, 1994 and 1993 (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 certain 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 pipeline facilities at December 31, 1995 consisted
of 6,381 miles of pipeline and 68 compressor stations with approximately 345,000
installed horsepower. At December 31, 1995, the design peak day delivery
capacity of the transmission system was approximately 2 Bcf per day. The
underground storage facilities have a working capacity of approximately 29 Bcf
and a peak day delivery capacity of approximately 780 MMcf.

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 gas sales contracts
extend through September 30, 1996. Effective October 1, 1993, Colorado formed an
unincorporated Merchant Division to conduct 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.

<PAGE>

Gas sales revenues were $124 million in 1995, compared to $139 million in
1994 and $223 million in 1993. The decreases from 1993 are due largely to the
fact that prior to the mandated restructuring under Order 636, the costs of
providing gathering, storage and transportation services for sales customers
were recovered as part of the total resale rate and were classified as part of
gas sales revenue. Subsequent to restructuring, these costs are now recovered
under separate rates for each service.

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
has "unbundled" these services from its sales services and continues to provide
these services to third parties under individual contracts. Such services are at
negotiated rates that are within minimum and maximum levels approved by the
FERC. Also, pursuant to Order 636, the Company, on September 30, 1993, sold all
of its working gas except for 3.8 Bcf which it retained for operational needs.

Pursuant to an operating agreement with CIG Gas Storage Company, an
affiliate, the Company operates a newly completed 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 1995, 1994 and 1993 were as follows:

Total System Daily Average
Year Deliveries System Deliveries
(Bcf) (MMcf)
---- ------------ -----------------

1995 456 1,248
1994 436 1,195
1993 453 1,241

Gas Gathering and Processing

Colorado provides gathering and processing services on an "unbundled" or
stand-alone basis. The Company contracts for these services under terms which
are negotiated. With respect to gathering, the Company is limited to charging
rates which are between minimum and maximum levels approved by the FERC.
Processing terms are not subject to FERC approval, but Colorado is required to
provide "open access" to its processing facilities.

Colorado has approximately 3,000 miles of gathering lines and
approximately 109,200 horsepower of compression in its gathering operations.
Colorado owns and operates six gas processing plants which recovered
approximately 81 million gallons of liquid hydrocarbons in 1995, compared to 88
million gallons in 1994 and 86 million gallons in 1993, and 4,600 long tons of
sulfur in 1995, compared to 4,300 long tons in 1994 and 4,400 long tons in 1993.
Additionally, in 1995 and 1994, Colorado processed approximately 6 million
gallons of liquid hydrocarbons owned by others compared to 12 million gallons in
1993. These plants, with a total operating capacity of approximately 697 MMcf
daily, recover mainly propane, butanes, natural gasoline, sulfur and other
by-products, which are sold to refineries, chemical plants and other customers.

On October 31, 1995, Colorado filed an application with the FERC seeking
authority to transfer to CFS, a subsidiary of Colorado, certain facilities
presently used for the gathering of natural gas that are subject to certificates
of public convenience and necessity. The filing was protested by some parties
and proceedings are underway at the FERC to resolve the issues that have been
raised by the intervenors. Following receipt of authorizations, Colorado will
transfer the certificated facilities along with certain noncertificated
gathering facilities to CFS.

The Company has also contracted to operate two helium processing
facilities located in eastern Colorado and the western Oklahoma panhandle area.
These helium facilities are joint venture/partnership arrangements which are
partially owned by affiliates of the Company.

<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 interruptible transportation. Additional information on Order 636 is
included under "Regulations Affecting Gas System" included herein.

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, through its unincorporated Merchant Division, continues to make
natural gas sales to a number of customers. In 1996, Colorado has sales contract
commitments of approximately 55,000 MMcf. 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, 1995, 1994, and 1993, as prepared by Huddleston,
Colorado's independent engineers.

1995 1994 1993
---- ---- ----

Owned or controlled by Colorado (Bcf)........ 346 383 433

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.

At December 31, 1995, Colorado maintained under its own account 1.4 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.

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. Effective October 1, 1993, an undivided interest in
the West Panhandle Field leases, related to this 23% of the total net production
not committed to Mesa, was assigned by Colorado to a subsidiary. The reserve
volumes reported represent those retained by Colorado as well as those assigned
to the subsidiary.

<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, had determined that it will not
regulate sales rates. Additionally, the FERC has asserted rate-regulation (but
not certificate regulation) over gathering. Colorado is challenging the FERC's
assertion of rate jurisdiction over gathering, but has agreed in a settlement
that for three years beginning October 1, 1993, Colorado will post in its tariff
the minimum and maximum gathering rates which will be established and approved
by the FERC. Colorado, where required, holds certificates of public convenience
and necessity issued by the FERC covering its jurisdictional facilities,
activities and services.

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 April 8, 1992, the FERC issued Order 636 which required significant
changes in the services provided by interstate natural gas pipelines. The
Company and numerous other parties have sought judicial review of aspects of
Order 636. Oral argument in the case was held before the United States Court of
Appeals for the D.C. Circuit in February 1996. Notwithstanding those appeals,
the Company has successfully complied with the requirements of Order 636.

Colorado's gas sales for resale contracts extend through September 30,
1996. Under Order 636, Colorado's certificate to sell gas for resale allows
sales to be made at negotiated prices and not at prices established by the FERC.
Colorado is also authorized to abandon all sales for resale without prior FERC
approval at such time as the contracts expire. Pursuant to Order 636, Colorado's
gas sales have been "unbundled" at the producer wellhead. Effective October 1,
1993, Colorado formed an unincorporated Merchant Division to conduct 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.

On March 31, 1993, Colorado filed with the FERC under Docket RP93-99 to
increase its rates and such filing became effective subject to refund on October
1, 1993. On November 10, 1994, the FERC approved a settlement offer submitted by
the Company which resolved all of the issues in the proceeding. The Company has
implemented the rates established in the settlement and was required to make
refunds as a result of the approval of the settlement. Such refunds were
distributed in March and April 1995 and totalled approximately $22 million,
inclusive of interest. The Company had fully accrued for these refunds and,
therefore, such refunds did not have an adverse effect on its consolidated
financial position or results of operations.

On October 31, 1995, Colorado filed an application with the FERC seeking
authority to transfer to CFS certain facilities presently used for the gathering
of natural gas that are subject to certificates of public convenience and
necessity. In that filing, Colorado requested that the FERC declare that in the
hands of CFS the transferred facilities will be considered "non-jurisdictional"
gathering facilities. The transferred facilities have a net book value of
approximately $36 million. Colorado has requested that the FERC issue an order
approving the application to be effective on September 30, 1996. The filing was
protested by some parties and proceedings are underway at the FERC to resolve
the issues that have been raised by the intervenors. Following receipt of
authorizations, Colorado will transfer the certificated facilities along with
certain noncertificated gathering facilities to CFS. The facilities to be
transferred comprise most, but not all, of the Company's current gathering
assets. Under current FERC policies, once the facilities are transferred to CFS,
the terms and conditions of service performed by those facilities will cease to
be subject to the

<PAGE>

FERC's general jurisdiction under the NGA, although the FERC has indicated that,
in certain very narrow circumstances, it will assert regulatory jurisdiction
over gathering by affiliates of interstate pipelines such as CFS. The FERC's
policy with respect to treatment of gathering affiliates of interstate pipelines
is on appeal at this time.

On January 31, 1996, the FERC issued a "Statement of Policy and Request
for Comments" in Docket Nos. RM95-6 and RM96-7 with respect to a pipeline's
ability to negotiate and charge rates for individual customers' services which
would not be limited to the "cost-based" rates established by the FERC in
traditional rate making. Under this Policy, a pipeline and a customer will be
allowed to negotiate a contract for service 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"). In
order to implement this Policy, a pipeline must make an initial tariff filing
with the FERC to indicate that it intends to contract for services under this
Policy, and subsequent tariff filings will indicate each instance where the
pipeline has negotiated a rate for service which exceeds the posted maximum
tariff rate. The FERC has also requested comments on whether this "recourse
rate" program should be extended to other terms and conditions of pipeline
transportation services.

Colorado will make a general rate increase filing with the FERC in the
first half of 1996, with such filing expected to become effective, subject to
refund, in late 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. 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 and condensate production volumes of
the Company, including quantities attributable to its natural gas system, for
the three years ended December 31, 1995:

<TABLE>
<CAPTION>
1995 1994 1993
---- ---- ----

<S> <C> <C> <C>
Gas (MMcf)........................................................... 52,341 61,046 56,454
Oil (000 barrels).................................................... 20 8 8
Condensate (000 barrels)............................................. 63 74 49
</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, 1995:

<TABLE>
<CAPTION>
1995 1994 1993
---- ---- ----

<S> <C> <C> <C>
Average sales price (net of production taxes):
Gas - per Mcf................................................... $ 1.04 $ 1.44 $ 1.81
Oil - per barrel................................................ 15.96 14.38 15.18
Condensate - per barrel......................................... 16.05 15.09 15.92

Average production cost per unit (equivalent Mcf).................... $ 0.45 $ 0.37 $ 0.51
</TABLE>

<PAGE>

At December 31, 1995, the gas and oil properties of the Company included
leasehold interests covering 459,411 acres (345,150 net acres), of which 381,455
acres (317,538 net acres) were developed and 77,956 acres (27,612 net acres)
were undeveloped. The net developed acreage is concentrated principally in Texas
(78%), Oklahoma (8%), Wyoming (6%) and Utah (6%). The net undeveloped acreage is
principally in Wyoming (52%), Montana (21%) and Colorado (9%).

The Company drilled 7 gross (2.44 net) gas wells, 19 gross (7.68 net) gas
wells and 22 gross (12.53 net) gas wells in 1995, 1994 and 1993, respectively.
The Company had 986 gross (840.22 net) productive gas wells and 7 gross (6.24
net) productive oil wells as of December 31, 1995.

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.

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
$500,000 on environmental capital projects in 1995 and anticipates annual
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.

There are additional areas of environmental remediation responsibilities
which may fall upon the Company. The states have regulatory programs that
mandate waste clean-up. The Clean Air Act Amendments of 1990 include new
permitting regulations which will result in increased operating expenditures.

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.

OTHER DEVELOPMENTS

In January 1996, the Company announced an open season for interested
parties to request new transportation capacity on its Wind River Lateral. The
lateral has a current capacity of 195,000 Mcf per day and transports natural gas

<PAGE>

from the Wind River Basin, where producers have increased natural gas production
by more than 25 percent since 1992. The expected expansion of the Wind River
Lateral would be sized to meet producer demand based upon the execution of new
transportation agreements.

Colorado has submitted bids and executed precedent agreements with WIC and
with Trailblazer Pipeline Company for 99 thousand and 10 thousand dekatherms per
day of firm transportation capacity, respectively. 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 anticipates making the appropriate filings at the FERC to hold
this capacity in late March, 1996.

Colorado currently has no excess firm pipeline capacity in its Rocky
Mountain states marketing area. In addition, Colorado recently agreed with its
major customer to a long-term transportation and storage contract, subject to
certain conditions.

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 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.

Other lawsuits and other proceedings which have arisen in the ordinary
course of business are pending or threatened against Colorado or its
subsidiaries.

Although no assurances can be given and no determination can be made at
this time as to the outcome of any particular lawsuit or proceeding, the Company
believes there are meritorious defenses to substantially all of the above claims
and that any liability which may finally be determined should not have a
material adverse effect on the Company's consolidated financial position or
results of operations. Additional information regarding legal proceedings is set
forth in Notes 3 and 10 of Notes to Consolidated Financial Statements included
herein.

Item 4. Submission of Matters to a Vote of Security Holders.

None.

<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.

Certain preferred stock resolutions restrict the payment of dividends on
common stock. Under the most restrictive of these provisions, approximately
$413.2 million of retained earnings was available for dividends on the common
stock of the Company at December 31, 1995. Additional information relating to
dividends is set forth under the "Statement of Consolidated Retained Earnings
and Additional Paid-In Capital" included herein.

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, 1994. The
Notes to Consolidated Financial Statements included herein contain information
relating to this data.

<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------------------------------------
1995 1994 1993 1992 1991
----------- ----------- ----------- ----------- ----------

<S> <C> <C> <C> <C> <C>
Operating revenues........................... $ 381,623 $ 385,289 $ 438,014 $ 402,220 $ 375,244
Net earnings................................. 87,716 78,507 73,178 84,075 82,757
Total assets................................. 861,448 962,111 901,627 1,097,178 1,023,586
Long-term debt, excluding current maturities. 179,299 179,225 179,145 195,278 203,404
Mandatory redemption preferred stock......... 556 556 556 556 906
Common stock and other stockholders' equity.. 459,808 411,423 358,047 525,400 503,946
</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.

<PAGE>

PART III

Item 10. Directors and Executive Officers of the Registrant.

The directors and executive officers of Colorado as of March 13, 1996,
were as follows:

Name (Age), Year First Elected Positions and Offices
Director and/or Officer with the Registrant
----------------------------------- ----------------------------
Harold Burrow (81), 1974 Chairman of the Board of
Directors
Jon R. Whitney (51), 1987 and 1974 President, Chief Executive
Officer and Director
Richard L. Anderson (59), 1989 Director
David A. Arledge (51), 1981 Director
James F. Cordes (55), 1986 Vice Chairman of the Board of
Directors
Peter J. King, Jr. (74), 1989 Director
Roger L. Ogden (50), 1989 Director
Paul W. Powers (53), 1989 Director
William B. Tutt, (54), 1989 Director
O. S. Wyatt, Jr. (71), 1972 Director
C. Scott Hobbs (42), 1985 Executive Vice President and
Chief Operating Officer
Daniel F. Collins (54), 1986 Senior Vice President
Donald H. Gullquist (52),1994 Senior Vice President
Rebecca H. Noecker (44), 1988 Senior Vice President, General
Counsel and Director
Austin M. O'Toole (60), 1984 Senior Vice President and
Secretary
Coby C. Hesse (48), 1986 Senior Vice President
Richard G. Smead (49), 1988 Senior Vice President
Donald J. Zinko (51), 1988 Senior Vice President
Steven J. Coffin (40), 1990 Vice President
Ronald A. Gillet (54), 1993 Vice President
Thomas E. Jackson, Jr. (56), 1989 Vice President
Ronald D. Matthews (48), 1994 Vice President and Treasurer
Robert O. Reid (49), 1985 Vice President
William H. Sparger (53), 1992 Vice President
Steven W. Zuckweiler (45), 1991 Vice President
Dan A. Homec (47), 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 1996. 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. Gillet was elected Vice President of Colorado in July 1993. Prior
thereto he served as Vice President of ANR Pipeline Company from 1985 to 1991
and as a Vice President of Coastal States Management Corporation since 1983.

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. Matthews was elected Vice President and Treasurer of Colorado in
October 1994. He was also elected Treasurer of Coastal and Vice President and
Treasurer of ANR Pipeline in September 1994. He has served as Assistant
Treasurer of Coastal since 1983 and as Vice President of Coastal States
Management Corporation, a subsidiary of Coastal, since 1991.

<PAGE>

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.

Mr. Zuckweiler was elected a Vice President of Colorado in August 1991. He
held the position of Director, Transportation and Exchange for the Company from
July 1981 to September 1988, at which time he was elected Assistant Vice
President.

<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, 1995, 1994 and 1993 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").

<TABLE>
Summary Compensation 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 ($)<F2> Bonus ($)<F3> SARs (#)<F4> ($)<F5> $<F6>
- ------------------ ---- ---------- --------- ------------ ------------- --------------

<S> <C> <C> <C> <C> <C> <C>
O. S. Wyatt, Jr., 1995 849,093 300,000 -0- -0- 67,928
Chairman of the Board 1994 849,093 200,000 -0- 67,928
(and CEO through 1993 962,495 90,000 -0- 71,690
October 4, 1995)

David A. Arledge, 1995 622,867 300,000 50,000 85,875 49,829
President, (CEO 1994 553,873 150,000 -0- 44,310
commencing October 5, 1993 473,211 70,000 38,848 42,042
1995) and Director

James F. Cordes, 1995 592,222 135,000 15,000 42,937 47,378
Executive V.P. 1994 592,223 130,000 -0- 47,378
and Director 1993 624,675 50,000 32,094 48,414

James A. King, 1995 343,823 80,000 10,000 -0- 10,141
Executive V.P. 1994 343,823 75,000 -0- 6,877
1993 324,658 28,000 20,000 3,254

Sam F. Willson, Jr. 1995 334,062 75,000 10,000 25,762 26,725
Executive V.P. 1994 334,062 75,000 -0- 26,725
1993 334,062 28,000 15,000 28,600
<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>
Salary amounts for Messrs. Wyatt, Arledge and Cordes for 1993 include directors'
fees paid during this period. Directors' fees for members of management of
Coastal were eliminated in September 1993. There was no salary change for Mr.
Wyatt during 1994 and 1995; the reduced base pay level for 1994 and 1995 was due
to the September 1993 salary reduction (reported in the 1994 Proxy Statement)
being in effect for all of 1994 and 1995.

<F3>
The 1995 bonuses were based on the following factors: the individual's position;
the individual's responsibility; and the individual's ability to impact
Coastal's financial success.

<PAGE>

<F4>
The options do not carry any stock appreciation rights.

<F5>
During 1995, Messrs. Arledge, Cordes and Willson 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.

<F6>
All Other Compensation for 1995 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 $3,000; and Sam F. Willson, Jr. $12,000); and
(ii) certain payments in lieu of Thrift Plan contributions (O. S. Wyatt, Jr.
$55,928; David A. Arledge $37,829; James F. Cordes $35,378; James A. King
$7,141; and Sam F. Willson, Jr., $14,725). 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.
</FN>
</TABLE>

Coastal is negotiating an employment contract with James L. Van Lanen,
Senior Vice President of Coastal responsible for coal operations, at his current
annual rate of salary which will become effective upon the completion of the
previously announced prospective sale of Coastal's coal subsidiaries, and which
will extend through January 26, 2000. In addition, Coastal anticipates an
agreement with Mr. Van Lanen under which he will receive a bonus based on the
proceeds of the sale of such subsidiaries.

Stock Options

The following table sets forth information with respect to stock options
granted on March 1, 1995 for the fiscal year ended December 31, 1995 to the
Named Executive Officers.

<TABLE>
Option/SAR Grants in Last Fiscal Year (1995)

<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 50,000 -0- 28.50 2/28/05 623,153

James F. Cordes 15,000 -0- 28.50 2/28/05 186,946

James A. King 10,000 -0- 28.50 2/28/05 124,631

Sam F. Willson, Jr. 10,000 -0- 28.50 2/28/05 124,631
<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 .4373 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 .2343, calculated using
monthly stock prices for the three years prior to the grant date, (ii) an
interest rate of 7.4%, (iii) a dividend yield of 1.42% and (iv) an option
exercise

<PAGE>

term of ten 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, which is based on certain assumptions, including
the assumption that the option will be held for the full ten-year term prior to
exercise. Studies conducted by Coastal's independent consultants indicate that
options are usually exercised before the end of the full ten-year term.
</FN>
</TABLE>

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, 1995.

<TABLE>
Aggregated Option/SAR Exercises In Last Fiscal Year
And FY-End Option/SAR Values (1995)

<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>
O. S. Wyatt, Jr. -0- -0- -0- / -0- -0- / -0-
David A. Arledge -0- -0- 222,373 / 98,000 2,501,525 / 833,300
James F. Cordes 121,787 1,036,099 16,000 / 49,000 20,000 / 414,850
James A. King -0- -0- 24,000 / 16,000 258,800 / 154,400
Sam F. Willson, Jr. 16,149 64,743 36,000 / 31,000 226,560 / 258,350
<FN>
- ------------------
<F1>
$-based on the market price of $37.19 at December 31, 1995.
</FN>
</TABLE>

COMPENSATION AND EXECUTIVE DEVELOPMENT COMMITTEE
REPORT ON EXECUTIVE COMPENSATION

The following report has been provided by Coastal'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 1995 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

<PAGE>

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.

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 1995 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 1995 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 1995, 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 1995 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 1995 is
a discretionary annual bonus pool. As a result, no formula performance

<PAGE>

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
qualitative performance assessment described above. As a result, actual bonus
payments for 1995 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 7 years of the grant date.

Stock options were granted to the Named Executive Officers in 1995 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.

1995 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).

O. S. Wyatt, Jr.

Mr. Wyatt served as CEO through October 4, 1995 when, at his
recommendation, the Board of Directors elected Mr. Arledge to the CEO position.

Mr. Wyatt received no salary increase in 1995. The Committee took no
action regarding Mr. Wyatt's base salary, in spite of significantly improved
Coastal performance during the year. This lack of any adjustment is not a
reflection of performance; rather, it is based on considering strong input from
the Chairman, who wants to see continued improvement in shareholder returns
before receiving any base salary increase.

Mr. Wyatt's bonus for 1995 performance was $300,000 payable in 1996. This
bonus 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 was below the aggressive Coastal targets.

<PAGE>

The Committee granted no stock options to Mr. Wyatt in 1995 (consistent
with past practices), considering his strongly expressed and longstanding
opinion on this issue. Mr. Wyatt and the Committee considered Mr. Wyatt's
current level of stock ownership in reaching this decision.

David A. Arledge

Mr. Arledge was elected CEO on October 5, 1995. During 1995, his base
annual salary was increased to $625,000.

Mr. Arledge's bonus for 1995 was $300,000 payable in 1996. 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 50,000 shares to Mr. Arledge in
1995 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 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 1995 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.

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

<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.

<TABLE>
Pension Plan 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................... $ 34,133 $ 45,511 $ 56,889 $ 68,266 $ 67,518
150,000................... 41,633 55,511 69,389 83,266 82,518
175,000................... 41,633 55,511 69,389 83,266 82,518
200,000................... 41,633 55,511 69,389 83,266 82,518
225,000................... 41,633 55,511 69,389 83,266 82,518
250,000................... 41,633 55,511 69,389 83,266 82,518
300,000................... 41,633 55,511 69,389 83,266 82,518
400,000................... 41,633 55,511 69,389 83,266 82,518
450,000................... 41,633 55,511 69,389 83,266 82,518
500,000................... 41,633 55,511 69,389 83,266 82,518
<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 1995.

(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, 1995 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, 40 years, $461,297; Mr.
Arledge, 15 years, $56,288; Mr. Cordes, 18 years, $76,087; Mr. King, 3
years $12,141 (not vested); and Mr. Willson, 23 years, $99,715.

(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).

<PAGE>

PERFORMANCE GRAPH - SHAREHOLDER RETURN ON COMMON STOCK

[GRAPH]

<TABLE>
Five-Year Cumulative Values
$100 Invested 12/31/90
Dividends Reinvested

<CAPTION>
DOLLAR VALUE OF $100 INVESTMENT AT DECEMBER 31,
-----------------------------------------------------------------------
1990 1991 1992 1993 1994 1995
---- ---- ---- ---- ---- ----

<S> <C> <C> <C> <C> <C> <C>
Coastal $ 100 $ 78 $ 77 $ 91 $ 85 $ 121
S&P 500 100 130 140 154 156 215
Index<F1><F2> 100 83 75 89 108 97

<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 capitalizations of the peer companies. The peer group is comprised of:
Arkla/NorAm, Burlington Res., Cabot, Columbia, Consolidated Nat. Gas, Eastern
Enterprises, Enron, Enserch, Equitable Res., KN Energy, Mitchell Energy,
National Fuel Gas, PanEnergy, Questar, Seagull Energy, Sonat, Southwestern
Energy, Tenneco, 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 1995 Coastal and/or its subsidiaries sold approximately 13,447,600
gallons of gasoline to Pester Marketing at prevailing market prices totaling
approximately $8,352,300.

<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 13, 1996, 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 13,
1996 is 113,480,598: consisting of 61,056 shares of $1.19 Cumulative Convertible
Preferred Stock, Series A (the "Series A Preferred Stock"); 77,495 shares of
$1.83 Cumulative Convertible Preferred Stock, Series B (the "Series B Preferred
Stock"); 32,663 shares of $5.00 Cumulative Convertible Preferred Stock, Series C
(the "Series C Preferred Stock"); 8,000,000 non-voting shares of $2.125
Cumulative Preferred Stock, Series H; 104,918,785 shares of Common Stock, and
390,599 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.

The following table sets forth information, as of March 13, 1996, 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.

<PAGE>

<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> 38.2
Chairman of the Board
of Coastal
Nine Greenway Plaza
Houston, Texas 77046-0995

Trustee/Custodian under the Common Stock 13,476,985 <F3> 12.8
Thrift Plan, ESOP and Class A Common Stock 71,537 <F3> 17.7
Pension Plan of Coastal
and its subsidiaries
Texas Commerce Bank
National Association
600 Travis, 10th Flr.
Houston, Texas 77002

FMR Corp. Common Stock 7,475,935 7.1
82 Devonshire Street
Boston, Massachusetts 02109

Isabel H. Long Series A Preferred Stock 28,976 47.5
485 S. Parkview Ave.,
Columbus, Ohio 43209-1075

The DeZurik Family Series C Preferred Stock 32,663 <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 826 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>

<PAGE>

The following table sets forth information, as of March 13, 1996,
regarding each of the current directors, including Class I 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. Bissell, Burrow, Chapin and
Katzin are Class I directors whose terms expire in 1996; Messrs. Arledge,
Brundrett, Wooddy and Wyatt are Class II directors whose terms expire in 1997
and Messrs. Cordes, Gates, Johnson and McDade are Class III directors whose
terms expire in 1998.

<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 2,866,558 <F2> 2.7
(71), 1955 Class A Common Stock 154,577 <F2> 38.2

Harold Burrow Vice Chairman of the Board; Common Stock 154,281 <F2>
(81), 1973 Chairman of Colorado and ANR Class A Common Stock 13,603 3.4

David A. Arledge President and Common Stock 234,634
(51), 1988 Chief Executive Officer Class A Common Stock 14,396 3.6

John M. Bissell Chairman and Chief Executive Common Stock 4,576
(65), 1985 Officer of Bissell Inc. Class A Common Stock -0-

George L. Brundrett, Jr. Attorney; Former Senior Vice President Common Stock 4,910
(74), 1973 and General Counsel of Coastal Class A Common Stock 2,290

Roy D. Chapin, Jr. Former Chairman and Common Stock 3,250 <F2>
(80), 1988 Chief Executive Officer Class A Common Stock -0-
of American Motors Corporation

James F. Cordes Executive Vice President; Common Stock 38,131
(55), 1985 President of ANR; Class A Common Stock -0-
President, Natural Gas Group

Roy L. Gates Retired; Ranching and Investments Common Stock 4,095
(67), 1969 Class A Common Stock 2,736

Kenneth O. Johnson Senior Vice President Common Stock 59,128
(75), 1988 Class A Common Stock 9,604 2.4

Jerome S. Katzin Retired Investment Banker Common Stock 41,803
(77), 1983 Class A Common Stock -0-

Thomas R. McDade Senior Partner, Law Firm of McDade Common Stock 500
(63), 1993 & Fogler L.L.P., Houston Class A Common Stock -0-

L. D. Wooddy, Jr. Retired; Former President of Exxon Common Stock 2,000
(69), 1992 Pipeline Company Class A Common Stock -0-

All directors and executive officers as a group Common Stock 3,985,862 <F3> 3.8
(31 persons, including the above) Class A Common Stock 200,522 <F3> 49.5

(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
186,198 shares of Class A Common Stock, which would constitute 47.7%
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 the Coastal ESOP and Thrift Plan, and presently
exercisable stock options held by Messrs. Burrow (14,189 shares of Common
Stock), Arledge (215,049 shares of Common Stock and 14,324 shares of Class A
Common Stock), Cordes (21,000 shares of Common Stock), and Johnson (27,848
shares of Common Stock).

<PAGE>

<F2>
Includes shares owned by the spouse and a son of Mr. Wyatt (266,595 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 677,979 shares of
Common Stock and 14,324 shares of Class A Common Stock; also includes 279,811
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 L.L.P. Prior to forming McDade & Fogler
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, Burrow, Cordes and Wyatt are directors of Colorado and
ANR Pipeline Messrs. Bissell and Chapin are directors of 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, 1995 the Company had advanced
$209.5 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 9 and 13 of Notes to Consolidated Financial
Statements included herein.

(b) Certain business relationships.

None.

(d) Transactions with promoters.

Not applicable.

<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:

Page
----
Independent Auditors' Report................................... F-6
Consolidated Balance Sheet at December 31, 1995 and 1994....... F-7
Statement of Consolidated Earnings for the Years Ended
December 31, 1995, 1994 and 1993.......................... F-9
Statement of Consolidated Retained Earnings and Additional
Paid-In Capital for the Years Ended December 31, 1995,
1994 and 1993............................................ F-9
Statement of Consolidated Cash Flows for the Years Ended
December 31, 1995, 1994 and 1993......................... F-10
Notes to Consolidated Financial Statements.................... F-11
Supplemental Information on Oil and Gas Producing Activities
(Unaudited).............................................. F-25

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.

(21)* Subsidiaries of the Company.

(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,
1995.

<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
March 29, 1996

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: HAROLD BURROW
-------------------------------
Harold Burrow
Chairman of the Board
March 29, 1996

By: JON R. WHITNEY
-------------------------------
Jon R. Whitney
President, Chief Executive Officer and Director
March 29, 1996

By: DAVID A. ARLEDGE
-------------------------------
David A. Arledge
Principal Financial Officer and Director
March 29, 1996

By: DAN A. HOMEC
-------------------------------
Dan A. Homec
Assistant Vice President and
Principal Accounting Officer
March 29, 1996

<PAGE>

By: RICHARD L. ANDERSON
-------------------------------
Richard L. Anderson
Director
March 29, 1996

By: JAMES F. CORDES
-------------------------------
James F. Cordes
Director
March 29, 1996

By: PETER J. KING, JR.
-------------------------------
Peter J. King, Jr.
Director
March 29, 1996

By: REBECCA H. NOECKER
-------------------------------
Rebecca H. Noecker
Director
March 29, 1996

By: ROGER L. OGDEN
-------------------------------
Roger L. Ogden
Director
March 29, 1996

By: PAUL W. POWERS
-------------------------------
Paul W. Powers
Director
March 29, 1996

By: WILLIAM B. TUTT
-------------------------------
William B. Tutt
Director
March 29, 1996

By: O. S. WYATT, JR.
-------------------------------
O. S. Wyatt, Jr.
Director
March 29, 1996

<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, especially natural gas prices 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>
1995 1994 1993
-------- -------- ---------

<S> <C> <C> <C>
Cash flow from operating activities to capital expenditures and debt
service requirements................................................... 147.5% 374.5% 80.0%

Debt to total capitalization........................................... 28.0% 30.3% 33.3%

Times interest earned (before tax)..................................... 8.3 7.4 6.5
</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 1993 through 1995 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 $86.6 million in 1995,
$195.7 million in 1994 and $77.6 million in 1993. The 1995 decrease can be
attributed to increases for working capital requirements partially offset by
increased earnings and changes in deferred income taxes. Liquidity needs were
met in 1995 by internally generated funds.

The Company has adopted a capital expenditure budget of approximately
$83.7 million for 1996, an increase from the capital additions of $58.7 million
in 1995. The anticipated increase in 1996 is the result of a $28.7 million
increase for natural gas projects partially offset by a $3.7 million decrease
for exploration and production projects. Alternatives to finance capital
expenditures and other cash needs are primarily limited by the terms of a
Coastal Natural Gas debt instrument. As of December 31, 1995, the Company and
certain affiliates could incur approximately $765.3 million of additional
indebtedness. For the Company and such affiliates to incur indebtedness for
borrowed money in excess of this amount, $200.0 million of indebtedness under
this agreement would need to be retired.

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, 1995, the Company had advanced
$209.5 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 and reduce take-or-pay
obligations, pursuing innovative marketing strategies and applying strict
cost-cutting measures.

F-1

<PAGE>

maintenance of its pipeline facilities. The Company spent approximately $500,000
on environmental capital projects in 1995 and anticipates annual 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.

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
--------------------
1995 1994
------- -------

<S> <C> <C>
Natural gas.................................................................... $ 6 $ (64)
Exploration and production..................................................... (13) 6
Adjustments and eliminations................................................... 3 5
------- ------
$ (4) $ (53)
======= ======
</TABLE>

Natural Gas

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.

1994 Versus 1993. Revenues from natural gas operations decreased in 1994
due to lower average sales prices of $59 million, the $35 million sale of
storage gas inventory in 1993 pursuant to the implementation of Order 636, an
$11 million decrease resulting from reduced sales volumes, increased
reservations of $17 million and reduced extracted products revenue of $4 million
offset by increased transportation and gathering revenues of $55 million and
increased contract storage revenue of $7 million.

The daily average volumes of natural gas sold were 229 MMcf, 259 MMcf and
272 MMcf for 1995, 1994 and 1993, respectively. However, over the remaining life
of Colorado's current gas sales contracts (most of which extend through
September 30, 1996), it is expected that customers will reduce their contractual
sales entitlement pursuant to

F-2

<PAGE>

the provisions of Order 636. Transportation volumes increased by 5% in 1995 over
the 1994 level and the 1996 transportation volumes are estimated to be
approximately the same as 1995.

Exploration and Production

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.

1994 Versus 1993. Revenues from exploration and production increased in
1994 as increases from natural gas volumes of $9 million and other increases of
$2 million were partially offset by decreased natural gas sales prices of $5
million.

Other Income - Net

The increases in 1995 and 1994 primarily reflect changes in interest
income resulting from loans to affiliated companies.

Cost of Gas Sold

1995 Versus 1994. The decrease is due primarily to reduced average
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.

1994 Versus 1993. The decrease is due primarily to reduced average gas
purchase rates of $24 million, reduced purchase volumes of $9 million, decreased
gas used costs of $19 million, decreased transportation, gathering and exchange
gas costs of $15 million and storage gas costs associated with the 1993 sale of
storage gas inventory pursuant to Order 636, net of injection/withdrawals in the
amount of $11 million, partially offset by increases of $3 million.

Operation and Maintenance

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 decreases of $1 million.

1994 Versus 1993. Operation and maintenance expenses increased in 1994 due
primarily to increased gas used in operations of $19 million partially offset by
decreased gas and gas liquids handling of $3 million, decreased production taxes
of $3 million and other decreases of $2 million.

Depreciation, Depletion and Amortization

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.

1994 Versus 1993. The increase is due primarily to a $5 million increase
resulting from increased production volumes in the exploration and production
segment and a $1 million increase as a result of increased depreciable plant in
the natural gas segment partially offset by a $1 million decrease in the
exploration and production segment due to a lower depreciation, depletion and
amortization rate.

F-3

<PAGE>

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
-------------------
1995 1994
------- ------

<S> <C> <C>
Natural gas.................................................................... $ 11 $ 5
Exploration and production..................................................... (7) 2
------- ------
$ 4 $ 7
======= ======
</TABLE>

Natural Gas

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.

1994 Versus 1993. The natural gas segment's operating profit increase in
1994 is due to decreased gas related costs of $75 million and an increase in
other income of $5 million partially offset by decreased operating revenues of
$64 million and increased operation and maintenance expenses of $11 million.

Exploration and Production

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.

1994 Versus 1993. The exploration and production segment's operating
profit increase in 1994 is due to increased revenues of $6 million, partially
offset by a $4 million increase in depreciation, depletion and amortization.

Interest Expense

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

1994 Versus 1993. The decrease in 1994 is due to lower average debt
outstanding resulting in a decrease of $2 million partially offset by a $1
million increase in other financial expenses.

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 1995, 33% in 1994 and 32% in 1993.

F-4

<PAGE>

Recent Pronouncement of the FASB

The FASB has issued Statement of Financial Accounting Standards No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
Be Disposed Of" ("FAS 121"), to be effective in 1996. The provisions of FAS 121
require the Company to review long-lived assets and certain identifiable
intangibles for impairment whenever events or changes in circumstances indicate
that the carrying amount of an asset may not be recoverable. FAS 121 also
requires that a rate-regulated enterprise recognize an impairment for the amount
of costs that a regulator excludes from the enterprise's allowable costs. If it
is determined that an impairment has occurred, the amount of the impairment
should be charged to earnings. The application of the new standard is not
expected to have a material effect on the Company's consolidated financial
position or results of operations in 1996.

F-5

<PAGE>

INDEPENDENT AUDITORS' REPORT

Board of Directors and Stockholders
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, 1995 and 1994, 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, 1995. 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, 1995 and 1994, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1995 in conformity with generally accepted accounting principles.

DELOITTE & TOUCHE LLP

Denver, Colorado
February 1, 1996

F-6

<PAGE>

<TABLE>
COLORADO INTERSTATE GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)

<CAPTION>
December 31,
---------------------------
ASSETS 1995 1994
------------ ------------

<S> <C> <C>
Plant, Property and Equipment, at cost:
Gas pipeline................................................................... $ 1,061,497 $ 1,016,188
Gas and oil properties, at full-cost........................................... 138,067 144,442
------------ ------------
1,199,564 1,160,630

Accumulated depreciation, depletion and amortization........................... 658,327 635,300
------------ ------------
541,237 525,330
------------ ------------

Current Assets:
Cash........................................................................... 883 372
Receivables.................................................................... 44,518 118,353
Receivables from affiliates.................................................... 221,784 246,609
Inventories.................................................................... 9,494 9,154
Prepaid expenses............................................................... 280 628
Current portion of deferred income taxes....................................... 25,359 43,760
------------ ------------
302,318 418,876
------------ ------------

Other Assets:
Other deferred charges......................................................... 17,893 17,905
------------ ------------

$ 861,448 $ 962,111
============ ============
</TABLE>

See Notes to Consolidated Financial Statements.

F-7

<PAGE>

<TABLE>
COLORADO INTERSTATE GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)

<CAPTION>
December 31,
---------------------------
STOCKHOLDERS' EQUITY AND LIABILITIES 1995 1994
------------ ------------

<S> <C> <C>
Common Stock and Other Stockholders' 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..................................................... 19,035 19,035
Retained earnings.............................................................. 413,212 364,827
------------ ------------
459,808 411,423
------------ ------------

Mandatory Redemption Preferred Stock, $100 par value, authorized 550,000 shares,
outstanding 5,560 shares:
5.50% Series................................................................ 556 556
------------ ------------

Debt:
Long-term debt................................................................. 179,299 179,225
------------ ------------

Current Liabilities:
Accounts payable and accrued expenses.......................................... 115,599 248,287
Accounts payable to affiliates................................................. 11,352 14,389
Taxes on income................................................................ 1,594 19,013
------------ ------------
128,545 281,689
------------ ------------

Deferred Credits:
Deferred income taxes.......................................................... 88,298 84,576
Other.......................................................................... 4,942 4,642
------------ ------------
93,240 89,218
------------ ------------

$ 861,448 $ 962,111
============ ============
</TABLE>

See Notes to Consolidated Financial Statements.

F-8

<PAGE>

<TABLE>
COLORADO INTERSTATE GAS COMPANY AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED EARNINGS
(Thousands of Dollars)

<CAPTION>
Year Ended December 31,
----------------------------------
1995 1994 1993
---------- ---------- ---------
<S> <C> <C> <C>
Revenues:
Operating revenues:
Nonaffiliates....................................................... $ 338,524 $ 333,113 $ 376,937
Affiliates.......................................................... 43,099 52,176 61,077
---------- ---------- ---------
381,623 385,289 438,014
Other income-net....................................................... 14,331 8,735 7,318
---------- ---------- ---------
395,954 394,024 445,332
---------- ---------- ---------
Costs and Expenses:
Cost of gas sold:
Nonaffiliates....................................................... 39,540 46,729 119,759
Affiliates.......................................................... 4,591 6,292 8,104
---------- ---------- ---------
44,131 53,021 127,863
Operation and maintenance.............................................. 163,255 159,223 148,351
Depreciation, depletion and amortization............................... 39,037 41,655 36,345
Interest expense....................................................... 18,092 18,932 20,426
Taxes on income........................................................ 43,723 42,686 39,169
---------- ---------- ---------
308,238 315,517 372,154
---------- ---------- ---------

Net Earnings.............................................................. $ 87,716 $ 78,507 $ 73,178
========== ========== =========
</TABLE>

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

<CAPTION>
Year Ended December 31,
----------------------------------
1995 1994 1993
---------- ---------- ---------
<S> <C> <C> <C>
Retained Earnings:
Beginning balance......................................................... $ 364,827 $ 311,451 $ 478,804
Net earnings........................................................... 87,716 78,507 73,178

Less dividends:
Preferred stock:
5.50% Series..................................................... 31 31 31
Common stock........................................................ 39,300 25,100 240,500
---------- ---------- ---------
39,331 25,131 240,531
---------- ---------- ---------

Ending balance............................................................ $ 413,212 $ 364,827 $ 311,451
========== ========== =========

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

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

See Notes to Consolidated Financial Statements.

F-9

<PAGE>

<TABLE>
COLORADO INTERSTATE GAS COMPANY AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CASH FLOWS
(Thousands of Dollars)

<CAPTION>
Year Ended December 31,
----------------------------------
1995 1994 1993
---------- ---------- ---------
<S> <C> <C> <C>
Net Cash Flow From Operating Activities:
Net earnings........................................................... $ 87,716 $ 78,507 $ 73,178
Add (subtract) items not requiring (providing) cash:
Depreciation, depletion and amortization............................ 39,037 41,655 36,345
Deferred income taxes............................................... 21,602 (17,002) 9,840
Producer contract reformation cost recoveries....................... 140 3,056 1,245
Other............................................................... 3,821 8,511 (11,043)
Working capital and other changes, excluding changes relating to cash and
non-operating activities:
Accounts receivable................................................. 73,835 54,434 (49,639)
Receivables from affiliates......................................... 13,571 14,821 (8,985)
Inventories......................................................... (340) 391 (986)
Prepaid expenses.................................................... 348 351 35,052
Accounts payable and accrued expenses............................... (132,688) 14,485 (8,354)
Accounts payable to affiliates...................................... (3,029) (21,203) 11,673
Taxes on income..................................................... (17,419) 17,738 (10,713)
---------- ---------- ---------

86,594 195,744 77,613
---------- ---------- ---------

Cash Flow from Investing Activities:
Purchases of plant, property and equipment............................. (58,716) (52,263) (72,433)
Proceeds from sale of plant, property and equipment.................... 1,756 1,187 1,331
Investments - other.................................................... (1,341) 1,226 (488)
Net (increase) decrease in notes receivable from associated
companies............................................................. 11,254 (113,250) 249,690
Gas supply prepayments and settlements................................. (12) (28) (7,121)
Recovery of gas supply prepayments..................................... 314 375 9,005
---------- ---------- ---------

(46,745) (162,753) 179,984
----------- ----------- ---------

Cash Flow from Financing Activities:
Premium paid on reacquisition of debt.................................. - - (166)
Payments to retire long-term debt...................................... - - (24,400)
Dividends paid......................................................... (39,338) (33,323) (232,336)
---------- ----------- ---------

(39,338) (33,323) (256,902)
---------- ----------- ---------

Net Increase (Decrease) in Cash........................................... 511 (332) 695

Cash at Beginning of Year................................................. 372 704 9
---------- ---------- ---------

Cash at End of Year....................................................... $ 883 $ 372 $ 704
========== ========== =========
</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 subject to the regulations and accounting procedures of the
FERC. Colorado meets the criteria and, accordingly, follows 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 public
utilities 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. Although the accounting methods for companies
subject to rate regulation may differ from those used by non-regulated
companies, the accounting methods prescribed by the regulatory authority conform
to the generally accepted accounting principle of matching costs with the
revenue to which they apply.

Transactions which the Company has recorded differently than a
non-regulated entity include the following: the Company (i) has capitalized the
cost of equity funds used during construction, and, (ii) has deferred purchase
gas costs, contract reformation costs, postemployment/postretirement benefit
costs and income tax reductions related to changes in federal income tax rates.
These items are being, or are anticipated to be, recovered or refunded in rates
chargeable to customers.

The Company has applied FAS 71 and evaluates the applicability of
regulatory accounting and the recoverability of these assets through rate or
other contractual mechanisms on an ongoing basis. If FAS 71 accounting
principles should no longer be applicable to the Company's operations, an amount
would be charged to earnings as an extraordinary item. At December 31, 1995,
this amount was approximately $5.0 million, net of income taxes. The Company
does not expect that its cash flows would be affected by discontinuing
application of FAS 71. Any potential charge would be noncash and would have no
direct effect on the Company's ability to include the underlying deferred items
in future rate proceedings or on its ability to collect the rates set thereby.

- - 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 $19.3 million, $17.5 million and $20.3 million in
1995, 1994 and 1993, respectively. Cash payments for income taxes amounted to
$39.5 million, $41.9 million and $40.5 million in 1995, 1994 and 1993,
respectively.

F-11

<PAGE>

- - Inventories

Materials and supplies inventories are carried principally at average
cost. Gas stored underground is carried at last-in, first-out cost ("LIFO"). The
excess of replacement cost over the carrying value of gas in underground storage
carried by the LIFO method, which is classified as Plant, Property and
Equipment, was $36.5 million and $31.2 million at December 31, 1995 and 1994,
respectively.

- - 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 $.9 million, $1.9
million and $1.2 million in 1995, 1994 and 1993, respectively. All costs
incurred in the acquisition, exploration and development of gas and oil
properties, including unproductive wells, are capitalized under the full-cost
method of accounting. Such costs include the costs of all unproved properties
but do not include internal general and administrative costs directly related to
acquisition, exploration and development activities. These amounts are expensed
as incurred.

The Company generally provides for depreciation on a straight-line basis,
although the unit-of-production method is used for depreciation, depletion and
amortization of certain natural gas properties. The depreciation rates for
production and gathering, products extraction, storage, and transmission plant
are 1.55 percent, 3.85 percent, 2.90 percent, and 2.60 percent, 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 equivalent unit of a
thousand cubic feet of gas production for oil and gas operations was $.89 for
the year 1995, $.96 for the year 1994 and $1.00 for the year 1993. 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 FASB has issued FAS 121 to be effective in 1996. The provisions of FAS
121 require the Company to review long-lived assets and certain identifiable
intangibles for impairment whenever events or changes in circumstances indicate
that the carrying amount of an asset may not be recoverable. FAS 121 also
requires that a rate-regulated enterprise recognize an impairment for the amount
of costs that a regulator excludes from the enterprise's allowable costs. If it
is determined that an impairment has occurred, the amount of the impairment
should be charged to earnings. The application of the new standard is not
expected to have a material effect on the Company's consolidated financial
position or results of operations in 1996.

- - 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.

F-12

<PAGE>

- - 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.

- - 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 results of operations or
financial position.

2. Long-Term Debt

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

1995 1994
--------- ---------

10% Senior Debentures, due 2005............... $ 179,299 $ 179,225
========= =========

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

Alternatives to finance capital expenditures and other cash needs are
primarily limited by the terms of a Coastal Natural Gas debt instrument. As of
December 31, 1995, the Company and certain affiliates could incur approximately
$765.3 million of additional indebtedness. For the Company and such affiliates
to incur indebtedness for borrowed money in excess of this amount, $200.0
million of indebtedness under this agreement would need to be retired.

3. Take-or-Pay Obligations

The Consolidated Balance Sheet includes assets of $4.9 million and $5.7
million at December 31, 1995 and 1994, respectively, relating to prepayments for
gas under gas purchase contracts with producers and settlement payment amounts
relative to the restructuring of gas purchase contracts as negotiated with
producers. As a result of the implementation of Order 636 by the Company on
October 1, 1993 (see Note 10 of Notes to Consolidated Financial Statements), gas
sales are made at negotiated prices and are not subject to regulatory price
controls. This does not affect the recoverability or the results of pending
take-or-pay litigation or any take-or-pay or contractual reformation settlements
that the Company may achieve with respect to periods before October 1, 1993. A
portion of the costs associated with take-or-pay incurred prior to October 1,
1993, may continue to be recovered pursuant to FERC's Order No. 528.

A few gas producers have instituted litigation arising out of take-or-pay
claims against the Company. In the Company's experience, producers' claims are
generally vastly overstated and do not consider all adjustments provided for in
the contract or allowed by law. The Company has resolved the majority of the
exposure with its suppliers for approximately 11% of the amounts claimed. At
December 31, 1995, the Company estimated that unresolved asserted and unasserted
producers' claims amounted to approximately $17.8 million. The remaining
disputes will be settled where possible and litigated if settlement is not
possible.

At December 31, 1995, the Company was committed to make future purchases
under certain take-or-pay contracts with fixed, minimum or escalating price
provisions. Based on contracts in effect at that date, and before considering
reductions provided in the contracts or applicable law, such commitments are
estimated to be $.7 million, $.7 million, $.6 million, $.6 million and $.5
million for the years 1996-2000, respectively, and $2.3 million thereafter. Such
commitments have not been adjusted for all amounts which may be assigned or
released, or for the results of future litigation or negotiation with producers.

The Company has made provisions, which it believes are adequate, for
payments to producers that may be required for settlement of take-or-pay claims
and restructuring of future contractual commitments. In determining the net loss
relating to such provisions, the Company has also made accruals for the
estimated portion of such payments which

F-13

<PAGE>

would be recoverable pursuant to FERC-approved settlements with customers. Such
provisions and accruals were not material to the Company for the years 1995,
1994 and 1993.

4. Common Stock and Other Stockholders' Equity

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

Certain provisions of the preferred stock resolutions restrict the payment
of dividends on common stock; however, all $413.2 million of retained earnings
were available for dividends on the common stock of the Company at December 31,
1995.

5. Mandatory Redemption Preferred Stock

The Company's Mandatory Redemption Preferred Stock consists of the
following:

5.50% Cumulative Preferred Stock - Of the 150,000 shares authorized, 5,560
were outstanding as of December 31, 1995. The stock outstanding has an annual
dividend rate of 5.5% and the remaining shares will be redeemed on or before
July 1, 1997.

The outstanding series of the Company's Mandatory Redemption Preferred
Stock is a $100 par value, cumulative, non-convertible and non-voting issue. If
at any time dividends on the Mandatory Redemption Preferred Stock shall be in
arrears in an amount equal to six quarterly dividends, holders of the Mandatory
Redemption Preferred Stock, voting as a class, will have the right to elect not
less than one-fourth of the Company's Board of Directors until all accrued and
unpaid dividends on the Mandatory Redemption Preferred Stock are paid in full.
In addition, if at any time dividends shall be in arrears in an aggregate amount
equal to eight full quarterly dividends, holders of these securities, voting as
a class, will have the right to elect such number of Directors as shall be
necessary to constitute a minimum majority of the Board of Directors until all
accrued and unpaid dividends on the Mandatory Redemption Preferred Stock are
paid in full.

6. 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, 1995 December 31, 1994
--------------------------- ---------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
----------- ----------- ----------- ----------
(Thousands of Dollars)

<S> <C> <C> <C> <C>
Financial assets:
Cash....................................... $ 883 $ 883 $ 372 $ 372
Notes receivable from affiliates........... 209,449 209,449 220,703 220,703
Financial liabilities:
Long-term debt............................. 179,299 223,819 179,225 191,126
Mandatory redemption preferred stock....... 556 556 556 556
</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, 1995 and 1994, respectively, for new issues with similar
remaining maturities.

F-14

<PAGE>

7. Taxes On Income

Provisions for income taxes are composed of the following (thousands of
dollars):

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

<S> <C> <C> <C>
Current Income Taxes:
Federal............................................................. $ 22,406 $ 54,194 $ 25,986
State............................................................... (285) 5,494 3,343
-------- -------- --------
22,121 59,688 29,329
-------- -------- --------

Deferred Income Taxes:
Federal............................................................. 19,328 (15,439) 8,818
State............................................................... 2,274 (1,563) 1,022
-------- -------- --------
21,602 (17,002) 9,840
-------- -------- --------

Taxes on Income........................................................ $ 43,723 $ 42,686 $ 39,169
======== ======== ========
</TABLE>

Coastal's federal income tax returns filed for the years 1985 through 1987
have been examined by the Internal Revenue Service ("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. Examinations of Coastal's federal income tax returns for 1988,
1989 and 1990 are currently in progress. 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,
--------------------------------
1995 1994 1993
-------- -------- --------

<S> <C> <C> <C>
Tax expense computed by applying the U.S. federal income
tax rate of 35%..................................................... $ 45,992 $ 42,407 $ 39,311

Increases (reductions) in taxes resulting from:
State income tax cost............................................... 1,293 2,556 2,837
Tight sands gas credit.............................................. (2,896) (4,344) (2,495)
Other............................................................... (666) 2,067 (484)
-------- -------- --------

Taxes on Income........................................................ $ 43,723 $ 42,686 $ 39,169
======== ======== ========
</TABLE>

F-15

<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,
--------------------
1995 1994
-------- --------

<S> <C> <C>
Excess of book basis over tax basis of plant, property and equipment................ $ 86,920 $ 80,037
AFUDC equity income tax gross-up pursuant to FAS No. 109............................ 1,786 4,620
Other............................................................................... (408) (81)
-------- --------
Deferred tax liabilities......................................................... 88,298 84,576
-------- --------

Provisions for rate refunds and contested claims.................................... (20,413) (32,547)
Recoverable regulatory costs and accrued expenses................................... (4,714) (9,573)
Other............................................................................... (232) (1,640)
-------- --------
Deferred tax (assets)............................................................ (25,359) (43,760)
-------- --------

Deferred income taxes............................................................ $ 62,939 $ 40,816
======== ========
</TABLE>

8. 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, 1995, the Plan did not have an unfunded accumulated benefit
obligation. Colorado made no contributions to the Plan for 1995, 1994 or 1993.
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.

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.
Irrevocable written elections to retire under this program were required to be
made by November 15, 1995. All benefits provided under this program are being
funded by the Plan and will 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 1995 and $2.8 million for each of the
years 1994 and 1993.

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 are being amortized to reflect the impact of rate regulation.

F-16

<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, 1995 and 1994 and the benefit cost for the years ended December 31,
1995, 1994 and 1993 (millions of dollars):

<TABLE>
<CAPTION>
December 31,
---------------------
1995 1994
-------- --------

<S> <C> <C>
Accumulated postretirement benefit obligation:

Retirees...................................................................... $ (11.3) $ (10.4)
Fully eligible plan participants.............................................. (.3) (.6)
Other active plan participants................................................ (6.4) (4.4)
-------- --------
(18.0) (15.4)

Plan assets at fair value......................................................... 5.9 3.4
-------- --------

Accumulated postretirement benefit obligation in excess of plan assets............. (12.1) (12.0)
Unrecognized net transition obligation............................................. 15.4 16.3
Unrecognized net (gain) from past experience different from that assumed........... (2.5) (4.0)
-------- --------
Postretirement benefit asset included in consolidated balance sheet................ $ .8 $ .3
======== ========
</TABLE>

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

<S> <C> <C> <C>
Net postretirement benefit cost consisted of the following components:

Service cost - benefits earned during the period.................... $ .3 $ .3 $ .2
Interest cost on accumulated postretirement benefit obligation...... 1.2 1.2 1.5
Amortization of transition obligation............................... .9 .9 .9
Return on assets, net of deferrals.................................. (.3) (.2) -
Deferred regulatory amount.......................................... 1.1 1.0 (1.8)
-------- -------- --------
Net postretirement benefit cost..................................... $ 3.2 $ 3.2 $ .8
======== ======== ========
</TABLE>

The assumed health care cost trend rate used in measuring the accumulated
postretirement benefit obligation was 11.2% in 1995, 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 12.0% in 1994 and 16.0% in
1993. 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, 1995 by approximately 3.4% and the net postretirement health
care cost by approximately 3.2%. The assumed discount rate used in determining
the accumulated postretirement benefit obligation was 7.25%.

9. Commitments

The Company and its subsidiaries had rental expense of approximately $5.0
million, $7.3 million and $9.0 million in 1995, 1994 and 1993, respectively
(excluding leases covering natural resources). The aggregate minimum lease
payments under existing noncapitalized long-term leases are estimated to be $3.9
million, $3.6 million, $3.6 million, $2.8 million, and $2.2 million for the
years 1996-2000, respectively, and $9.3 million thereafter.

F-17

<PAGE>

The Company has executed a service agreement with WIC, an affiliate,
providing for the availability of pipeline transportation capacity through
January 1, 2004. 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):

1996 ..................................... $ 4,200
1997 ..................................... 4,200
1998 ..................................... 3,700
1999 ..................................... 3,700
2000 ..................................... 3,600
Later years .............................. 11,100

The Company expensed approximately $4.4 million related to the minimum
payments under this agreement in 1995.

10. Litigation and Regulatory Matters

- - Litigation

Other lawsuits and other proceedings which have arisen in the ordinary
course of business are pending or threatened against the Company or its
subsidiaries.

- - Rate Matters

F-18

<PAGE>

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 will make a general rate increase filing with the FERC in the
first half of 1996, with such filing expected to become effective, subject to
refund, in late 1996.

11. Quarterly Results of Operations (Unaudited)

The results of operations by quarter for the years ended December 31, 1995
and 1994 were (thousands of dollars):

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

<S> <C> <C> <C> <C>
Revenues................................................. $ 106,827 $ 92,841 $ 92,414 $ 103,872
Cost of gas sold......................................... 10,975 9,576 9,652 13,928
--------- ---------- ---------- ---------
Revenues less cost of gas sold........................ 95,852 83,265 82,762 89,944
Other costs and expenses................................. 67,591 66,545 64,339 65,632
--------- ---------- ---------- ---------
Net earnings.......................................... $ 28,261 $ 16,720 $ 18,423 $ 24,312
========= ========== ========== =========
</TABLE>

<TABLE>
<CAPTION>
1994 Quarter Ended
----------------------------------------------
March 31, June 30, Sept. 30, Dec. 31,
--------- ---------- ---------- ---------

<S> <C> <C> <C> <C>
Revenues................................................. $ 111,111 $ 96,738 $ 79,521 $ 106,654
Cost of gas sold......................................... 15,707 14,675 7,235 15,404
--------- ---------- ---------- ---------
Revenues less cost of gas sold........................ 95,404 82,063 72,286 91,250
Other costs and expenses................................. 71,959 62,409 59,408 68,720
--------- ---------- ---------- ---------
Net earnings.......................................... $ 23,445 $ 19,654 $ 12,878 $ 22,530
========= ========== ========== =========
</TABLE>

F-19

<PAGE>

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.

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.

F-20

<PAGE>

The Company's operating revenues and operating profit (loss) for the years
ended December 31, 1995, 1994 and 1993, and identifiable assets as of December
31, 1995, 1994 and 1993, by segment, are shown below (thousands of dollars):

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

<S> <C> <C> <C>
1995

Natural gas............................................ $ 374,273 $ 143,598 $ 823,013
Exploration and production............................. 12,487 (3,524) 38,435
Adjustments and eliminations........................... (5,137) - -
-------------- -------------- --------------
Segment totals...................................... 381,623 140,074 861,448
Other income-net....................................... 14,331 14,331 -
Corporate general and administrative expenses.......... - (4,874) -
Interest............................................... - (18,092) -
Income taxes........................................... - (43,723) -
-------------- -------------- --------------
Consolidated Totals................................. $ 395,954 $ 87,716 $ 861,448
============== ============== ==============

1994

Natural gas............................................ $ 368,604 $ 132,355 $ 914,195
Exploration and production............................. 24,934 4,086 47,916
Adjustments and eliminations........................... (8,249) - -
-------------- -------------- --------------
Segment totals...................................... 385,289 136,441 962,111
Other income-net....................................... 8,735 8,735 -
Corporate general and administrative expenses.......... - (5,051) -
Interest............................................... - (18,932) -
Income taxes........................................... - (42,686) -
-------------- -------------- --------------
Consolidated Totals................................. $ 394,024 $ 78,507 $ 962,111
============== ============== ==============

1993

Natural gas............................................ $ 432,971 $ 127,411 $ 846,739
Exploration and production............................. 18,675 2,383 54,888
Adjustments and eliminations........................... (13,632) - -
-------------- -------------- --------------
Segment totals...................................... 438,014 129,794 901,627
Other income-net....................................... 7,318 7,318 -
Corporate general and administrative expenses.......... - (4,339) -
Interest............................................... - (20,426) -
Income taxes........................................... - (39,169) -
-------------- -------------- --------------
Consolidated Totals................................. $ 445,332 $ 73,178 $ 901,627
============== ============== ==============
</TABLE>

F-21

<PAGE>

Capital expenditures and depreciation, depletion and amortization expense
by segment for the years ended December 31, 1995, 1994 and 1993, were (thousands
of dollars):

<TABLE>
<CAPTION>
Depreciation,
Depletion and
Capital Amortization
Segment Expenditures Expense
------- ------------ -------------
1995
----
<S> <C> <C>
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

1993
----
Natural gas................................................. $ 68,186 $ 26,064
Exploration and production.................................. 4,247 10,281
</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,
----------------------------------
1995 1994 1993
---------- --------- ---------

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

Amount (thousands of dollars)...................................... $ 160,523 $ 198,002 $ 201,505
========== ========= =========

Percent............................................................. 41% 50% 45%
========== ========= =========
</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, 1995, 1994 and 1993. 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-22

<PAGE>

13. Transactions with Affiliates

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

<TABLE>
<CAPTION>
1995 1994 1993
------------------ ------------------ -----------------
Percent Percent Percent
Amount of Total Amount of Total Amount of Total
------ -------- ------ -------- ------ --------

<S> <C> <C> <C> <C> <C> <C>
Revenues
Gathering and Transportation -
ANR Pipeline Company <F1>.................. $ - -% $ - - % $ 6,548 4.9%
Coastal Chem, Inc.......................... 2,005 1.0 2,522 1.3 2,711 2.0
Coastal Gas Marketing Company.............. 9,257 4.6 10,582 5.4 8,438 6.4
Coastal Oil & Gas Corporation ............. 2,439 1.2 6,753 3.5 7,686 5.8

Extracted Products and Gas Processing -
Coastal Refining & Marketing, Inc.......... $ 26,047 97.6% $ 28,991 96.0% $ 32,597 92.4%
Coastal States Trading, Inc................ 351 1.3 923 3.1 869 2.5

Incidental Gasoline, Oil and Condensate
Sales -
Coastal Refining & Marketing, Inc.......... $ 1,348 35.0% $ 857 23.5% $ 905 34.2%
Coastal States Trading, Inc................ 1,342 34.8 1,185 32.5 1,219 46.1

Contract Storage -
Coastal Chem, Inc.<F1>..................... $ - -% $ - -% $ 74 2.5%
Coastal Gas Marketing Company<F2>.......... - - 456 4.6 30 1.0

Miscellaneous -
Coastal Refining & Marketing, Inc.<F3>..... $ 285 11.2% $ 194 10.3% $ - -%

Costs and Expenses
Gas Purchases -
Coastal Gas Marketing Company.............. $ 1,345 1.9% $ 1,582 1.7% $ 2,755 2.1%
Coastal Limited Ventures, Inc.<F2>......... - - 205 .2 374 .3
Coastal Oil & Gas Corporation.............. 3,156 4.5 4,505 4.9 4,975 3.9

Gathering, Transportation and Compression -
WIC........................................ $ 4,425 55.6% $ 4,934 55.3% $ 5,362 51.2%
ANR Pipeline Company<F4>................... 178 2.2 - - - -
<FN>
- -----------------
<F1>
The 1995 and 1994 amounts were immaterial.
<F2>
The 1995 amounts were immaterial.
<F3>
The 1993 amounts were immaterial.
<F4>
The 1994 and 1993 amounts were immaterial.
</FN>
</TABLE>

Services provided by the Company at cost for affiliated companies were
$5.9 million for 1995, $8.3 million for 1994 and $7.9 million for 1993. Services
provided by affiliated companies for the Company at cost were $7.6 million for
1995, $7.7 million for 1994 and $8.1 million for 1993. 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

F-23

<PAGE>

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 $1.3 million for 1995, $1.4 million in 1994 and $1.5 million in
1993 was recorded in conjunction with the terms of the lease agreements.

In 1992, the Company entered into a five-year lease agreement with ANR
Production Company, an affiliate, for the rental of certain pipeline facilities.
Under the conditions of the lease agreement, the Company has the option to renew
the agreement under the same terms for an additional five year period. Annual
rental expense of approximately $.2 million was recorded in 1995, 1994 and 1993
in conjunction with the terms of the lease agreement.

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, 1995, the Company had advanced
$209.5 million to associated companies at a market rate of interest. Such amount
is repayable on demand.

F-24

<PAGE>

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

Reserves, capitalized costs, costs incurred in oil and gas acquisition,
exploration and development activities, results of operations and the
standardized measure of discounted future net cash flows are presented for the
exploration and production segment. Natural gas systems reserves and the related
standardized measure of discounted future net cash flows are 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>
Estimated Quantities of Proved Reserves
<CAPTION>
Natural Gas Exploration
Company-Owned Reserves Systems and Production
------------- --------------------------
Developed Developed Undeveloped Total
------------- --------- ----------- ---------
<S> <C> <C> <C> <C>
Natural Gas (MMcf):
------------------
1995............................................. 302,420 66,282 7,090 375,792
1994............................................. 334,597 76,917 2,598 414,112
1993............................................. 379,795 87,905 8,088 475,788

Oil, Condensate and Natural Gas Liquids (000 barrels):
-----------------------------------------------------
1995............................................. 126 323 36 485
1994............................................. 11 409 3 423
1993............................................. 7 385 26 418
</TABLE>

Changes in proved reserves since the end of 1992 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 Systems Production Systems Production
- --------------------- -------- ----------- -------- -----------
<S> <C> <C> <C> <C>
Total, end of 1992.............................. 418,831 96,318 14 376
-------- -------- -------- --------
Production during 1993.......................... (46,524) (9,930) (1) (56)
Extensions and discoveries...................... - 6,455 - 33
Acquisitions.................................... - - - -
Revisions of previous quantity estimates and
other.......................................... 7,488 3,150 (6) 58
-------- -------- -------- --------
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
======== ======== ======== ========
</TABLE>

F-25

<PAGE>

Total proved reserves for natural gas systems exclude storage gas and
liquids volumes. The natural gas systems storage gas volumes are 39,215, 39,984
and 41,012 MMcf and storage liquids volumes are approximately 138,000, 172,000
and 150,000 barrels at December 31, 1995, 1994 and 1993, respectively.

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

<CAPTION>
December 31, 1995 December 31, 1994
------------------------------- ------------------------------
Accumulated Accumulated
Depreciation, Depreciation,
Capitalized Depletion and Capitalized Depletion and
Proved and Unproved Properties Cost Amortization Cost Amortization
- ------------------------------ ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Undeveloped............................. $ 461 $ 269 $ 753 $ 339
Developed............................... 137,606 103,980 143,689 104,069
----------- ----------- ----------- -----------
$ 138,067 $ 104,249 $ 144,442 $ 104,408
=========== =========== =========== ===========
</TABLE>

As described in Note 1 of Notes to Consolidated Financial Statements, the
Company follows the full-cost method of accounting for oil and gas properties.

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

<CAPTION>
Year Ended December 31,
--------------------------------
1995 1994 1993
-------- -------- --------

<S> <C> <C> <C>
Property acquisition costs................................................... $ 436 $ 5 $ 52
Exploration costs............................................................ 40 323 63
Development costs............................................................ 3,200 6,717 4,123
</TABLE>

Property acquisition costs consist principally of amounts paid for proved
reserves.

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

<CAPTION>
Year Ended December 31,
--------------------------------
1995 1994 1993
-------- -------- --------

<S> <C> <C> <C>
Revenues:
Sales..................................................................... $ 2,313 $ 4,167 $ 3,133
Transfers................................................................. 10,799 21,984 16,607
-------- -------- --------
Total.................................................................. 13,112 26,151 19,740

Production costs............................................................. (5,022) (5,627) (5,265)
Operating expenses........................................................... (1,710) (1,810) (1,621)
Depreciation, depletion and amortization..................................... (9,855) (14,675) (10,281)
-------- -------- --------
(3,475) 4,039 2,573

Income tax benefit .......................................................... 4,112 2,930 1,594
-------- -------- --------

Results of operations for producing activities (excluding corporate
overhead and interest costs).............................................. $ 637 $ 6,969 $ 4,167
======== ======== ========
</TABLE>

The average amortization rate per equivalent Mcf was $0.89 in 1995, $0.96
in 1994 and $1.00 in 1993.

F-26

<PAGE>

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, may be subject to material
future revisions (thousands of dollars):

<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------------------------------------------------------------
1995 1994 1993
------------------------- ------------------------- --------------------------
Natural Exploration Natural Exploration Natural Exploration
Gas and Gas and Gas and
Systems Production Systems Production Systems Production
----------- ----------- ----------- ----------- ----------- -----------

<S> <C> <C> <C> <C> <C> <C>
Future cash inflows.......... $ 286,853 $ 104,369 $ 235,101 $ 133,850 $ 298,859 $ 226,754
Future production and
development costs......... (82,282) (49,586) (65,388) (51,623) (62,684) (59,499)
Future income tax expenses... (68,163) (6,872) (57,958) (13,339) (81,827) (37,124)
----------- ----------- ----------- ----------- ----------- -----------
Future net cash flows........ 136,408 47,911 111,755 68,888 154,348 130,131
10% annual discount for
estimated timing of cash
flows..................... (61,368) (14,278) (43,983) (22,358) (59,542) (45,605)
----------- ----------- ----------- ----------- ----------- -----------
Standardized measure of
discounted future net
cash flows................ $ 75,040 $ 33,633 $ 67,772 $ 46,530 $ 94,806 $ 84,526
=========== =========== =========== =========== =========== ===========
</TABLE>

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

<S> <C> <C> <C> <C> <C> <C>
Sales and transfers, net of
production costs.......... $ (30,580) $ (7,726) $ (39,272) $ (18,115) $ (35,394) $ (14,475)
Net changes in prices and
production costs.......... 45,874 (10,302) (15,493) (31,746) (881) 14,805
Extensions and discoveries... - 1,149 - 3,597 - 5,098
Acquisitions................. 941 388 - - - -
Development costs incurred
during the period that
reduced estimated future
development costs......... - 496 - 3,750 - 1,694
Revisions of previous quantity
estimates, timing and other (15,449) (4,573) 1,449 (17,781) 11,975 2,694
Accretion of discount........ 7,325 4,497 10,793 8,718 12,409 7,334
Net change in income taxes... (843) 3,174 15,489 13,581 3,432 (9,321)
----------- ----------- ----------- ----------- ----------- -----------
Net change.............. $ 7,268 $ (12,897) $ (27,034) $ (37,996) $ (8,459) $ 7,829
=========== =========== =========== =========== =========== ===========
</TABLE>

None of the amounts include any value for storage gas and liquids volumes,
which were approximately 39.2 Bcf and 138 thousand barrels, respectively, at the
end of 1995.

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.

(21)* Subsidiaries of the Company.

(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.

EXHIBIT 10

AGREEMENT FOR CONSULTING SERVICES

This Agreement made and entered into as of January 1, 1996, by and between
Colorado Interstate Gas Company of Colorado Springs, Colorado, (hereinafter "the
Company") and Harold Burrow of Houston, Texas, (hereinafter "the Consultant").

WHEREAS, the Company requires the services of the Consultant from time to
time; and,

WHEREAS, Consultant is well qualified and willing to perform such
services;

NOW, THEREFORE, the Company and the Consultant agree as follows:

1. TERM: - This Agreement shall be effective from the date hereof and
shall remain in effect until terminated by either party in accordance with the
termination provisions set forth below.

2. SCOPE OF SERVICES: - Consultant agrees to provide the Company with such
services as shall be requested by the Company from time to time; provided,
however, nothing in this Agreement shall be deemed to constitute a promise by
the Company to provide, or the Consultant to perform, any minimum amount of
work.

The Company shall inform and direct the Consultant as to the desired
activities. It shall be Consultant's responsibility to see that such activities
are performed in a proper manner and that periodic progress reports are provided
upon request, thereby enabling the Company to monitor the quality and progress
of the activity.

3. INDEPENDENT CONTRACTOR: - The Consultant agrees that he is acting as an
independent contractor. The Consultant will be responsible for the payment of
all taxes associated with the consulting services performed hereunder including,
but not limited to, federal withholding, social security, worker's compensation,
unemployment, and any other taxes associated with the employment of Consultant
as an independent contractor.

4. COMPENSATION: - The Company agrees to pay, and the Consultant agrees to
accept as a fee for his services, the sum of $2,500.00 for each calendar month
during which this Agreement remains in effect, with partial months to be
compensated on a pro-rata basis.

The Company further agrees that it will reimburse consultant for all
reasonable travel and other expenses incurred in connection with the performance
of the services contemplated by this Agreement.

Further, in order to facilitate the cooperation between the parties hereto
and provide an unrestricted flow of vital company information between the
Company and the Consultant, to the ultimate benefit of the Company, it is agreed
and understood that Company will provide Consultant, at no cost to Consultant,
with office, automobile, office furniture, office equipment and qualified office
assistance of the quality and amount heretofore provided to Consultant when same
was an employee of the Company. It is agreed and understood that the cost to the
Company in connection with items provided under the provisions of this paragraph
may be allocated between itself and any of its affiliates who have comparable
agreements with Consultant in such proportions as they may agree upon.

5. PAYMENT FOR CONSULTING SERVICES: - The Company will pay Consultant each
month the agreed upon fee as specified in Section 4 hereof. In addition thereto
the Company, upon receipt of statement from Consultant, shall make prompt
payment to Consultant such amounts as may be due for travel and other expenses
as specified in Section 4 hereof.

6. CONFIDENTIAL INFORMATION: - Confidential information shall include all
information disclosed to the Consultant or which Consultant has heretofore
acquired which relates to the Company's past, present, or future research,
development, or business activities.

Consultant shall hold all such confidential information in trust and
confidence for the Company and agrees that he will not, during or after the term
of this Agreement, disclose to any person, firm or corporation, nor use for his
own business or benefit, any such confidential information not in the public
domain, obtained by him while in the execution of the terms and conditions of
his Agreement.

-1-

<PAGE>

7. TERMINATION: - Either party shall have the right to terminate this
Agreement with or without cause at any time by providing the other party with a
certified, return receipt written notice of termination at least 30 days in
advance of such termination. Upon termination, all Company property will be
surrendered and the Consultant will be obligated to provide no further services
to the Company. Termination will become effective upon completion of payment to
the Consultant for all services rendered up to and including the date of
termination.

8. ASSIGNMENT: - The Consultant shall not assign this Agreement or any
part hereof without the written consent of the Company.

9. HOLD HARMLESS: - The Consultant agrees that no liability shall attain
in favor of the Consultant as against any officer, director, member, agent, or
employee of the Company, but that he will instead look solely to the assets of
the Company for satisfaction of any debts arising out of this Agreement. The
Consultant further agrees to hold the Company harmless and to accept full
responsibility for any additional income or employment taxes incurred by virtue
of the execution or performance of this agreement. The Consultant further agrees
that during the term of this Agreement he will maintain in force and effect
automobile liability insurance in a sufficient amount.

10. SOLE AGREEMENT: - This Agreement shall supersede any and all prior
agreements and understandings between the parties respecting the subject matter
hereof. No representations or statements made by any representative of the
Company or the Consultant which are not stated herein shall be binding. The
provisions hereof constitute the entire Agreement between the parties. No
modification or amendment hereof shall be binding unless in writing and signed
by a duly authorized representative of each party. Failure of either party to
enforce rights under this Agreement shall not constitute a waiver of such
rights.

11. GOVERNING LAW: - This Agreement shall be governed by, and construed in
accordance with, the laws of the State of Texas.

WHEREFORE, the parties have set their hands hereto, as indicated by the
signatures below.

HAROLD BURROW
-----------------------------------
Harold Burrow
Consultant

COLORADO INTERSTATE GAS COMPANY

JON R. WHITNEY
-----------------------------------
Jon R. Whitney
President and Chief Executive Officer

-2-

EXHIBIT 21

SUBSIDIARIES OF COLORADO INTERSTATE GAS COMPANY

State of
Incorporation

CIG Exploration, Inc...................................... Delaware
CIG Field Services Company................................ Delaware
Colorado Water Supply Company............................. Delaware
Subsidiary:
Colorado Interstate Production Company.............. Delaware

<ARTICLE> 5
<LEGEND> THE SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION
EXTRACTED FROM COLORADO INTERSTATE GAS COMPANY FORM
10-K ANNUAL REPORT FOR THE PERIOD ENDED DECEMBER
31, 1995 AND IS QUALIFIED IN ITS ENTIRETY BY
REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000

<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> DEC-31-1995
<CASH> 883
<SECURITIES> 0
<RECEIVABLES> 266,302
<ALLOWANCES> 0
<INVENTORY> 9,494
<CURRENT-ASSETS> 302,318
<PP&E> 1,199,564
<DEPRECIATION> 658,327
<TOTAL-ASSETS> 861,448
<CURRENT-LIABILITIES> 128,545
<BONDS> 179,299
556
0
<COMMON> 27,561
<OTHER-SE> 432,247
<TOTAL-LIABILITY-AND-EQUITY> 861,448
<SALES> 381,623
<TOTAL-REVENUES> 395,954
<CGS> 44,131
<TOTAL-COSTS> 246,423
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 18,092
<INCOME-PRETAX> 131,439
<INCOME-TAX> 43,723
<INCOME-CONTINUING> 87,716
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 87,716
<EPS-PRIMARY> 0
<EPS-DILUTED> 0

</TABLE>