COLORADO INTERSTATE GAS CO, 10-K405, 1995-03-31

COLORADO INTERSTATE GAS CO
10-K405, 1995-03-31
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, 1994 or

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

For the transition period from ____________________ to _____________________

Commission file number 1-4874

COLORADO INTERSTATE GAS COMPANY
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)

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

TWO NORTH NEVADA AVENUE
COLORADO SPRINGS, COLORADO 80903-1727
(Address of principal executive offices) (Zip Code)

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

SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:

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

10% Senior Debentures, due 2005 New York Stock Exchange

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 15, 1995, 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
- -------- ----
<S> <C> <C>
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.............................................. 2
Gas System Reserves........................................ 3
General.................................................. 3
Reserves................................................. 3
Reserves Dedicated to a Particular Customer.............. 3
Regulations Affecting Gas System........................... 3
General.................................................. 3
Rate Matters............................................. 4
Gas and Oil Exploration and Production....................... 5
Environmental................................................ 5
Other Developments........................................... 6
2. Properties..................................................... 6
3. Legal Proceedings.............................................. 6
4. Submission of Matters to a Vote of Security Holders............ 6

PART II

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

PART III

10. Directors and Executive Officers of the Registrant............. 8
11. Executive Compensation......................................... 10
12. Security Ownership of Certain Beneficial Owners and Management. 18
13. Certain Relationships and Related Transactions................. 22

PART IV

14. Exhibits, Financial Statement Schedules, and Reports on
Form 8-K...................................................... 23
</TABLE>

(i)
<PAGE>

GLOSSARY

"ANR" means American Natural Resources Company

"ANR Pipeline" means ANR Pipeline Company

"Bcf" means billion cubic feet

"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

"FERC" means Federal Energy Regulatory Commission

"Huddleston" means Huddleston & Co., Inc., Houston, Texas

"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.

NOTE: 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, 1994, the Company had 1,110 employees.

The revenues and operating profit of the Company by industry segment for each
of the three years in the period ended December 31, 1994, and the related
identifiable assets as of December 31, 1994, 1993 and 1992, 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.

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, 1994 consisted of
6,356 miles of pipeline and 66 compressor stations with approximately 348,000
installed horsepower. At December 31, 1994, the design peak day delivery
capacity of the transmission system was approximately 2.0 Bcf per day. The
underground storage facilities have a working capacity of approximately 29 Bcf
and a peak day delivery capacity of approximately 769 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, but provide for reduced customer purchases to be
made each year. 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 at such
time as the contracts expire and without prior FERC approval. 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.

1
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Effective October 1, 1993, Colorado assigned an undivided interest in a
portion of its company-owned leases to a new subsidiary. The subsidiary
contracts to sell the production to Colorado's Merchant Division, which utilizes
the gas primarily for its sales to Colorado's traditional customers. The reserve
volumes reported represent those interests retained by Colorado together with
those assigned to the new subsidiary.

Gas sales revenues were $139 million in 1994, compared to $223 million in
1993 and $261 million in 1992. The decreases 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. In addition, prior to October 1, 1993,
Colorado provided storage and transportation services as part of its "bundled"
sales service. 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.

Colorado's deliveries for the years 1994, 1993 and 1992 are as follows:
<TABLE>
<CAPTION>

Total System Daily Average
Year Deliveries System Deliveries
- --------------- -------------- -----------------
(Bcf) (MMcf)
<S> <C> <C>

1994 436 1,195
1993 453 1,241
1992 428 1,169
</TABLE>

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
110,200 horsepower of compression in its gathering operations. Colorado owns and
operates six gas processing plants which recovered approximately 88 million
gallons of liquid hydrocarbons in 1994, compared to 86 million gallons in 1993
and 77 million gallons in 1992, and 4,300 long tons of sulfur in 1994, compared
to 4,400 long tons in 1993 and 3,600 long tons in 1992. Additionally, in 1994,
Colorado processed approximately 6 million gallons of liquid hydrocarbons owned
by others compared to 12 million in 1993 and 10 million in 1992. 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.

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 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.

2
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Natural gas competes with other forms of energy available to customers,
primarily on the basis of price. 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 1995, Colorado has sales contract
commitments of approximately 65,000 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 monthly
spot gas purchases, if needed.

RESERVES

The table below represents estimates of the Company's owned reserves as of
December 31, 1994, 1993, and 1992 (Bcf), as prepared by Huddleston, Colorado's
independent engineers.
<TABLE>
<CAPTION>

1994 1993 1992
---- ---- ----
<S> <C> <C> <C>
Owned or controlled by Colorado.......... 383 433 478
</TABLE>

The estimates of 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, 1994, Colorado maintained under its own account 2 Bcf of
natural gas in underground working storage for system balancing. The Company has
an additional 38 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 new subsidiary. The reserve
volumes reported represent those retained by Colorado as well as those assigned
to the new subsidiary.

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

3
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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.
Operations on United States government land are regulated by the Department of
the Interior.

FERC Order Nos. 500 and 528 allowed regulated pipelines, including Colorado,
to recover, through a fixed charge, from 25% to 50% of the cost of payments made
to producers to extinguish outstanding claims under existing gas purchase
contracts or to secure reformation of existing contracts. Fixed charges are paid
by pipeline sales customers without regard to volumes of gas purchased. Under
this election, however, an amount equivalent to the amount included in the fixed
charge must be borne by the pipeline. Colorado has incurred costs related to
contract reformation and settlements of take-or-pay claims, a portion of which
has been recovered under Order Nos. 500 and 528.

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. The case is currently in the briefing phase before the United States
Court of Appeals for the D.C. Circuit. Notwithstanding those appeals, the
Company has successfully complied with the requirements of Order 636.

On July 2, 1993, the Company submitted to the FERC an unanimous offer of
settlement which resolved all the Order 636 restructuring issues which had been
raised in its restructuring proceedings. That settlement was ultimately approved
(except for minor issues), and the Company's restructured services became
effective October 1, 1993. As of October 1, 1993, the Company separated all of
its services and separately contracts for each service on a stand-alone or
"unbundled" basis. Gathering, storage and transportation services are provided
at negotiated rates established between minimum and maximum levels approved by
the FERC, while gas processing rates are not subject to FERC regulations.

RATE MATTERS

Colorado's gas sales for resale contracts extend through September 30, 1996,
but provide for reduced customer purchases to be made each year. 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 at FERC under Docket RP93-99 to increase
its rates by approximately $26.5 million annually. Such rates (adjusted to
reflect Colorado's Order 636 program) 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 for prospective
application and will be required to make refunds as a result of the approval of
the settlement. Such refunds will be distributed in March 1995. The Company has
fully accrued for these refunds and therefore such refunds will not have an
adverse effect on its consolidated financial position or results of operations.

Certain 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.

4
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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, 1994:
<TABLE>
<CAPTION>

1994 1993 1992
------ ------ ------
<S> <C> <C> <C>

Gas (MMcf)................ 61,046 56,454 55,150
Oil (000 barrels)......... 8 8 5
Condensate (000 barrels).. 74 49 42
</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, 1994:
<TABLE>
<CAPTION>

1994 1993 1992
------ ------ ------
<S> <C> <C> <C>

Average sales price (net of production taxes):
Gas - per Mcf................................... $ 1.44 $ 1.81 $ 1.66
Oil - per barrel................................ 14.38 15.18 17.76
Condensate - per barrel......................... 15.09 15.92 16.44

Average production cost per unit (equivalent Mcf).. $ 0.37 $ 0.51 $ 0.39
</TABLE>

At December 31, 1994, the gas and oil properties of the Company included
leasehold interests covering 471,047 acres (353,978 net acres), of which 385,978
acres (320,852 net acres) were producing and 85,069 acres (33,126 net acres)
were undeveloped. The net producing acreage, held by production, is concentrated
principally in Texas (78%), Oklahoma (8%), Wyoming (6%) and Utah (6%). The net
undeveloped acreage, not held by production, is principally in Wyoming (45%),
Montana (22%) and Colorado (19%).

The Company drilled 19 gross (7.68 net) gas wells, 22 gross (12.53 net) gas
wells, and 39 gross (34.41 net) gas wells in 1994, 1993 and 1992, respectively.

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.

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 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.

5
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("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 March 1994, the Company sold its interest in Natural Fuels Corporation to
CIC Stock Corporation, an affiliate.

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. Trial has been set for March 22, 1995.

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.

6
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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
$364.8 million was available for dividends on the common stock of the Company at
December 31, 1994. 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, 1993. The
Notes to Consolidated Financial Statements included herein contain information
relating to this data.
<TABLE>
<CAPTION>

Year Ended December 31,
------------------------------------------------------
1994 1993 1992 1991 1990
-------- -------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>

Operating revenues............................... $385,289 $438,014 $ 402,220 $ 375,244 $ 372,854
Net earnings..................................... 78,507 73,178 84,075 82,757 64,380
Total assets..................................... 962,111 901,627 1,097,178 1,023,586 1,016,781
Long-term debt, excluding current maturities..... 179,225 179,145 195,278 203,404 215,530
Mandatory redemption preferred stock, excluding
shares redeemable within one year............... 556 556 556 906 3,898
Common stock and other stockholders' equity...... 411,423 358,047 525,400 503,946 428,320

</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-4 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.

7
<PAGE>

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.

The directors and executive officers of Colorado as of March 15, 1995, were
as follows:
<TABLE>
<CAPTION>

NAME (AGE), YEAR FIRST ELECTED POSITIONS AND OFFICES
DIRECTOR AND/OR OFFICER WITH THE REGISTRANT
- ------------------------------ ---------------------
<S> <C>
Harold Burrow (80), 1974 Chairman of the Board of Directors
Jon R. Whitney (50), 1987 and 1974 President, Chief Executive Officer and
Director
Richard L. Anderson (58), 1989 Director
David A. Arledge (50), 1981 Director
James F. Cordes (54), 1986 Director
Peter J. King, Jr. (73), 1989 Director
Roger L. Ogden (49), 1989 Director
Paul W. Powers (52), 1989 Director
William B. Tutt, (53), 1989 Director
O. S. Wyatt, Jr. (70), 1972 Director
C. Scott Hobbs (41), 1985 Executive Vice President and Chief
Operating Officer
Daniel F. Collins (53), 1986 Senior Vice President
Donald H. Gullquist (51),1994 Senior Vice President
Rebecca H. Noecker (43), 1988 Senior Vice President, General Counsel and
Director
Austin M. O'Toole (59), 1984 Senior Vice President and Secretary
Coby C. Hesse (47), 1986 Senior Vice President
Richard G. Smead (48), 1988 Senior Vice President
Donald J. Zinko (50), 1988 Senior Vice President
Paul Dallas Childress (56), 1985 Vice President
Steven J. Coffin (39), 1990 Vice President
Ronald A. Gillet (53), 1993 Vice President
Thomas E. Jackson, Jr. (55), 1989 Vice President
Ronald D. Matthews (47), 1994 Vice President and Treasurer
Robert O. Reid (48), 1985 Vice President
E. C. Simpson (59), 1990 Vice President
William H. Sparger (52), 1992 Vice President
Steven W. Zuckweiler (44), 1991 Vice President
Dan A. Homec (46), 1989 Assistant Vice President and Controller
</TABLE>

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 1995. Each of the directors and officers named above have been officers or
employees of Colorado, ANR Pipeline and/or Coastal for five years or more except
for the following:

Mr. Coffin was elected a Vice President of Colorado in June 1990. Before
joining the Company, he practiced law with the Denver law firms of Holland &
Hart from 1986 to 1988 and Brownstein Hyatt Farber & Madden from 1988 to 1990.
Prior thereto, he served as Deputy Administrative Assistant to a United States
congressman.

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.

8
<PAGE>

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.

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.

9
<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, 1994, 1993 and 1992 as to cash compensation paid by Coastal and its
subsidiaries, as well as certain other compensation paid or accrued for those
years, to Coastal's Chief Executive Officer ("CEO") and its four other most
highly compensated executive officers (the "Named Executive Officers").

SUMMARY COMPENSATION TABLE
<TABLE>
<CAPTION>

Long Term Compensation
------------------------
Annual Compensation/(1)/ Awards Payouts
------------------------------------------- ------------ ----------
Securities All Other
Underlying LTIP Compen-
Name and Options/ Payouts sation
Principal Position Year Salary ($)/(2)/ Bonus ($)/(4)/ SARs (#)/(5)/ ($) $/(6)/
- -------------------------- --------- ---------------- --------------- ------------- ------- -----------
<S> <C> <C> <C> <C> <C> <C>

O. S. Wyatt, Jr., 1994 849,093 200,000 -0- -0- 67,928
Chairman of the Board 1993 962,495 90,000 -0- 71,690
and CEO 1992 1,038,178/(3)/ -0- -0- 75,974

David A. Arledge, 1994 553,873 150,000 -0- -0- 44,310
President, Chief 1993 473,211 70,000 38,848 42,042
Operating Officer 1992 469,858/(3)/ 60,000 35,000 48,794
and Director

James F. Cordes, 1994 592,223 130,000 -0- -0- 47,378
Executive V.P. 1993 624,675 50,000 32,094 48,414
and Director 1992 596,221/(3)/ 60,000 25,000 48,118

James A. King, 1994 343,823 75,000 -0- -0- 6,877
Executive V.P. 1993 324,658 28,000 20,000 3,254
1992 208,038/(3)/ 60,000 10,000 -0-

Sam F. Willson, Jr., 1994 334,062 75,000 -0- -0- 26,725
Executive V.P. 1993 334,062 28,000 15,000 28,600
1992 344,603/(3)/ 60,000 15,000 29,443
</TABLE>
________________________

(1) 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.

(2) Salary amounts for Messrs. Wyatt, Arledge and Cordes for 1992 and 1993
include directors' fees paid during these periods which were previously
reported under "All Other Compensation." Directors' fees for members of
management of Coastal were eliminated in September, 1993. There was no
salary change for Mr. Wyatt during 1994; the reduced base pay level for
1994 was due to the September 1993 salary reduction (reported in the 1994
Coastal Proxy Statement) being in effect for all of 1994.

10
<PAGE>

(3) Due to Coastal's practice of paying bi-weekly, there is one extra pay
period reflected in the 1992 salary. Normally there are 26 pay periods, but
approximately once every 11 years there are 27 pay periods; 1992 was such a
year.

(4) Although 1993 bonus awards were not finalized by Coastal's Compensation
and Executive Development Committee until after the 1994 Coastal Proxy
Statement had been prepared, all awards were based solely on 1993
performance. Bonuses for 1992 were paid in equal installments over a three-
year period, provided the employee was still employed on the anniversary
date of the award. The 1994 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.

(5) The options do not carry any stock appreciation rights.

(6) All Other Compensation for 1994 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 $4,232 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 $32,310; James F. Cordes
$35,378; James A. King $2,645 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.

Mr. Cordes is employed pursuant to a five-year employment contract expiring
in 1995, which provides that if he is terminated for a reason not permitted by
the employment contract, he will be entitled to receive for the remainder of the
term the salary, employee benefits, perquisites, salary increases, bonuses and
other incentive compensation which he would have received had he not been
terminated. Such reasons are a significant change in title, duties, authorities
or reporting responsibilities, a reduction in salary or benefits or a move of
the location of his office to a location not acceptable to him.

STOCK OPTIONS

No option/SAR grants were made to the Named Executive Officers during the
fiscal year ended December 31, 1994.

11
<PAGE>

OPTION/SAR EXERCISES AND HOLDINGS

The following table sets forth information with respect to the Named
Executive Officers, concerning the exercise of options during the last fiscal
year and unexercised options and SARs held as of the fiscal year ("FY") ended
December 31, 1994.

AGGREGATED OPTION/SAR EXERCISES IN LAST FISCAL YEAR
AND FY-END OPTION/SAR VALUES (1994)
<TABLE>
<CAPTION>

Number of
Securities Value of
Underlying Unexercised
Unexercised In-the-Money
Options/SARs Options/SARs
at FY-End (#) at FY-End($)/(1)/

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- 167,371 / 103,002 473,536 / -0-
James F. Cordes -0- -0- 98,785 / 73,002 206,367 / -0-
James A. King -0- -0- 2,000 / 28,000 -0- / -0-
Sam F. Willson, Jr. -0- -0- 28,149 / 45,000 12,825 / -0-
</TABLE>
- ------------------
(1) $-based on the market price of $25.63 at December 31, 1994.

12
<PAGE>

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 Securities and Exchange Commission ("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 1994 pay levels for the CEO.

OVERALL OBJECTIVES OF THE EXECUTIVE COMPENSATION PROGRAM

Coastal's compensation philosophy and program objectives are directed by two
primary guiding principles. First, the program is intended to provide fully
competitive levels of compensation - at expected levels of performance - in
order to attract, motivate and retain talented executives. Second, the program
is intended to create an alignment of interests between Coastal's executives and
shareowners such that a significant portion of each executive's compensation is
directly linked to maximizing shareholder 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 are generally consistent with that
target. (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 graphs, 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 40 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 1994 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.

13
<PAGE>

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 Coastal's 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 1994, 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 1994 Coastal's EBIT performance
significantly improved over 1993 performance. This 1994 EBIT achievement 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 1994 is
a discretionary annual bonus pool. As a result, no formula performance measures
were used in establishing the size of awards under this portion of the plan.
However, in establishing the size of the discretionary bonus pool, the Committee
considered Coastal's Return on Equity relative to industry peers (using the same
peers included in the shareholder return graphs), 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
1994 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
Coastal's 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.

No stock options were granted to the Named Executive Officers in 1994 since
Coastal made larger than normal grants to key executives in December 1993.
However, 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

14
<PAGE>

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.

1994 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).

Mr. Wyatt received no salary increase in 1994. 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 CEO, who
wants to see continued improvement in shareholder returns before receiving any
base salary increase.

Mr. Wyatt's bonus for 1994 performance was $200,000. 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 (but above 1993 levels).

The Committee granted no stock options to Mr. Wyatt in 1994 (consistent with
past practices), considering the strongly expressed opinion of the CEO. Mr.
Wyatt and the Committee considered Mr. Wyatt's current level of stock ownership
in reaching this decision.

$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 1994 LTIP was 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 CEO is the only executive whose base salary
plus target bonus exceeds $1 million. In order to preserve Coastal's tax
deduction for the CEO's base salary plus bonus, Coastal has established a
nonqualified deferred compensation program for Mr. Wyatt. Under this program,
any annual incentive awards that bring Mr. Wyatt's cash compensation to a level
over $1 million will be deferred so that payments occur after Mr. Wyatt 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

15
<PAGE>

PENSION PLAN

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

PENSION PLAN TABLE
<TABLE>
<CAPTION>

YEARS OF CREDITED SERVICE
------------------------------------------------
<S> <C> <C> <C> <C> <C>
5-YEAR FINAL
AVERAGE PAY 15 YEARS 20 YEARS 25 YEARS 30 YEARS 35 YEARS
- ------------------- ------- ------- ------- ------- -------

$125,000........ $34,265 $45,687 $57,109 $68,531 $67,812
150,000........ 41,765 55,687 69,609 83,531 82,812
175,000........ 41,765 55,687 69,609 83,531 82,812
200,000........ 41,765 55,687 69,609 83,531 82,812
225,000........ 41,765 55,687 69,609 83,531 82,812
250,000........ 41,765 55,687 69,609 83,531 82,812
300,000........ 41,765 55,687 69,609 83,531 82,812
400,000........ 41,765 55,687 69,609 83,531 82,812
450,000........ 41,765 55,687 69,609 83,531 82,812
500,000........ 41,765 55,687 69,609 83,531 82,812
</TABLE>

(A) Compensation covered under the Pension Plan for employees of Coastal and the
Coastal Replacement Pension Plan generally includes only base salary and is
limited to $150,000 for 1994.

(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, 1994 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, 39 years, $469,834; Mr. Arledge, 14
years, $54,181; Mr. Cordes, 17 years, $74,523; Mr. King, 2 years, $9,474
(not vested) and Mr. Willson, 22 years, $98,357.

(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 years).

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).

16
<PAGE>

PERFORMANCE GRAPHS - SHAREHOLDER RETURN ON COMMON STOCK

FIVE-YEAR CUMULATIVE VALUES
$100 INVESTED 12/31/89
DIVIDENDS REINVESTED

[GRAPH APPEARS HERE]
<TABLE>
<CAPTION>
1989 1990 1991 1992 1993 1994
---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
Coastal $100 $99 $ 77 $ 76 $ 90 $ 84
S&P 500 $100 $97 $126 $136 $150 $152
Index(1)(2) $100 $81 $ 73 $ 85 $104 $ 96
</TABLE>

YEAR ENDED 12/31

(1) The Index is based on Value Line Diversified Natural Gas Group - the
Performance Graphs reflect total shareholder return weighted to reflect the
market capitalizations of the peer companies. The peer group is comprised
of: NorAm, Burlington Res., Columbia, Consolidated Nat. Gas, Eastern
Enterprises, Enron, Enserch, Equitable Res., KN Energy, Mitchell Energy,
National Fuel Gas, Panhandle Eastern, Seagull Energy, Sonat, Southwestern
Energy, Tenneco, Transco, Valero and Williams Cos.
(2) Coastal is excluded from the Index.

TEN-YEAR TWO MONTHS CUMULATIVE VALUES
$100 INVESTED 12/31/84
DIVIDENDS REINVESTED

[GRAPH APPEARS HERE]
<TABLE>
<CAPTION>
Two
Months
Ended 2/28
1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995
---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Coastal $100 $209 $190 $214 $283 $408 $403 $319 $313 $370 $345 $382
S&P 500 $100 $132 $156 $164 $192 $252 $245 $317 $343 $378 $380 $408
Index(1)(2) $100 $107 $105 $103 $120 $173 $145 $135 $161 $200 $186 $210
</TABLE>
YEAR ENDED 12/31

17
<PAGE>

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.

(a) Security ownership of certain beneficial owners.

The following is information, as of March 15, 1995, 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 15,
1995 is 112,960,388: consisting of 63,118 shares of $1.19 Cumulative
Convertible Preferred Stock, Series A (the "Series A Preferred Stock"), 83,756
shares of $1.83 Cumulative Convertible Preferred Stock, Series B (the "Series B
Preferred Stock"), 34,191 shares of $5.00 Cumulative Convertible Preferred
Stock, Series C (the "Series C Preferred Stock"), and 8,000,000 non-voting
shares of $2.125 Cumulative Preferred Stock, Series H, 104,363,374 shares of
Common Stock, and 415,949 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.

18
<PAGE>

The following table sets forth information, as of March 15, 1995, with
respect to each person known or believed by Coastal to be the beneficial owner,
who has or shares voting and/or investment power (other than as set forth
below), of more than five percent (5%) of any class of its voting securities.
<TABLE>
<CAPTION>

NAME AND ADDRESS PERCENT (%)
OF BENEFICIAL OWNER TITLE OF CLASS NUMBER OF SHARES OF CLASS (1)
- ------------------- -------------------- ---------------- -----------------
<S> <C> <C> <C>

O. S. Wyatt, Jr. Class A Common Stock 154,577 (2) 36.0
Chairman of the Board
of Coastal
Nine Greenway Plaza
Houston, Texas 77046-0995

Trustee/Custodian under the Common Stock 14,073,783 (3) 13.4
Thrift Plan, ESOP and Class A Common Stock 76,988 (3) 17.9
Pension Plan of Coastal
and its subsidiaries
Texas Commerce Bank
National Association
600 Travis, 10th Flr.
Houston, Texas 77002

Isabel H. Long Series A Preferred Stock 28,976 45.9
485 S. Parkview Ave.,
Columbus, Ohio 43209-1075

The DeZurik Family Series C Preferred Stock 34,191 (4) 100.0
c/o David DeZurik
2460 S.E. 8th St.
Pompano Beach, Florida 33062
</TABLE>
__________

(1) Class includes presently exercisable stock options held by directors and
executive officers.

(2) 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.

(3) The Trustee/Custodian is the record owner of these shares; and also is
the record owner of 953 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 voting instructions, the Trustee is permitted to
vote Thrift Plan shares on any matter, but has no authority to vote ESOP
shares or 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.

(4) 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.

19
<PAGE>

The following table sets forth information, as of March 15, 1995, regarding
each of the then current directors, including Class III 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, Marshall and McDade are Class III directors
whose terms expire in 1995.
<TABLE>
<CAPTION>

OFFICES WITH COASTAL NUMBER OF SHARES
NAME, (AGE), YEAR AND/OR PRINCIPAL BENEFICIALLY PERCENT (%)
FIRST BECAME DIRECTOR OCCUPATION TITLE OF CLASS OWNED(1) OF CLASS
- ---------------------- ---------------------------- --------------------- ------------------- -------------
<S> <C> <C> <C> <C>

O. S. Wyatt, Jr. Chairman of the Board and Common Stock 3,179,981 (2) 3.0
(70), 1955 Chief Executive Officer Class A Common Stock 154,577 (2) 36.0

Harold Burrow Vice Chairman of the Board; Common Stock 154,112 (2)
(80), 1973 Chairman of Colorado and ANR Class A Common Stock 13,602 3.2

David A. Arledge President and Common Stock 179,122
(50), 1988 Chief Operating Officer Class A Common Stock 13,940 3.2

John M. Bissell Chairman and Chief Executive Common Stock 4,576
(64), 1985 Officer of Bissell Inc. Class A Common Stock -0-

George L. Brundrett, Jr. Attorney; Former Senior Vice Common Stock 4,910
(73), 1973 President and General Class A Common Stock
Counsel of Coastal 2,290

Roy D. Chapin, Jr. Former Chairman and Common Stock 3,250 (2)
(79), 1988 Chief Executive Officer Class A Common Stock -0-
of American Motors
Corporation

James F. Cordes Executive Vice President; Common Stock 120,062
(54), 1985 President of ANR: President, Class A Common Stock -0-
Coastal Natural Gas Group

Roy L. Gates Retired; Ranching and Common Stock 4,095
(66), 1969 Investments Class A Common Stock 2,736

Kenneth O. Johnson Senior Vice President Common Stock 84,042
(74), 1988 Class A Common Stock 9,604 2.2

Jerome S. Katzin Retired Investment Banker Common Stock 41,803 (2)
(76), 1983 Class A Common Stock -0-

J. Howard Marshall, II Retired; Former Executive of Common Stock 11,924 (2)
(90), 1973 Allied Chemical Corporation, Class A Common Stock 600 (2)
Ashland Oil and Refining
Company and Signal Oil and
Gas Company

Thomas R. McDade Senior Partner, Law Firm of Common Stock 500
(62), 1993 McDade & Fogler L.L.P., Class A Common Stock -0-
Houston

L. D. Wooddy, Jr. Retired; Former President Common Stock 2,000
(68), 1992 of Exxon Pipeline Company Class A Common Stock -0-

All directors and executive officers as a group Common Stock 4,383,914 (3) 4.2
(34 persons, including the above) Class A Common Stock 200,700 (3) 46.7

</TABLE>
* 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 186,832 shares of Class A Common
Stock, which would constitute 44.9% of the shares of such class.

(1) Except for the shares referred to in Notes 2 and 3 below, and the shares
represented by presently exercisable stock options, the holders are
believed by Coastal to have sole voting and investment power as to the
shares indicated. Amounts include shares in Coastal ESOP and Thrift Plan,
and presently exercisable stock options held by Messrs. Burrow (14,189
shares of Common Stock), Arledge (160,503 shares of Common Stock and
13,868 shares of Class A Common Stock), Cordes (103,785 shares of Common
Stock) and Johnson (53,915 shares of Common Stock).

20
<PAGE>

(2) Includes shares owned by the spouse and a son of Mr. Wyatt (266,295
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), by the spouse of Mr.
Chapin (1,000 shares of Common Stock) and by the spouse of Mr. Katzin
(928 shares of Common Stock), as to which shares beneficial ownership is
disclaimed; also includes shares owned by the estate of the late Mrs.
Marshall (4,362 shares of Common Stock and 100 shares of Class A Common
Stock).

(3) Includes presently exercisable stock options to purchase 674,265 shares
of Common Stock and 13,868 shares of Class A Common Stock; also includes
280,339 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; also includes 4,362 shares of Common Stock and 100 shares of
Class A Common Stock owned by the estate named in Note 2 above. 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.

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. Marshall is a member of the Boards of Directors of Missouri-Kansas-Texas
Railroad Company and Presidio Oil Company.

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. Both of these subsidiaries of Coastal are subject to the reporting
requirements of the Securities Exchange Act of 1934, as amended.

21
<PAGE>

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, 1994 the Company had advanced $220.7
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.

22
<PAGE>

PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.

(a) The following documents are filed as part of this Annual Report or
incorporated herein by reference:

1. Financial Statements and Supplemental Information.

The following Consolidated Financial Statements of Colorado and
Subsidiaries and Supplemental Information are included in response to Item
8 hereof on the attached pages as indicated:
<TABLE>
<CAPTION>

Page
----
<S> <C>

Independent Auditors' Report............................................................... F-5
Consolidated Balance Sheet at December 31, 1994 and 1993................................... F-6
Statement of Consolidated Earnings for the Years Ended December 31, 1994, 1993 and 1992.... F-8
Statement of Consolidated Retained Earnings and Additional Paid-In Capital for the Years
Ended December 31, 1994, 1993 and 1992.................................................... F-8
Statement of Consolidated Cash Flows for the Years Ended December 31, 1994, 1993 and 1992.. F-9
Notes to Consolidated Financial Statements................................................. F-10
Supplemental Information on Oil and Gas Producing Activities (Unaudited)................... F-22
</TABLE>

2. Financial Statement Schedules.

Schedules are omitted as not applicable or not required, or the
required information is shown in the Consolidated Financial Statements or
Notes thereto.

3. Exhibits.

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

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

(3.3)+ Certificate of Amendment of Certification of Incorporation
of the Company (Exhibit 3.1 to the Company's Annual Report
on Form 10-K for the fiscal year ended December 31, 1989).

(4) With respect to instruments defining the rights of holders
of long-term debt, the Company will furnish to the
Securities and Exchange Commission any such document on
request.

(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,
1994.

23
<PAGE>

POWER OF ATTORNEY

Each person whose signature appears below hereby appoints David A. Arledge,
Dan A. Homec and Austin M. O'Toole and each of them, any one of whom may act
without the joinder of the others, as his attorney-in-fact to sign on his behalf
and in the capacity stated below and to file all amendments to this Annual
Report on Form 10-K, which amendment or amendments may make such changes and
additions thereto as such attorney-in-fact may deem necessary or appropriate.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.

COLORADO INTERSTATE GAS COMPANY
(Registrant)

By: JON R. WHITNEY
--------------------------------
Jon R. Whitney
President
March 29, 1995

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, 1995

By: JON R. WHITNEY
--------------------------------
Jon R. Whitney
President, Chief Executive Officer and Director
March 29, 1995

By: DAVID A. ARLEDGE
--------------------------------
David A. Arledge
Principal Financial Officer and Director
March 29, 1995

By: DAN A. HOMEC
--------------------------------
Dan A. Homec
Assistant Vice President and
Principal Accounting Officer
March 29, 1995

24
<PAGE>

By: RICHARD L. ANDERSON By: ROGER L. OGDEN
---------------------------- ----------------------------
Richard L. Anderson Roger L. Ogden
Director Director
March 29, 1995 March 29, 1995

By: JAMES F. CORDES By: PAUL W. POWERS
---------------------------- ----------------------------
James F. Cordes Paul W. Powers
Director Director
March 29, 1995 March 29, 1995

By: PETER J. KING, JR. By: WILLIAM B. TUTT
---------------------------- ----------------------------
Peter J. King, Jr. William B. Tutt
Director Director
March 29, 1995 March 29, 1995

By: REBECCA H. NOECKER By: O. S. WYATT, JR.
---------------------------- ----------------------------
Rebecca H. Noecker O. S. Wyatt, Jr.
Director Director
March 29, 1995 March 29, 1995

25
<PAGE>

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS

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>

1994 1993 1992
------ ----- ------
<S> <C> <C> <C>
Cash flow from operating activities to capital expenditures and debt
service requirements.................................................. 374.5% 80.0% 105.2%

Debt to total capitalization.......................................... 30.3% 33.3% 27.1%

Times interest earned (before tax).................................... 7.4 6.5 7.2
</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 1992 through 1994 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 $195.7 million in 1994 and
$77.6 million in 1993. Pre-payments for gas supply and settlement of natural gas
contract disputes required investments of $28 thousand in 1994 and $7.1 million
in 1993. Liquidity needs were met in 1994 by internally generated funds.

The Company has adopted a capital expenditure budget of approximately $71.3
million for 1995, an increase from the capital additions of $52.3 million in
1994. The anticipated increase in 1995 is the result of a $24.6 million increase
for natural gas projects partially offset by a $5.6 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, 1994, the Company and
certain affiliates could incur approximately $770 million of additional
indebtedness. For the Company and such affiliates to incur indebtedness for
borrowed money in excess of this amount, approximately $350 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, 1994, the Company had advanced $220.7 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.

The Company adopted FAS No. 112, "Employers' Accounting for Postemployment
Benefits", effective January 1, 1994. This standard covers the accounting for
estimated costs of benefits provided to former or inactive employees before
their retirement. The effect of this new standard did not have a material effect
on the Company's consolidated financial position or results of operations.

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 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.

F-1
<PAGE>

The Comprehensive Environmental Response, Compensation and Liability Act,
also known as "Superfund", as reauthorized, imposes liability, without regard to
fault or the legality of the original act, for disposal of a "hazardous
substance." 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.

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

1994 1993
---- ----

Natural gas................... $(64) $35
Exploration and production.... 6 4
Adjustments and eliminations.. 5 (3)
----- ---
$ (53) $36
===== ===
</TABLE>

NATURAL GAS

On April 8, 1992, the FERC issued Order 636 which required significant
changes in the services provided by interstate natural gas pipelines (see Note
10 of the Notes to Consolidated Financial Statements). The Company's
restructured services became effective October 1, 1993, and the Company now
offers a wide range of "unbundled" storage, transportation and balancing
services. Colorado's gas sales contracts have been unbundled and such sales are
now made at the producer wellhead. Gas sales contracts extend through September
30, 1996, but provide for reduced customer purchases to be made each year.

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.

1993 Versus 1992. Revenues from natural gas operations increased in 1993 due
to the $35 million sale of storage gas inventory, increased transportation and
gathering revenues of $34 million and increased extracted products revenue of $4
million offset by lower sales prices of $23 million and a $15 million decrease
resulting from reduced sales volumes.

The daily average volumes of natural gas sold were 259 MMcf, 272 MMcf and 287
MMcf for 1994, 1993 and 1992, 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 the provisions of Order 636. At this time, however, the
magnitude of those conversions cannot be estimated with reasonable certainty.
Transportation volumes increased by 9% in 1994 over the 1993 level and are
expected to increase slightly in 1995.

F-2
<PAGE>

EXPLORATION AND PRODUCTION

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

1993 Versus 1992. Revenues from exploration and production increased in 1993
as natural gas volumes generated a $4 million increase and natural gas prices
increased by $1 million, partially offset by decreases of $1 million.

OTHER INCOME - NET

The increase in 1994 and the decrease in 1993 primarily reflect changes in
interest income resulting from loans to affiliated companies.

COST OF GAS SOLD

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 other increases of $3 million.

1993 Versus 1992. The increase in 1993 was due primarily to increased
transportation, gathering and exchange gas costs of $17 million and storage gas
costs associated with the sale of storage gas inventory pursuant to Order 636,
net of injection/withdrawals in the amount of $11 million, partially offset by
other decreases of $1 million.

OPERATION AND MAINTENANCE

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.

1993 Versus 1992. Operation and maintenance expenses increased in 1993 due
primarily to increased property and production taxes of $3 million, increased
professional services of $2 million, increased gas used costs of $2 million and
other increases of $1 million.

DEPRECIATION, DEPLETION AND AMORTIZATION

1994 Versus 1993. Depreciation, depletion and amortization increased $5
million in 1994 due primarily to increased production volumes in the exploration
and production segment and an increase in the natural gas segment's depreciable
plant.

1993 Versus 1992. Depreciation, depletion and amortization increased $8
million in 1993 due primarily to an increase in the natural gas segment's
depreciable plant and increased production volumes in the exploration and
production segment.

OPERATING PROFIT

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

INCREASE (DECREASE)
FROM PRIOR YEAR
-------------------
<S> <C> <C>

1994 1993
----- -------
Natural gas................. $ 5 $ (7)
Exploration and production.. 2 -
----- -------
$ 7 $ (7)
===== =======

</TABLE>

F-3
<PAGE>

NATURAL GAS

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.

1993 Versus 1992. The natural gas segment's operating profit decrease in 1993
is due to increased gas related costs of $27 million, increased operation and
maintenance expenses of $6 million, increased depreciation, depletion and
amortization expenses of $6 million and other increases of $3 million partially
offset by increased operating revenues of $35 million.

EXPLORATION AND PRODUCTION

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.

1993 Versus 1992. The exploration and production segment's operating profit
was unchanged from 1992 as increased revenues of $4 million were offset by
increases of $2 million for operation and maintenance expenses and $2 million
for depreciation, depletion and amortization.

INTEREST EXPENSE

The decrease in both 1994 and 1993 is primarily due to lower average debt
outstanding partially offset by increases 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 33% in 1994 and 32% in 1993 and 1992.

F-4
<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, 1994 and 1993, 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, 1994. 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, 1994 and 1993, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1994 in conformity with generally accepted accounting principles.

As discussed in Note 8 to the consolidated financial statements, in 1993 the
Company changed its method of accounting for postretirement benefits other than
pensions to conform with Statement of Financial Accounting Standards No. 106.

DELOITTE & TOUCHE LLP

Denver, Colorado
February 2, 1995

F-5
<PAGE>

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

December 31,
----------------------
ASSETS 1994 1993
---------- ----------
<S> <C> <C>

Plant, Property and Equipment, at cost:
Gas pipeline.......................................... $1,016,188 $ 980,839
Gas and oil properties, at full-cost.................. 144,442 139,757
---------- ----------
1,160,630 1,120,596

Accumulated depreciation, depletion and amortization.. 635,300 601,890
---------- ----------
525,330 518,706
---------- ----------

Current Assets:
Cash.................................................. 372 704
Receivables........................................... 118,353 172,787
Receivables from affiliates........................... 246,609 148,180
Inventories........................................... 9,154 9,545
Prepaid expenses...................................... 628 979
Current portion of deferred income taxes.............. 43,760 23,539
---------- ----------
418,876 355,734
---------- ----------

Other Assets:
Other deferred charges................................ 17,905 27,187
---------- ----------

$ 962,111 $ 901,627
========== ==========
</TABLE>

See Notes to Consolidated Financial Statements.

F-6
<PAGE>

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

December 31,
------------------
STOCKHOLDERS' EQUITY AND LIABILITIES 1994 1993
---- ----
<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........................................................ 364,827 311,451
-------- --------
411,423 358,047
-------- --------

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

Debt:
Long-term debt........................................................... 179,225 179,145
-------- --------

Current Liabilities:
Accounts payable and accrued expenses.................................... 248,287 233,802
Accounts payable to affiliates........................................... 14,389 43,786
Taxes on income.......................................................... 19,013 1,275
-------- --------
281,689 278,863
-------- --------

Deferred Credits:
Deferred income taxes.................................................... 84,576 80,684
Other.................................................................... 4,642 4,332
-------- --------
89,218 85,016
-------- --------

$962,111 $901,627
======== ========
</TABLE>

See Notes to Consolidated Financial Statements.

F-7
<PAGE>

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

<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------
1994 1993 1992
-------- -------- --------
<S> <C> <C> <C>
Revenues:
Operating revenues:
Nonaffiliates........................... $333,113 $376,937 $353,777
Affiliates.............................. 52,176 61,077 48,443
-------- -------- --------
385,289 438,014 402,220
Other income-net.......................... 8,735 7,318 17,433
-------- -------- --------
394,024 445,332 419,653
-------- -------- --------
Costs and Expenses:
Cost of gas sold:
Nonaffiliates........................... 46,729 119,759 89,351
Affiliates.............................. 6,292 8,104 11,663
-------- -------- --------
53,021 127,863 101,014
Operation and maintenance................. 159,223 148,351 139,890
Depreciation, depletion and amortization.. 41,655 36,345 28,137
Interest expense.......................... 18,932 20,426 20,876
Taxes on income........................... 42,686 39,169 45,661
-------- -------- --------
315,517 372,154 335,578
-------- -------- --------

Net Earnings............................... $ 78,507 $ 73,178 $ 84,075
======== ======== ========

</TABLE>

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

Year Ended December 31,
----------------------------
1994 1993 1992
-------- -------- --------
<S> <C> <C> <C>
Retained Earnings:
Beginning balance....................... $311,451 $478,804 $457,364
Net earnings........................... 78,507 73,178 84,075

Less dividends:
Preferred stock:
5.50% Series........................ 31 31 35
Common stock......................... 25,100 240,500 62,600
-------- -------- --------
25,131 240,531 62,635
-------- -------- --------

Ending balance.......................... $364,827 $311,451 $478,804
======== ======== ========

Additional Paid-In Capital:
Beginning balance....................... $ 19,035 $ 19,035 $ 19,021
Gain on redemption of preferred stock.. - - 14
-------- -------- --------

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

See Notes to Consolidated Financial Statements.

F-8
<PAGE>

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

Year Ended December 31,
----------------------------------
1994 1993 1992
---------- ---------- ----------
<S> <C> <C> <C>

Net Cash Flow From Operating Activities:
Net earnings...................................................... $ 78,507 $ 73,178 $ 84,075
Add (subtract) items not requiring (providing) cash:
Depreciation, depletion and amortization........................ 41,655 36,345 28,137
Deferred income taxes........................................... (17,002) 9,840 3,702
Producer contract reformation cost recoveries................... 3,056 1,245 2,977
Other........................................................... 8,511 (11,043) 9,294
Working capital and other changes, excluding changes relating to
cash and non-operating activities:
Accounts receivable............................................. 54,434 (49,639) (16,741)
Receivables from affiliates..................................... 14,821 (8,985) (12,449)
Inventories..................................................... 391 (986) 528
Prepaid expenses................................................ 351 35,052 7,769
Accounts payable and accrued expenses........................... 14,485 (8,354) 40,588
Accounts payable to affiliates.................................. (21,203) 11,673 3,865
Taxes on income................................................. 17,738 (10,713) 17,318
--------- --------- ---------

195,744 77,613 169,063
--------- --------- ---------

Cash Flow from Investing Activities:
Purchases of plant, property and equipment........................ (52,263) (72,433) (152,504)
Proceeds from sale of plant, property and equipment............... 1,187 1,331 3,056
Investments - other............................................... 1,226 (488) (800)
Net (increase) decrease in notes receivable from associated
companies........................................................ (113,250) 249,690 48,494
Gas supply prepayments and settlements............................ (28) (7,121) (2,416)
Recovery of gas supply prepayments................................ 375 9,005 4,675
--------- --------- ---------

(162,753) 179,984 (99,495)
--------- --------- ---------

Cash Flow from Financing Activities:
Mandatory redemption of preferred stock........................... - - (350)
Premium paid on reacquisition of debt............................. - (166) -
Payments to retire long-term debt................................. - (24,400) (8,200)
Dividends paid.................................................... (33,323) (232,336) (62,639)
--------- --------- ---------

(33,323) (256,902) (71,189)
--------- --------- ---------

Net Increase (Decrease) in Cash.................................... (332) 695 (1,621)

Cash at Beginning of Year.......................................... 704 9 1,630
--------- --------- ---------

Cash at End of Year................................................ $ 372 $ 704 $ 9
========= ========= =========
</TABLE>

See Notes to Consolidated Financial Statements.

F-9
<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 Company is regulated by and 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."

- - 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 $17.5 million, $20.3 million and $20.7 million in
1994, 1993 and 1992, respectively. Cash payments for income taxes amounted to
$41.9 million, $40.5 million and $22.5 million in 1994, 1993 and 1992,
respectively.

- - 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 $31.2 million and $52.6 million at December 31, 1994 and 1993,
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 is included in the cost of the natural gas
segment's additions and betterments. This cost amounted to $1.9 million, $1.2
million and $2.4 million in 1994, 1993 and 1992, 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.

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.
The unit-of-production method is utilized for depreciation, depletion and
amortization of oil and gas properties. The average amortization rate per
equivalent unit of a thousand cubic feet of gas production for oil and gas
properties was $0.96 for the year 1994 and $1.00 for the years 1993 and 1992.

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.

F-10
<PAGE>

- - 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.

- - Gain or Loss on Reacquired Debt

As required by the FERC, gain or loss on reacquired debt is deferred and
amortized over the remaining life of the related long-term indebtedness.

- - 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):

<TABLE>
<CAPTION>
1994 1993
---- ----
<S> <C> <C>
10% Senior Debentures, due 2005................... $179,225 $179,145
======== ========
</TABLE>

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, 1994, the Company and certain affiliates could incur approximately
$770 million of additional indebtedness. For the Company and such affiliates to
incur indebtedness for borrowed money in excess of this amount, approximately
$350 million of indebtedness under this agreement would need to be retired.

3. Take-or-Pay Obligations

The Consolidated Balance Sheet includes assets of $5.7 million and $13.2
million at December 31, 1994 and 1993, 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, 1994, the Company estimated that unresolved asserted and unasserted
producers' claims amounted to approximately $18.0 million. The remaining
disputes will be settled where possible and litigated if settlement is not
possible.

F-11
<PAGE>

At December 31, 1994, 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 $.8 million, $.7 million, $.7 million, $.6 million and $.6
million for the years 1995-1999, respectively, and $2.9 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 would be recoverable pursuant to FERC-
approved settlements with customers. Such provisions and accruals were not
material to the Company for the years 1994, 1993 and 1992.

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 $364.8 million of retained earnings were
available for dividends on the common stock of the Company at December 31, 1994.

5. Mandatory Redemption Preferred Stock

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

5.50% Cumulative Preferred Stock (Third Series) - Of the 150,000 shares
authorized and issued, 5,560 were outstanding as of December 31, 1994. The
remaining stock outstanding is due in 1997 at par value with an annual dividend
rate of 5.5%.

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, 1994 December 31, 1993
-------------------------- --------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- ---------------- ----------------- --------
(Thousands of Dollars)
<S> <C> <C> <C> <C>

Financial assets:
Cash.................................. $ 372 $ 372 $ 704 $ 704
Notes receivable from affiliates...... 220,703 220,703 107,453 107,453
Financial liabilities:
Long-term debt........................ 179,225 191,126 179,145 215,010
Mandatory redemption preferred stock.. 556 556 556 556
</TABLE>

F-12
<PAGE>

The carrying values of cash and the 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, 1994 and 1993, respectively, for new issues with similar
remaining maturities.

7. Taxes On Income

Provisions for income taxes are composed of the following (thousands of
dollars):
<TABLE>
<CAPTION>

Year Ended December 31,
---------------------------
1994 1993 1992
--------- ------- -------
<S> <C> <C> <C>

Current Income Taxes:
Federal................ $ 54,194 $25,986 $37,233
State.................. 5,494 3,343 4,726
-------- ------- -------
59,688 29,329 41,959
-------- ------- -------

Deferred Income Taxes:
Federal................ (15,439) 8,818 2,830
State.................. (1,563) 1,022 872
-------- ------- -------
(17,002) 9,840 3,702
-------- ------- -------

Taxes on Income......... $ 42,686 $39,169 $45,661
======== ======= =======
</TABLE>

Coastal and the Internal Revenue Service ("IRS") Appeals Office have settled
all contested adjustments to federal income tax returns filed for the years 1982
through 1984. Coastal's federal income tax returns filed for the years 1985
through 1987 have been examined by the IRS, and Coastal has received notice of
proposed adjustments to the returns for each of those years. Coastal currently
is contesting certain of these adjustments with the IRS Appeals Office.
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,
----------------------------
1994 1993 1992
-------- -------- --------
<S> <C> <C> <C>

Tax expense computed by applying the U.S. federal income
tax rate of 35% for 1994 and 1993 and 34% for 1992....... $42,407 $39,311 $44,110

Increases (reductions) in taxes resulting from:
State income tax cost.................................... 2,556 2,837 3,695
Tight sands gas credit................................... (4,344) (2,495) -
Other.................................................... 2,067 (484) (2,144)
------- ------- -------

Taxes on Income........................................... $42,686 $39,169 $45,661
======= ======= =======
</TABLE>

F-13
<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,
--------------------
1994 1993
--------- ---------
<S> <C> <C>

Excess of book basis over tax basis of plant, property and equipment.. $ 80,037 $ 76,573
AFUDC equity income tax gross-up pursuant to FAS No. 109.............. 4,620 3,676
Other................................................................. (81) 435
-------- --------
Deferred tax liabilities............................................. 84,576 80,684
-------- --------

Provisions for rate refunds and contested claims...................... (32,547) (22,449)
Recoverable regulatory costs and accrued expenses..................... (9,573) (213)
Inventory adjustments................................................. (393) (581)
Other................................................................. (1,247) (296)
-------- --------
Deferred tax (assets)................................................ (43,760) (23,539)
-------- --------

Deferred income taxes................................................ $ 40,816 $ 57,145
======== ========
</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, 1994, the Plan did not have an unfunded accumulated benefit obligation.
Colorado made no contributions to the Plan for 1994, 1993 or 1992. 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 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 $2.8 million for each of the years 1994 and 1993 and
$2.6 million for 1992.

The Company provides certain health care and life insurance benefits for
retired employees. Effective January 1, 1993, the Company adopted FAS No. 106,
"Employers' Accounting for Postretirement Benefits Other Than Pensions" ("FAS
No. 106"). FAS No. 106 requires the Company to accrue the estimated cost of
retiree benefit payments during the years the employee provides services. The
Company previously expensed the cost of these benefits, which are principally
health care, as claims were incurred. FAS No. 106 allows recognition of the
cumulative effect of the liability in the year of the adoption or the
amortization of the obligation over a period of up to twenty years. The Company
elected to recognize the initial postretirement benefit obligation of
approximately $18.2 million over a period of twenty years. Recognition of FAS
No. 106 cost is determined by currently effective rates as filed with the FERC.
The difference between actuarially determined FAS No. 106 costs and the level of
costs collected in rates is reflected as a deferred regulatory amount.

F-14
<PAGE>

The following tables set forth the accumulated postretirement benefit asset
recognized in the Company's Consolidated Balance Sheet and the benefit cost for
the years ended December 31, 1994 and 1993 (millions of dollars):
<TABLE>
<CAPTION>

December 31,
----------------
1994 1993
------- -------
<S> <C> <C>

Accumulated postretirement benefit obligation:

Retirees...................................................................... $(10.4) $(15.2)
Fully eligible plan participants.............................................. (.6) (2.4)
Other active plan participants................................................ (4.4) (3.5)
------ ------
(15.4) (21.1)

Plan assets at fair value..................................................... 3.4 2.1
------ ------

Accumulated postretirement benefit obligation in excess of plan assets......... (12.0) (19.0)
Unrecognized net transition obligation......................................... 16.3 17.3
Unrecognized net (gain) loss from past experience different from that assumed.. (4.0) 1.7
------ ------
Postretirement benefit asset included in consolidated balance sheet............ $ .3 $ -
====== ======

December 31,
---------------
1994 1993
------ ------

Net postretirement benefit cost consisted of the following components:

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

The assumed health care cost trend rate used in measuring the accumulated
postretirement benefit obligation was 12.0% in 1994, declining gradually to 6.0%
by the year 2005. The assumed health care cost trend rate used in measuring the
accumulated postretirement benefit obligation was 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, 1994 and the net postretirement health care cost by approximately
4.01%. The assumed discount rate used in determining the accumulated
postretirement benefit obligation was 8.75%.

The Company adopted FAS No. 112, "Employers' Accounting for Postemployment
Benefits" effective January 1, 1994. This standard covers the accounting for
estimated costs of benefits provided to former or inactive employees before
their retirement. The implementation of the new standard did not have a material
effect on the Company's consolidated financial position or results of
operations.

9. Commitments

The Company and its subsidiaries had rental expense of approximately $7.3
million, $9.0 million and $9.7 million in 1994, 1993 and 1992, respectively
(excluding leases covering natural resources). The aggregate minimum lease
payments under existing noncapitalized long-term leases are estimated to be $4.5
million, $3.6 million, $1.7 million, $1.6 million, and $.9 million for the
years 1995-1999, respectively, and $1.1 million thereafter.

F-15
<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):
<TABLE>
<CAPTION>

<S> <C>
1995......... $ 4,300
1996......... 4,200
1997......... 4,200
1998......... 3,700
1999......... 3,700
Later years.. 14,700
</TABLE>

The Company expensed approximately $4.6 million related to the minimum
payments under this agreement in 1994.

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-16
<PAGE>

11. Quarterly Results of Operations (Unaudited)

The results of operations by quarter for the years ended December 31, 1994
and 1993 were (thousands of dollars):
<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>

<TABLE>
<CAPTION>
1993 Quarter Ended
----------------------------------------
March 31, June 30, Sept. 30, Dec. 31,
--------- ------- -------- --------
<S> <C> <C> <C> <C>
Revenues......................... $136,289 $86,041 $106,651 $116,351
Cost of gas sold................. 51,288 10,337 31,362 34,876
-------- ------- -------- --------
Revenues less cost of gas sold.. 85,001 75,704 75,289 81,475
Other costs and expenses......... 62,008 59,321 60,832 62,130
-------- ------- -------- --------
Net earnings.................... $ 22,993 $16,383 $ 14,457 $ 19,345
======== ======= ======== ========

</TABLE>

12. Segment Reporting

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

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

Gas and oil exploration and production operations involve primarily the
development and production of natural gas, crude oil, condensate and natural gas
liquids.

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-17
<PAGE>

The Company's operating revenues and operating profit for the years ended
December 31, 1994, 1993 and 1992, and identifiable assets as of December 31,
1994, 1993 and 1992, by segment, are shown below (thousands of dollars):
<TABLE>
<CAPTION>

Operating Operating Identifiable
Revenues Profit Assets
---------- ---------- ------------

1994
- ----
<S> <C> <C> <C>
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
======== ======== ==========

1992
- ----

Natural gas.................................... $397,737 $134,749 $1,037,840
Exploration and production..................... 14,463 2,739 59,338
Adjustments and eliminations................... (9,980) - -
-------- -------- ----------
Segment totals............................... 402,220 137,488 1,097,178
Other income-net............................... 17,433 17,433 -
Corporate general and administrative expenses.. - (4,309) -
Interest....................................... - (20,876) -
Income taxes................................... - (45,661) -
-------- -------- ----------
Consolidated Totals.......................... $419,653 $ 84,075 $1,097,178
======== ======== ==========
</TABLE>

F-18
<PAGE>

Capital expenditures and depreciation, depletion and amortization expense by
segment for the years ended December 31, 1994, 1993 and 1992, were (thousands of
dollars):
<TABLE>
<CAPTION>

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

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

1992
----

Natural gas................. 132,642 20,471
Exploration and production.. 19,862 7,666

</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 (thousands of dollars):

Year Ended December 31,
-------------------------------
1994 1993 1992
---- ---- ----
<S> <C> <C> <C>

Public Service Company of Colorado......... $198,002 $201,505 $207,300
======== ======== ========
</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, 1994, 1993 and 1992, respectively. 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-19
<PAGE>

13. Transactions with Affiliates

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

1994 1993 1992
------------------ --------------------- ---------------------
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 /1/................... $ - - % $ 6,548 4.9% $ 5,457 6.0%
Coastal Chem, Inc.......................... 2,522 1.3 2,711 2.0 2,145 2.4
Coastal Gas Marketing Company.............. 10,582 5.4 8,438 6.4 9,577 10.5
Coastal Oil & Gas Corporation /2/.......... 6,753 3.5 7,686 5.8 - -

Extracted Products and Gas Processing -
Coastal Refining & Marketing, Inc.......... $28,991 96.0% $ 32,597 92.4% $ 28,173 92.3%
Coastal States Trading, Inc................ 923 3.1 869 2.5 717 2.4

Incidental Gasoline, Oil and Condensate
Sales -
Coastal Refining & Marketing, Inc.......... $ 857 23.5% $ 905 34.2% $ 675 20.1%
Coastal States Trading, Inc................ 1,185 32.5 1,219 46.1 1,592 47.4

Contract Storage -
Coastal Chem, Inc./1/...................... $ -- --% $ 74 2.5% $ 98 8.6%
Coastal Gas Marketing Company.............. 456 4.6 30 1.0 9 .8

Miscellaneous --
Coastal Refining & Marketing, Inc./3/...... $ 194 10.3% $ -- --% $ -- --%

Costs and Expenses
- ------------------
Gas Purchases -
Coastal Gas Marketing Company.............. $ 1,582 1.7% $ 2,755 2.1% $ 5,143 3.1%
Coastal Limited Ventures, Inc.............. 205 .2 374 .3 1,019 .6
Coastal Oil & Gas Corporation.............. 4,505 4.9 4,975 3.9 5,501 3.3

Gathering, Transportation and Compression -
WIC........................................ $ 4,934 55.3% $ 5,362 51.2% $ 4,965 41.8%
- ----------------------------
</TABLE>
/1/ The 1994 amounts were immaterial.
/2/ The 1992 amounts were immaterial.
/3/ The 1993 and 1992 amounts were immaterial.

Services provided by the Company at cost for affiliated companies were $8.3
million for 1994, $7.9 million for 1993 and $8.1 million for 1992. Services
provided by affiliated companies for the Company at cost were $7.7 million for
1994, $8.1 million for 1993 and $7.9 million for 1992. The services provided by
the Company to affiliates, and by affiliates to the Company, primarily reflect
the allocation of costs relating to the sharing/operating of facilities and
general and administrative functions. Such costs are allocated using a three
factor formula consisting of revenue, property and payroll, or other methods
which have been applied on a reasonable and consistent basis.

In 1989, the Company entered into two separate five-year lease agreements
with ANR Western Storage Company, an affiliate, for the rental of certain
pipeline facilities. Rental expense of approximately $1.4 million for 1994, $1.5
million in 1993 and $1.6 million in 1992 was recorded in conjunction with the
terms of the lease agreements.

F-20
<PAGE>

In 1992, the Company entered into a five-year lease agreement with ANR
Production Company, an affiliate, for the rental of certain pipeline facilities.
Annual rental expense of approximately $.2 million was recorded in 1994, 1993
and 1992 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, 1994, the Company had advanced $220.7
million to associated companies at a market rate of interest. Such amount is
repayable on demand.

F-21
<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.

ESTIMATED QUANTITIES OF PROVED RESERVES
<TABLE>
<CAPTION>

Natural Gas Exploration
Company-Owned Reserves Systems and Production
- ---------------------- -------------- ----------------------------------
Developed Developed Undeveloped Total
-------------- ---------------- ---------------- ----------------
<S> <C> <C> <C> <C>

Natural Gas-Proved (MMcf):
- ---------------------------

1994..................... 334,597 76,917 2,598 414,112
1993..................... 379,795 87,905 8,088 475,788
1992..................... 418,831 88,631 7,687 515,149

Oil, Condensate and NGL-Proved (000 barrels):
- -------------------------------------------------

1994..................... 11 409 3 423
1993..................... 7 385 26 418
1992..................... 14 341 35 390

</TABLE>

Changes in proved reserves since the end of 1991 are shown in the following
table:

Natural Gas Oil, Condensate and NGL
(MMcf) (000 barrels)
----------------------------- ----------------------------------
Natural Exploration Natural Exploration
and Gas Gas and
Total Proved Reserves Systems Production Systems Production
- --------------------------- ---------- ---------------- ----------------- ---------------
<S> <C> <C> <C> <C>

Total, end of 1991......... 456,580 105,964 13 373
Production during 1992..... (47,754) (7,396) (2) (45)
Extensions and discoveries. - 9,849 - 43
Acquisitions............... - 2,310 - 16
Revisions of previous
estimates and other....... 10,005 (14,409) 3 (11)
------- ------- ----- -------
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
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
estimates and other....... 1,090 (7,024) 5 24
------- ------- ----- -------
Total, end of 1994......... 334,597 79,515 11 412
======= ======= ===== =======
</TABLE>

Total proved reserves for natural gas systems exclude storage gas and liquids
volumes. The natural gas systems storage gas volumes are 39,984, 41,012 and
55,284 MMcf and storage liquids volumes are approximately 172,000, 150,000 and
159,000 barrels at December 31, 1994, 1993 and 1992, respectively.

F-22
<PAGE>

CAPITALIZED COSTS RELATING TO EXPLORATION AND PRODUCTION ACTIVITIES
(thousands of dollars)

December 31, 1994 December 31, 1993
----------------------------- -------------------------------
Accumulated Accumulated
Depreciation, Depreciation,
Capitalized Depletion and Capitalized Depletion and
Proved and Unproved Properties Cost Amortization Cost Amortization
- -------------------------------- --------------- -------------- -------------- ------------------
<S> <C> <C> <C> <C>
Undeveloped..................... $ 753 $ 339 $ 506 $ 331
Developed....................... 143,689 104,069 139,251 91,687
-------- -------- -------- -------
$144,442 $104,408 $139,757 $92,018
======== ======== ======== =======
</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.

COSTS INCURRED IN OIL AND GAS ACQUISITION, EXPLORATION AND DEVELOPMENT
ACTIVITIES
(thousands of dollars)

Year Ended December 31,
-----------------------------
1994 1993 1992
-------- -------- -------
<S> <C> <C> <C>
Property acquisition costs............................................................. $ 5 $ 52 $ 1,789
Exploration costs...................................................................... 323 63 270
Development costs...................................................................... 6,717 4,123 17,824
</TABLE>

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

RESULTS OF OPERATIONS FOR EXPLORATION AND PRODUCTION ACTIVITIES
(thousands of dollars)

Year Ended December 31,
-----------------------------
1994 1993 1992
-------- -------- -------
<S> <C> <C> <C>
Revenues:
Sales................................................................................. $ 4,167 $ 3,133 $ 1,507
Transfers............................................................................. 21,984 16,607 12,295
-------- -------- -------
Total................................................................................ 26,151 19,740 13,802

Production costs....................................................................... (5,627) (5,265) (2,958)
Operating expenses..................................................................... (1,810) (1,621) (1,878)
Depreciation, depletion and amortization............................................... (14,675) (10,281) (7,666)
-------- -------- -------
4,039 2,573 1,300

Income tax benefit (expense)........................................................... 2,930 1,594 (442)
-------- -------- -------

Results of operations for producing activities (excluding corporate
overhead and interest costs).......................................................... $ 6,969 $ 4,167 $ 858
======== ======== =======
</TABLE>
The average amortization rate per equivalent Mcf was $0.96 in 1994 and $1.00
for both 1993 and 1992.

F-23
<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 future
revisions (thousands of dollars):
<TABLE>
<CAPTION>

At December 31,
-------------------------------------------------------------------------
1994 1993 1992
----------------------- ----------------------- -----------------------
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......... $235,101 $133,850 $298,859 $226,754 $331,418 $197,374
Future production and
development costs.......... (65,388) (51,623) (62,684) (59,499) (50,562) (55,492)
Future income tax expenses.. (57,958) (13,339) (81,827) (37,124) (95,491) (23,934)
-------- -------- -------- -------- -------- --------
Future net cash flows....... 111,755 68,888 154,348 130,131 185,365 117,948
10% annual discount for
estimated timing of cash
flows...................... (43,983) (22,358) (59,542) (45,605) (82,100) (41,251)
-------- -------- -------- -------- -------- --------
Standardized measure of
discounted future net
cash flows................. $ 67,772 $ 46,530 $ 94,806 $ 84,526 $103,265 $ 76,697
======== ======== ======== ======== ======== ========
</TABLE>

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

Sales and transfers, net of
production costs............... $(39,272) $(18,115) $(35,394) $(14,475) $(51,904) $(10,844)
Net changes in prices and
production costs............... (15,493) (31,746) (881) 14,805 11,899 11,906
Extensions and discoveries...... - 3,597 - 5,098 - 5,785
Acquisitions.................... - - - - - 1,190
Development costs incurred
during the period that
reduced estimated future
development costs.............. - 3,750 - 1,694 8,560 14,438
Revisions of previous quantity
estimates, timing and other.... 1,449 (17,781) 11,975 2,694 11,280 (13,707)
Accretion of discount........... 10,793 8,718 12,409 7,334 11,596 6,174
Net change in income taxes...... 15,489 13,581 3,432 (9,321) 2,058 (7,163)
-------- -------- -------- -------- -------- --------
Net change.................... $(27,034) $(37,996) $ (8,459) $ 7,829 $ (6,511) $ 7,779
======== ======== ======== ======== ======== ========
</TABLE>

None of the amounts include any value for storage gas and liquids which were
approximately 40 Bcf and 172 thousand barrels, respectively, at the end of 1994.

F-24
<PAGE>

EXHIBIT INDEX
<TABLE>
<CAPTION>

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

<S> <C>
(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.

(21)* Subsidiaries of the Company.

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

(27)* Financial Data Schedule.
</TABLE>

__________________________________

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

<PAGE>

EXHIBIT 21

SUBSIDIARIES OF COLORADO INTERSTATE GAS COMPANY

State of
Incorporation
-------------
<S> <C>
CIG Exploration, Inc...................................... Delaware
Colorado Water Supply Company............................. Delaware
Subsidiary:
Colorado Interstate Production Company................. Delaware
</TABLE>

<PAGE>

<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,
1994 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-31-1994
<PERIOD-END> DEC-31-1994
<CASH> 372
<SECURITIES> 0
<RECEIVABLES> 364,962
<ALLOWANCES> 0
<INVENTORY> 9,154
<CURRENT-ASSETS> 418,876
<PP&E> 1,160,630
<DEPRECIATION> 635,300
<TOTAL-ASSETS> 962,111
<CURRENT-LIABILITIES> 281,689
<BONDS> 179,225
<COMMON> 27,561
556
0
<OTHER-SE> 383,862
<TOTAL-LIABILITY-AND-EQUITY> 962,111
<SALES> 385,289
<TOTAL-REVENUES> 394,024
<CGS> 53,021
<TOTAL-COSTS> 253,899
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 18,932
<INCOME-PRETAX> 121,193
<INCOME-TAX> 42,686
<INCOME-CONTINUING> 78,507
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 78,507
<EPS-PRIMARY> 0
<EPS-DILUTED> 0

</TABLE>