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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the fiscal year ended December 31, 1996 or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from __________ to __________
Commission file number 1-4874
COLORADO INTERSTATE GAS COMPANY
(Exact name of registrant as specified in its charter)
Delaware 84-0173305
(State or other jurisdiction of I.R.S. Employer
incorporation or organization) Identification No.)
Two North Nevada Avenue
Colorado Springs, Colorado 80903-1727
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (719) 473-2300
---------------------------
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
------------------- -----------------------
10% Senior Debentures, due 2005 New York Stock Exchange
---------------------------
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months, and (2) has been subject to such filing
requirements for the past 90 days. Yes __X__ No _____
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
As of March 12, 1997, there were outstanding 10 shares of common stock of
the Registrant, $5.00 par value per share, its only class of common stock. None
of the voting stock of the Registrant is held by non-affiliates.
Documents incorporated by reference: None
<PAGE>
TABLE OF CONTENTS
Item No. Page
Glossary......................................................(ii)
PART I
1. Business...................................................... 1
Introduction.............................................. 1
Natural Gas System........................................ 1
Operations............................................ 1
General........................................... 1
Gas Sales, Storage and Transportation............. 2
Gas Gathering and Processing...................... 2
Competition....................................... 3
Gas System Reserves................................... 3
General........................................... 3
Reserves.......................................... 3
Reserves Dedicated to a Particular Customer....... 3
Regulations Affecting Gas System...................... 4
General........................................... 4
Rate Matters...................................... 4
Gas and Oil Exploration and Production.................... 5
Environmental............................................. 7
2. Properties.................................................... 7
3. Legal Proceedings............................................. 7
4. Submission of Matters to a Vote of Security Holders........... 8
PART II
5. Market for the Registrant's Common Equity and Related
Stockholder Matters........................................... 9
6. Selected Financial Data....................................... 9
7. Management's Discussion and Analysis of Financial
Condition and Results of Operations........................... 9
8. Financial Statements and Supplementary Data................... 9
9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure...................................... 9
PART III
10. Directors and Executive Officers of the Registrant............ 10
11. Executive Compensation........................................ 11
12. Security Ownership of Certain Beneficial Owners and
Management.................................................... 19
13. Certain Relationships and Related Transactions................ 22
PART IV
14. Exhibits, Financial Statement Schedules, and Reports on
Form 8-K...................................................... 23
(i)
<PAGE>
GLOSSARY
"AICPA" means American Institute of Certified Public Accountants
"ANR" means American Natural Resources Company
"ANR Pipeline" means ANR Pipeline Company
"Bcf" means billion cubic feet
"CIGFS" means CIG Field Services Company
"Coastal" means The Coastal Corporation
"Coastal Natural Gas" means Coastal Natural Gas Company
"Colorado" or the "Company" means Colorado Interstate Gas Company
and/or its subsidiaries
"FAS" means Statement of Financial Accounting Standards
"FASB" means Financial Accounting Standards Board
"FERC" means Federal Energy Regulatory Commission
"Huddleston" means Huddleston & Co., Inc., Houston, Texas - Volumes in the
Huddleston Report are at 14.65 pounds per square inch absolute and 60
degrees Fahrenheit
"Long tons" means weight measurement of 2,240 pounds
"Mcf" means thousand cubic feet
"MMcf" means million cubic feet
"NGA" means Natural Gas Act of 1938, as amended
"NGL" means natural gas liquids
"Order 636" means FERC Order No. 636 which required significant changes in
services provided by interstate natural gas pipelines, including the
unbundling of services
"WIC" means Wyoming Interstate Company, Ltd.
"Working gas" means that volume of gas available for withdrawal and use by the
Company's customers
NOTE: Unless otherwise noted, all natural gas volumes presented in this
Annual Report are stated at a pressure base of 14.73 pounds per square
inch absolute and 60 degrees Fahrenheit.
(ii)
<PAGE>
PART I
Item 1. Business.
INTRODUCTION
Colorado is a Delaware corporation organized in 1927. All of Colorado's
outstanding common stock is owned by Coastal Natural Gas, which is a
wholly-owned subsidiary of Coastal. Colorado owns and operates an interstate
natural gas pipeline system and also has gas and oil exploration and production
operations. At December 31, 1996, the Company had 979 employees.
The revenues and operating profit of the Company by industry segment for
each of the three years in the period ended December 31, 1996, and the related
identifiable assets as of December 31, 1996, 1995 and 1994, are set forth in
Note 12 of Notes to Consolidated Financial Statements included herein.
NATURAL GAS SYSTEM
OPERATIONS
General
The Company is involved in the production, gathering, processing,
transportation, storage and sale of natural gas. Colorado also contracts to
gather, process, transport and store natural gas owned by third parties.
Separately, Colorado purchases and produces natural gas and makes sales of such
gas at the wellhead principally to local gas distribution companies for resale.
Public Service Company of Colorado was the Company's only customer
accounting for revenue that equaled or exceeded 10% of the Company's
consolidated revenues for the years 1996, 1995 and 1994 (See Note 12 of Notes to
Consolidated Financial Statements.)
Colorado's gas transmission system extends from gas production areas in the
Texas Panhandle, western Oklahoma and western Kansas, northwesterly through
eastern Colorado to the Denver area, and from production areas in Montana,
Wyoming and Utah, southeasterly to the Denver area. The Company's gas gathering
and processing facilities are located throughout the production areas adjacent
to its transmission system. Most of the Company's gathering facilities connect
directly to its transmission system, but some gathering systems are connected to
other pipelines. The Company also has minor gathering facilities located in New
Mexico. Colorado owns four underground gas storage fields; three located in
Colorado, and one in Kansas.
The Company's principal transmission and storage pipeline facilities,
including certain facilities in the Panhandle Field of Texas ("Panhandle
Field"), at December 31, 1996 consisted of 4,123 miles of pipeline and 56
compressor stations with approximately 300,200 installed horsepower. At December
31, 1996, the design peak day delivery capacity of the transmission system was
approximately 2.0 Bcf per day. The underground storage facilities have a working
capacity of approximately 29 Bcf and a peak day delivery capacity of
approximately 775 MMcf.
Colorado's gathering facilities, excluding certain FERC regulated
facilities in the Panhandle Field, consist of 2,289 miles of gathering lines and
approximately 48,500 horsepower of compression. Colorado owned and operated five
gas processing plants in 1996. These plants, with a total operating capacity of
approximately 512 MMcf daily, recover mainly propane, butanes, natural gasoline,
sulfur and other by-products, which are sold to refineries, chemical plants and
other customers.
1
<PAGE>
On June 26, 1996, the FERC approved Colorado's request for authority to
transfer to its subsidiary, CIGFS, all of Colorado's gathering facilities except
for those in the Panhandle Field. The transferred facilities had a net book
value of approximately $42 million. The June 26, 1996 order further confirmed
that the facilities transferred to CIGFS would be considered non-jurisdictional.
The FERC issued a related order on September 26, 1996, accepting Colorado's
filing under Section 4 of the NGA confirming that Colorado no longer offered
gathering services through the transferred facilities. The FERC orders accepting
Colorado's spin-down and related Section 4 filings were not appealed and are now
final. Colorado completed the transfer to CIGFS effective October 1, 1996.
Gas Sales, Storage and Transportation
Beginning in October 1993, Colorado implemented Order 636 on its system and
as a result, Colorado's gas sales contracts have been "unbundled" and such sales
are now made at the producer wellhead. Colorado's unincorporated Merchant
Division conducts most of the Company's sales activity in the Order 636
environment. The gas sales volumes reported include those sales which continue
to be made by Colorado together with those of its Merchant Division.
Colorado has engaged in "open access" transportation and storage of gas
owned by third parties for several years. As a result of Order 636, the Company
continues to provide these services to third parties under individual contracts.
Such services are at rates that are within minimum and maximum levels approved
by the FERC.
Pursuant to an operating agreement with an affiliate, the Company operates
the newly completed Young Gas Storage Field located in northeastern Colorado.
When fully developed, the field will have a storage capacity of 5.3 Bcf with a
delivery rate of 200 MMcf per day. Such capacity is fully subscribed under
30-year contracts.
Colorado's deliveries for the years 1996, 1995 and 1994 were as follows:
Total System Daily Average
Year Deliveries System Deliveries
---- ------------ -----------------
(Bcf) (MMcf)
1996 475 1,298
1995 456 1,248
1994 436 1,195
Gas Gathering and Processing
Colorado provides gathering and processing services on an "unbundled" or
stand-alone basis. The Company's processing terms are not regulated by the FERC,
but Colorado is required to provide "open access" to its processing facilities.
The gathering that Colorado provides in the Panhandle Field continues to be
regulated by the FERC, and the Company is limited to charging rates between
minimum and maximum levels approved by the FERC. The gathering (and processing)
that Colorado's subsidiary, CIGFS, provides is not regulated by the FERC.
However, under the terms by which the Company obtained FERC approval to transfer
these facilities to CIGFS, CIGFS offered "default contracts" to all gathering
customers receiving service at the date of the transfer. Under the "default
contracts," CIGFS is required to honor the rates and terms of any pre-existing
gathering contracts that were in effect as of the transfer date between Colorado
and the customers for a period of two years. However, the "default contract"
obligation does not apply to new customers or new contracts entered into after
the date of the transfer.
The gas processing plants recovered approximately 66 million gallons of
liquid hydrocarbons in 1996 compared to 81 million gallons in 1995, and 88
million gallons in 1994, as well as 3,100 long tons of sulfur in 1996, compared
to 4,600 long tons in 1995 and 4,300 long tons in 1994. Additionally, Colorado
processed approximately 6 million gallons of liquid hydrocarbons owned by others
in 1996, 1995 and 1994.
The Company operates two helium processing facilities, one located in
eastern Colorado and the other in the western Oklahoma panhandle area. These
helium facilities are joint venture/partnership arrangements which are partially
owned by Company affiliates. The Company also operates two gas processing plants
for affiliates.
2
<PAGE>
Competition
Colorado has historically competed with interstate and intrastate pipeline
companies in the sale, transportation and storage of gas and with independent
producers, brokers, marketers and other pipelines in the gathering, processing
and sale of gas within its service areas. On October 1, 1993, the Company
implemented Order 636 on its system and, as a consequence, its gas sales
contracts have been "unbundled" at the producer wellhead. Order 636 also
mandated implementation of capacity release and secondary delivery point options
thus allowing a pipeline's firm transportation customers to compete with the
pipeline for firm and interruptible transportation and storage.
Natural gas competes with other forms of energy available to customers,
primarily on the basis of price paid by end users. These competitive forms of
energy include electricity, coal, propane and fuel oils. Changes in the
availability or price of natural gas or other forms of energy, as well as
changes in business conditions, conservation, legislation or governmental
regulations, capability to convert to alternate fuels, changes in rate
structure, taxes and other factors may affect the demand for natural gas in the
areas served by Colorado.
GAS SYSTEM RESERVES
General
Colorado, primarily through its unincorporated Merchant Division, continues
to make natural gas sales to a number of customers. Colorado will meet its sales
commitments primarily with purchases from third parties under existing contracts
and with production of Company-owned reserves. Colorado will also make spot gas
purchases, if needed.
Reserves
The table below represents estimates of the Company's owned or controlled
reserves as of December 31, 1996, 1995, and 1994, as prepared by Huddleston,
Colorado's independent engineers.
<TABLE>
<CAPTION>
1996 1995 1994
---- ---- ----
<S> <C> <C> <C>
Owned or controlled by Colorado (Bcf).................................... 307 346 383
</TABLE>
The estimates of owned or controlled gas reserves include quantities
economically recoverable over the productive life of existing wells and
quantities estimated to be recoverable in the future, either from completions in
other productive zones of existing wells or from additional wells to be drilled
in proven reservoirs currently controlled by Colorado. The independent
engineers' estimates of reserves are based upon new analyses or upon a review of
earlier analyses updated by production and field performance. The reserve
volumes reported represent those retained by Colorado as well as those assigned
to a subsidiary.
At December 31, 1996, Colorado maintained under its own account 2.7 Bcf of
natural gas in underground working storage for system balancing. The Company has
an additional 37.8 Bcf of base gas in its four owned storage fields. These
amounts reflect actual balances at December 31, 1996, and vary slightly from the
Huddleston report which includes estimates for November and December 1996.
Reserves Dedicated to a Particular Customer
Colorado is committed to sell gas to Mesa Operating Company ("Mesa"), a
customer, under a 1928 agreement as amended, from specific owned gas reserves in
the West Panhandle Field of Texas. Under an amendment which became effective
January 1, 1991, a cumulative 23% of the total net production may be taken for
customers other than Mesa.
3
<PAGE>
REGULATIONS AFFECTING GAS SYSTEM
General
Under the NGA, the FERC has jurisdiction over Colorado as to rates and
charges for the transportation and storage of natural gas and the construction
of new facilities, extension or abandonment of service and facilities, accounts
and records, depreciation and amortization policies and certain other matters.
In addition, the FERC has certificate authority over gas sales for resale in
interstate commerce, but under Order 636, has determined that it will not
regulate sales rates. Additionally, the FERC has asserted rate-regulation (but
not certificate regulation) over gathering services provided by interstate
pipeline companies such as Colorado.
Colorado is also subject to regulation with respect to safety requirements
in the design, construction, operation and maintenance of its interstate gas
transmission and storage facilities by the Department of Transportation.
Additionally, the Company is subject to similar safety requirements from the
Department of Labor's Occupational Safety and Health Administration related to
its processing plants. Operations on United States government land are regulated
by the Department of the Interior.
Rate Matters
On January 31, 1996, the FERC issued a "Statement of Policy and Request for
Comments" ("Policy Statement") with respect to a pipeline's ability to negotiate
and charge rates for individual customers' services which would not be limited
to the "cost-based" rates established by the FERC in traditional rate making.
Under this Policy Statement, a pipeline and a customer will be allowed to
negotiate a contract which provides for rates and charges that exceed the
pipeline's posted maximum tariff rates, provided that the shipper agreeing to
such negotiated rates has the ability to elect to receive service at the
pipeline's posted maximum rate (known as a "recourse rate"). To implement this
Policy Statement, a pipeline must make an initial tariff filing with the FERC to
indicate that it intends to contract for services under this Policy Statement,
and subsequent tariff filings will indicate each time the pipeline negotiates a
rate for service which exceeds the recourse rate. The FERC is also considering
comments on whether this "negotiated rate" program should be extended to other
terms and conditions of pipeline transportation services.
On July 31, 1996, the FERC also issued a "Notice of Proposed Rulemaking"
requesting comments on various aspects of secondary market transactions on
interstate natural gas pipelines, including the comparability of pipeline
capacity with released capacity.
On March 29, 1996, Colorado filed with the FERC under Docket No. RP96-190
to increase its rates by approximately $30 million annually and to realign
certain transportation services. On April 25, 1996, the FERC accepted the filing
to become effective October 1, 1996, subject to refund. In the event that the
case cannot be settled, a hearing before a FERC Administrative Law Judge is
currently scheduled for late 1997.
The FERC April 25, 1996 order also accepted tariff sheets filed by Colorado
to establish its rights to enter into negotiated rates consistent with the
negotiated rate Policy Statement. Colorado's tariff sheets became effective May
1, 1996, and continue to be effective despite the fact that certain parties have
sought judicial review of the FERC's actions with respect to Colorado's
negotiated rate provisions.
On June 26, 1996, the FERC approved Colorado's request for authority to
transfer to its subsidiary, CIGFS all of Colorado's gathering facilities except
for those in the Panhandle Field. The transferred facilities had a net book
value of approximately $42 million. The June 26, 1996 order further confirmed
that the facilities transferred to CIGFS would be considered non-jurisdictional.
The FERC issued a related order on September 26, 1996, accepting Colorado's
filing under Section 4 of the NGA confirming that Colorado no longer offered
gathering services through the transferred facilities. The FERC orders accepting
Colorado's spin-down and related Section 4 filings were not appealed and are now
final. Colorado completed the transfer to CIGFS effective October 1, 1996.
Certain of the above regulatory matters and other regulatory issues remain
unresolved among the Company, its customers, its suppliers and the FERC. The
Company has made provisions which represent management's assessment
4
<PAGE>
of the ultimate resolution of these issues. As a result, the Company anticipates
that these regulatory matters will not have a material adverse effect on its
consolidated financial position, results of operations or cash flows. While the
Company estimates the provisions to be adequate to cover potential adverse
rulings on these and other issues, it cannot estimate when each of these issues
will be resolved.
GAS AND OIL EXPLORATION AND PRODUCTION
The Company has domestic gas and oil production operations. The gas is
delivered primarily to Colorado's interstate gas pipeline system while the crude
oil and condensate are sold at the wellhead to oil purchasing companies at
prevailing market prices. The production of gas and oil is subject to regulation
in states in which the Company operates.
The following table shows gas, oil, condensate and natural gas liquids
production volumes of the Company, including quantities attributable to its
natural gas system, for the three years ended December 31, 1996:
<TABLE>
<CAPTION>
1996 1995 1994
---- ---- ----
<S> <C> <C> <C>
Exploration and Production
Gas (MMcf)...................................................... 12,304 10,703 14,758
Oil (000 barrels)............................................... 2 5 8
Condensate (000 barrels)........................................ 61 60 73
Natural Gas Liquids (000 barrels)............................... 51 2 -
Natural Gas System
Gas (MMcf)...................................................... 39,405 41,638 46,288
Oil (000 barrels)............................................... 23 15 -
Condensate (000 barrels)........................................ - 1 1
Natural Gas Liquids (000 barrels)............................... - - -
</TABLE>
The following table summarizes sales price and unit cost information of the
Company's exploration and production operations for the three years ended
December 31, 1996:
<TABLE>
<CAPTION>
1996 1995 1994
---- ---- ----
<S> <C> <C> <C>
Average sales price:
Gas - per Mcf................................................... $ 1.51 $ 1.08 $ 1.52
Oil - per barrel................................................ 19.91 16.47 14.80
Condensate - per barrel......................................... 21.39 17.34 16.04
Natural Gas Liquids - per barrel................................ 8.19 10.22 -
Average production cost per unit (equivalent Mcf).................... $ 0.35 $ 0.45 $ 0.37
</TABLE>
5
<PAGE>
Acreage held under gas and oil mineral leases as of December 31, 1996 is
summarized as follows:
<TABLE>
<CAPTION>
Undeveloped Developed
------------------------ -------------------------
Area Gross Net Gross Net
-------------------------------------------------------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Exploration and Production.............................. 65,734 16,791 103,880 48,149
Natural Gas System...................................... - - 264,712 261,363
----------- ----------- ----------- -----------
65,734 16,791 368,592 309,512
=========== =========== =========== ===========
</TABLE>
The net developed acreage is concentrated principally in Texas (79%),
Oklahoma (7%), Wyoming (6%) and Utah (6%). The net undeveloped acreage is
principally in Wyoming (49%), Montana (24%), Utah (11%) and Texas (10%).
Information on wells drilled in the three years ended December 31, 1996, is
summarized as follows:
<TABLE>
<CAPTION>
1996 1995 1994
------------------------ ------------------------ -------------------------
Gross Net Gross Net Gross Net
----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Exploration and Production
--------------------------
Development Wells
-----------------
Oil........................ - - - - - -
Gas........................ 5 1.86 7 2.44 19 7.68
Dry Holes.................. - - - - - -
----------- ----------- ----------- ----------- ----------- -----------
5 1.86 7 2.44 19 7.68
----------- ----------- ----------- ----------- ----------- -----------
Natural Gas System
------------------
Development Wells
-----------------
Oil........................ 2 2.00 - - - -
Gas........................ 8 8.00 1 1.00 3 3.00
Dry Holes.................. - - - - - -
----------- ----------- ----------- ----------- ----------- -----------
10 10.00 1 1.00 3 3.00
----------- ----------- ----------- ----------- ----------- -----------
Total.................. 15 11.86 8 3.44 22 10.68
=========== =========== =========== =========== =========== ===========
</TABLE>
Productive wells as of December 31, 1996 are as follows:
<TABLE>
<CAPTION>
Type of Well Gross Net
---------------------------------------------------------------------------------- ----------- -----------
<S> <C> <C>
Exploration and Production
Oil.......................................................................... 1 0.09
Gas.......................................................................... 329 201.42
----------- -----------
Total Exploration and Production...................................... 330 201.51
----------- -----------
Natural Gas System
Oil.......................................................................... 9 8.25
Gas.......................................................................... 675 670.86
----------- -----------
Total Natural Gas System.............................................. 684 679.11
----------- -----------
Total..................................................... 1,014 880.62
=========== ===========
</TABLE>
Information on Company-owned reserves of oil and gas is included herein
under "Supplemental Information on Oil and Gas Producing Activities (Unaudited)"
in Item 14(a)1 included herein.
6
<PAGE>
The Company competes with major integrated oil companies and independent
oil and gas companies for suitable prospects for oil and gas drilling
operations. The availability of a ready market for gas discovered and produced
depends on numerous factors frequently beyond the Company's control. These
factors include the extent of gas discovery and production by other producers,
crude oil imports, the marketing of competitive fuels, and the proximity,
availability and capacity of gas pipelines and other facilities for the
transportation and marketing of gas. The production and sale of oil and gas is
subject to a variety of federal and state regulations, including regulation of
production levels.
ENVIRONMENTAL
The Company's operations are subject to extensive and evolving federal,
state and local environmental laws and regulations which may affect such
operations and costs as a result of their effect on the construction, operation,
and maintenance of its pipeline facilities. The Company spent approximately $1.2
million on environmental capital projects in 1996 and anticipates annual
environmental capital expenditures of $1 to $2 million over the next several
years aimed at maintaining compliance with such laws and regulations.
Additionally, appropriate governmental authorities may enforce the laws and
regulations with a variety of civil and criminal enforcement measures, including
monetary penalties and remediation requirements.
The Comprehensive Environmental Response, Compensation and Liability Act,
also known as "Superfund", as reauthorized, imposes liability, without regard to
fault or the legality of the original act, for disposal of a "hazardous
substance." The Company is not presently, and has not been in the past, a
potentially responsible party ("PRP") in any "Superfund" waste disposal sites.
However, the Company has received notice from a committee formed from a group of
55 companies who are named as PRPs at one site requesting the Company pay a de
minimis share (approximately $36,000) of the associated clean-up costs.
Future information and developments will require the Company to continually
reassess the expected impact of all applicable environmental laws and
regulations. Compliance with all applicable environmental protection laws and
regulations is not expected to have a material adverse impact on the Company's
liquidity, consolidated financial position or results of operations.
Item 2. Properties.
Information on properties of Colorado is included in Item 1, "Business,"
included herein.
The real property owned by the Company in fee consists principally of sites
for compressor and metering stations and microwave and terminal facilities. With
respect to the four owned storage fields, the Company holds title to gas storage
rights representing ownership of, or has long-term leases on, various subsurface
strata and surface rights and also holds certain additional mineral rights.
Under the NGA, the Company may acquire by the exercise of the right of eminent
domain, through proceedings in U.S. District Courts or in state courts,
necessary rights-of-way to construct, operate and maintain pipelines and
necessary land or other property for compressor and other stations and equipment
necessary to the operation of pipelines.
Item 3. Legal Proceedings.
In December 1992, certain of Colorado's natural gas lessors in the West
Panhandle Field filed a complaint in the U.S. District Court for the Northern
District of Texas, claiming underpayment, breach of fiduciary duty, fraud and
negligent misrepresentation. Management believes that Colorado has numerous
defenses to the lessors' claims, including (i) that the royalties were properly
paid, (ii) that the majority of the claims were released by written agreement,
and (iii) that the majority of the claims are barred by the statute of
limitations. In March of 1995, the Trial Court granted a partial summary
judgment in favor of Colorado, holding that the four-year statute of limitations
had not been tolled, that the releases are valid, and dismissing all tort claims
and claims for breach of any duty of disclosure. The remaining claim for
underpayment of royalties was tried to a jury which, in May 1995, made findings
favorable to Colorado. On June 7, 1995, the Trial Court entered a judgment that
the lessors recover no monetary damages from Colorado and permanently
7
<PAGE>
estopping the lessors from asserting any claim based on an interpretation of the
contract different than that asserted by Colorado in the litigation. The
lessors' motion for a new trial is pending. On June 7, 1996, the same Plaintiffs
sued Colorado in state court in Amarillo, Texas for underpayment of royalties.
Colorado removed the second lawsuit to federal court which granted a stay of the
second lawsuit pending the outcome of the first lawsuit.
A natural gas producer has filed a claim on behalf of the U.S. government
in the U.S. District Court for the District of Columbia under the federal False
Claims Act. The Second Amended Complaint filed on May 24, 1996, against seventy
(70) defendants, including Colorado, alleges that the defendants' methods of
measuring the heating content and volume of natural gas purchased from
federally-owned or Indian properties have caused underpayment of royalties to
the U.S. government. Colorado, together with the other pipeline defendants, has
filed a motion to dismiss.
Other lawsuits and other proceedings which have arisen in the ordinary
course of business are pending or threatened against the Company or its
subsidiaries.
Although no assurances can be given and no determination can be made at
this time as to the outcome of any particular lawsuit or proceeding, the Company
believes there are meritorious defenses to substantially all of the above claims
and that any liability which may finally be determined should not have a
material adverse effect on the Company's consolidated financial position,
results of operations or cash flows.
Item 4. Submission of Matters to a Vote of Security Holders.
None.
8
<PAGE>
PART II
Item 5. Market for the Registrant's Common Equity and
Related Stockholder Matters.
All common stock of Colorado is owned by Coastal Natural Gas. At December
31, 1996, $269.3 million of retained earnings was available for dividends on
common stock. Additional information relating to dividends is set forth under
the "Statement of Consolidated Retained Earnings and Additional Paid-In Capital"
included herein.
All of the remaining outstanding shares of preferred stock at January 1,
1996 were redeemed on July 31, 1996 at par value.
Item 6. Selected Financial Data.
The following selected financial data (in thousands of dollars) is derived
from the Consolidated Financial Statements included herein and Item 6 of the
Company's Annual Report on Form 10-K for the year ended December 31, 1995, as
adjusted for minor reclassifications. The Notes to Consolidated Financial
Statements included herein contain information relating to this data.
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------------------------------------
1996* 1995 1994 1993 1992
----------- ----------- ----------- ----------- ----------
<S> <C> <C> <C> <C> <C>
Operating revenues........................... $ 412,477 $ 382,200 $ 386,553 $ 438,890 $ 402,998
Earnings before extraordinary item........... 82,058 87,716 78,507 73,178 84,075
Total assets................................. 908,922 861,448 962,111 901,627 1,097,178
Long-term debt, excluding current maturities. 229,373 179,299 179,225 179,145 195,278
Mandatory redemption preferred stock......... - 556 556 556 556
Common stock and other stockholder's equity.. 416,652 459,808 411,423 358,047 525,400
<FN>
- ----------------------
* Effective November 1, 1996, the Company discontinued the application of
FAS 71. Additional information is set forth in Management's Discussion and
Analysis of Financial Condition and Results of Operations and Note 10 of
Notes to Consolidated Financial Statements included herein.
</FN>
</TABLE>
All of the outstanding common stock of Colorado is owned by Coastal Natural
Gas; therefore, earnings and cash dividends per common share have no
significance and are not presented.
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.
The Management's Discussion and Analysis of Financial Condition and Results
of Operations is presented on pages F-1 through F-5 herein.
Item 8. Financial Statements and Supplementary Data.
The Financial Statements and Supplementary Data required hereunder are
included in this Annual Report as set forth in Item 14(a) herein.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
None.
9
<PAGE>
PART III
Item 10. Directors and Executive Officers of the Registrant.
The directors and executive officers of Colorado as of March 12, 1997, were
as follows:
Name (Age), Year First Elected Positions and Offices
Director and/or Officer with the Registrant
- ---------------------------------- ---------------------------------------
Jon R. Whitney (52), 1987 and 1974 President, Chief Executive Officer and
Director
Jeffrey A. Connelly (50), 1996 Director
David A. Arledge (52), 1981 Director
Harold Burrow (82), 1974 Director
C. Scott Hobbs (43), 1985 Executive Vice President, Chief Operating
Officer and Director
Coby C. Hesse (49), 1986 Executive Vice President
Daniel F. Collins (55), 1986 Senior Vice President
Donald H. Gullquist (53),1994 Senior Vice President
Rebecca H. Noecker (45), 1988 Senior Vice President and General Counsel
Austin M. O'Toole (61), 1984 Senior Vice President and Secretary
Richard G. Smead (50), 1988 Senior Vice President
Donald J. Zinko (52), 1988 Senior Vice President
Steven J. Coffin (41), 1990 Vice President
Ronald A. Gillet (55), 1993 Vice President
Thomas E. Jackson, Jr. (57), 1989 Vice President
Ronald D. Matthews (49), 1994 Vice President and Treasurer
Robert O. Reid (50), 1985 Vice President
William H. Sparger (54), 1992 Vice President
Dan A. Homec (48), 1989 Assistant Vice President and Controller
The above named persons bear no family relationship to each other. Their
respective terms of office expire coincident with Colorado's Annual Meeting of
the Sole Stockholder and Annual Meeting of the Board of Directors to be held in
May 1997. Each of the directors or officers named above have been directors or
officers of Colorado, ANR Pipeline and/or Coastal for five years or more except
for the following:
Mr. Gullquist was elected Senior Vice President of Colorado in October
1994. From 1988 to 1989 he served as Vice President, Finance at Enron
Corporation; from 1989 to 1990 he served as president of Enron Finance
Corporation.
Mr. Sparger was elected a Vice President of Colorado in June 1992. Before
joining the Company, he served in various capacities with Transcontinental Gas
Pipe Line Corporation since 1967.
10
<PAGE>
Item 11. Executive Compensation.
Colorado is an indirectly, wholly-owned subsidiary of Coastal. Information
concerning the cash compensation and certain other compensation of directors and
officers of Coastal is contained in this section.
The following table sets forth information for the fiscal years ended
December 31, 1996, 1995 and 1994 as to cash compensation paid by Coastal and its
subsidiaries, as well as certain other compensation paid or accrued for those
years, to Coastal's Chief Executive Officer ("CEO") and its four other most
highly compensated executive officers (the "Named Executive Officers").
Summary Compensation Table
<TABLE>
<CAPTION>
Long Term Compensation
-------------------------------
Annual Compensation<F1> Awards Payouts
---------------------------------- ------------- -------------
Securities All Other
Underlying LTIP Compen-
Name and Options/ Payouts sation
Principal Position Year Salary ($) Bonus ($)<F2> SARs (#)<F3> ($)<F4> $<F5>
- ------------------ ---- ---------- --------- ------------- ------------- ---------
<S> <C> <C> <C> <C> <C>
O. S. Wyatt, Jr., 1996 849,093 300,000 -0- 67,928
Chairman of the Board 1995 849,093 300,000 -0- 67,928
1994 849,093 200,000 -0- 67,928
David A. Arledge, 1996 707,194 300,000 150,000 56,576
President, CEO 1995 622,867 300,000 50,000 85,875 49,829
and Director 1994 553,873 150,000 -0- 44,310
James F. Cordes,<F6> 1996 592,223 -0- -0- 12,000
Executive V.P. 1995 592,223 135,000 15,000 42,937 47,378
and Director 1994 592,223 130,000 -0- 47,378
James A. King, 1996 343,823 80,000 10,000 13,572
Executive V.P. 1995 343,823 80,000 10,000 10,141
1994 343,823 75,000 -0- 6,877
Jerry D. Bullock, 1996 249,147 160,000 10,000 6,383
Senior V.P. 1995 249,147 75,000 10,000 6,766
1994 249,147 65,000 -0- 3,383
<FN>
- ------------------------
<F1> Does not include the value of perquisites and other personal benefits
because the aggregate amount of such compensation, if any, does not exceed
the lesser of $50,000 or 10 percent of annual salary and bonus for any
named individual.
<F2> Bonuses are based on the following factors: the individual's position; the
individual's responsibility; and the individual's ability to impact
Coastal's financial success.
<F3> The options do not carry any stock appreciation rights.
<F4> During 1995, Messrs. Arledge and Cordes received one-time cash payments in
the amounts indicated in connection with awards made in 1987 under
Coastal's Performance Unit Plan. No further awards have been made under
this Plan.
11
<PAGE>
<F5> All Other Compensation for 1996 consists of: (i) Coastal contributions to
the Coastal Thrift Plan (O. S. Wyatt, Jr. $12,000; David A. Arledge
$12,000; James F. Cordes $12,000; James A. King $6,000; and Jerry D.
Bullock $6,000); and (ii) certain payments in lieu of Thrift Plan
contributions (O. S. Wyatt, Jr. $55,927; David A. Arledge $44,576; James F.
Cordes $-0-; James A. King $7,572; and Jerry D. Bullock $383); these
payments are made to all employees of Coastal and its subsidiaries who
participate in the Thrift Plan who must discontinue their Thrift Plan
participation due to federal statutory limits.
<F6> Mr. Cordes retired as an officer of Coastal effective March 7, 1997.
</FN>
</TABLE>
Stock Options
The following table sets forth information with respect to stock options
granted on March 1, 1996 for the fiscal year ended December 31, 1996 to the
Named Executive Officers.
Option/SAR Grants in Last Fiscal Year (1996)
<TABLE>
<CAPTION>
Number of Percent of Total
Securities Options/SARs
Underlying Granted to Exercise Grant Date
Options/SARs Employees in Price Expiration Present
Name Granted<F1> Fiscal Year<F2> ($/Sh) Date Value ($)<F3>
---- ----------------- --------------------- ---------- -------------- --------------
<S> <C> <C> <C> <C> <C>
O. S. Wyatt, Jr. -0- -0- -0- -0- -0-
David A. Arledge 150,000 22.6 36.56 2/28/06 1,848,108
James F. Cordes -0- -0- -0- -0- -0-
James A. King 10,000 1.5 36.56 2/28/06 123,207
Jerry D. Bullock 10,000 1.5 36.56 2/28/06 123,207
<FN>
- ---------------------
<F1> Options expire ten years from the date of issuance and are granted at the
fair market value of the Common Stock of Coastal on the date of grant.
Options vest cumulatively at a rate of 20% of the option shares on each
anniversary date of the date of grant beginning with the second
anniversary.
<F2> The options do not carry any stock appreciation rights.
<F3> Based on the Black-Scholes option pricing model expressed as a ratio .337 x
exercise price x number of shares. The actual value, if any, an executive
may realize will depend on the excess of the stock price over the exercise
price on the date the option is exercised, so that there is no assurance
the value realized by an executive will be at or near the value estimated
by the Black-Scholes model. The estimated values under that model are based
on assumptions that include (i) a stock price volatility of .1925,
calculated using monthly stock prices for the three years prior to the
grant date, (ii) an interest rate of 6.25%, (iii) a dividend yield of 1.40%
and (iv) an expected option holding period of eight years. No adjustments
were made for the non-transferability of the options or to reflect any risk
of forfeiture prior to vesting. The Securities and Exchange Commission
("S.E.C.") requires disclosure of the potential realizable value or present
value of each grant. Coastal's use of the Black-Scholes model to indicate
the present value of each grant is not an endorsement of this valuation.
</FN>
</TABLE>
12
<PAGE>
Option/SAR Exercises and Holdings
The following table sets forth information with respect to the Named
Executive Officers, concerning the exercise of options during the last fiscal
year and unexercised options and SARs held as of the fiscal year ("FY") ended
December 31, 1996.
Aggregated Option/SAR Exercises In Last Fiscal Year
And FY-End Option/SAR Values (1996)
<TABLE>
<CAPTION>
Number of
Securities Value of
Underlying Unexercised
Unexercised In-the-Money
Options/SARs Options/SARs
at FY-End (#) at FY-End ($)<F1>
Shares Acquired Exercisable/ Exercisable/
Name on Exercise (#) Value Realized ($) Unexercisable Unexercisable
- -------------------- ------------------- -------------------- ---------------- -----------------------
<S> <C> <C> <C> <C> <C> <C>
O. S. Wyatt, Jr. -0- -0- -0- / -0- -0- / -0-
David A. Arledge 55,000 1,118,737 187,373 / 228,000 3,943,307 / 3,595,560
James F. Cordes 30,000 234,914 -0- / 35,000 -0- / 754,500
James A. King -0- -0- 26,000 / 24,000 599,800 / 432,200
Jerry D. Bullock 6,000 69,920 2,000 / 27,000 41,760 / 491,860
<FN>
- ------------------
<F1> $-based on the market price of $49.44 at December 31, 1996.
</FN>
</TABLE>
COMPENSATION AND EXECUTIVE DEVELOPMENT COMMITTEE
REPORT ON EXECUTIVE COMPENSATION
The following report has been provided by The Coastal Corporation's
Compensation and Executive Development Committee (the "Committee") of the Board
of Directors in accordance with current S.E.C. proxy statement disclosure
requirements. The members of the Committee include John M. Bissell (Chairman),
Roy D. Chapin, Jr., and Jerome S. Katzin.
This material states Coastal's current overall compensation philosophy and
program objectives. Detailed descriptions of Coastal's compensation programs are
provided as well as the information on Coastal's 1996 pay levels for the CEO.
Overall Objectives of the Executive Compensation Program
Coastal's compensation philosophy and program objectives are directed by
two primary guiding principles. First, the program is intended to provide fully
competitive levels of compensation - at expected levels of performance - in
order to attract, motivate and retain talented executives. Second, the program
is intended to create an alignment of interests between Coastal's executives and
stockholders such that a significant portion of each executive's compensation is
directly linked to maximizing stockholder value.
In support of this philosophy, the executive compensation program is
designed to reward performance that is directly relevant to Coastal's short-term
and long-term success. As such, Coastal attempts to provide both short-term and
long-term incentive pay that varies based on corporate and individual
performance.
13
<PAGE>
To accomplish these objectives, the Committee has structured the executive
compensation program with three primary underlying components: base salary,
annual incentives, and long-term incentives (i.e., stock options). The following
sections describe Coastal's plans by element of compensation and discuss how
each component relates to Coastal's overall compensation philosophy.
In reviewing this information, reference is often made to the use of
competitive market data as criteria for establishing targeted compensation
levels. Coastal targets the market 50th percentile for its total compensation
program and actual total compensation rates in 1996 were at or below the
targeted level. (However, Coastal's competitive pay posture varies by pay
element, as described below.) Several market data sources are used by Coastal,
including energy industry norms for the publicly traded peer companies included
in Coastal's shareholder return performance graph, as reflected in these
companies' proxy statements. In addition, we utilize published survey data and
data obtained from independent consultants that are for general industry
companies similar in size (i.e., revenues) to Coastal. The published surveys
include data on over 50 companies of comparable size to Coastal, as measured by
revenues. Greater emphasis is placed on the published data and data obtained
from consultants than on the data for proxy peers, since the published data and
consulting data are reflective of company size.
Base Salary Program
Coastal's base salary program is based on a philosophy of providing base
pay levels that fall between the market 50th and 75th percentiles. Coastal
periodically reviews its executive pay levels to assure consistency with the
external market. Generally, Coastal's actual base salary levels for 1996 for
executives as a group were consistent with the targeted percentiles. We believe
it is crucial to provide strongly competitive salaries over time in order to
attract and retain executives who are highly talented.
Annual salary adjustments for Coastal are based on several factors: general
levels of market salary increases, individual performance, competitive base
salary levels, and Coastal's overall financial results. Coastal reviews
performance qualitatively considering total shareholder returns, the level of
earnings, return on equity, return on total capital and individual business unit
performance. These criteria are assessed qualitatively and are not weighted. All
base salary increases are based on a philosophy of pay-for-performance and
perceptions of an individual's long-term value to Coastal. As a result,
employees with higher levels of performance sustained over time will be paid
correspondingly higher salaries.
The Annual Bonus Plan
Coastal's Annual Bonus Plan is intended to (1) reward key employees based
on company/business unit and individual performance; (2) motivate key employees;
and (3) provide competitive cash compensation opportunities to plan
participants. Under the plan, target award opportunities vary by individual
position and are expressed as a percent of base salary. The individual target
award opportunities, which are slightly below market median levels, are then
aggregated into a total target pool which is adjusted as described below. The
amount a particular executive may earn is directly dependent on the individual's
position, responsibility, and ability to impact our financial success.
The actual bonus pool is established each year by modifying the target pool
based on Coastal's overall performance against measures established by the
Committee. In fiscal year 1996, the key performance measure considered was
earnings before interest and taxes ("EBIT") against plan. This measure was
weighted 50% of the total bonus program. In 1996 Coastal's EBIT performance was
above threshold standards (minimum performance level for bonus payment) but
below a very aggressive plan, resulting in the EBIT portion of the bonus paid
being below target. The remaining 50% of the annual bonus opportunity in 1996 is
a discretionary annual bonus pool. As a result, no formula performance measures
were used in establishing the size of awards under this portion of the plan.
However, in establishing the size of the discretionary bonus pool, the Committee
considered Coastal's Return on Equity relative to industry peers (using the same
peers included in the shareholder return graph), Return on Total Capital
compared to industry peers, the EBIT performance of each business unit, progress
made toward improving Coastal's operational and financial performance, and the
need to reward unique individual contributions. These measures were not formally
weighted by the Committee. The size of the discretionary bonus pool element was
established above threshold but below target based on the
14
<PAGE>
qualitative performance assessment described above. As a result, actual bonus
payments for 1996 were below target and median market levels.
Individual awards from the established bonus pool are recommended by senior
management, with advice and consent from the Committee. Individual awards from
the pool are based on business unit and individual employee performance, future
potential, and competitive considerations. All individual performance
assessments are conducted in a non-formula fashion without specific goal
weightings. The total bonus awards made may not exceed the amount of funds in
the bonus pool.
Long-Term Incentive Plan
Coastal's Long-Term Incentive Plan ("LTIP") is designed to focus executive
efforts on the long-term goals of Coastal and to maximize total return to our
shareholders. While Coastal's LTIP allows the Committee to use a variety of
long-term incentive devices, the Committee has relied solely on stock option
awards to provide long-term incentive opportunities in recent years.
Stock options align the interests of employees and shareholders by
providing value to the executive through stock price appreciation only. All
stock options have a ten-year term before expiration and are fully exercisable
within 6 years of the grant date.
Stock options were granted to certain of the Named Executive Officers in
1996 and it is anticipated that stock option awards will be made periodically at
the discretion of the Committee in the future. As in past years, the number of
shares actually granted to a particular participant is also based on Coastal's
financial success, its future business plans, and the individual's position and
level of responsibility within Coastal. All of these factors are assessed
subjectively and are not weighted. Stock options granted by Coastal in 1996 were
overall below market median levels.
1996 Chief Executive Officer Pay
As previously described, the Committee considers several factors in
developing an executive's compensation package. For the CEO, these include
competitive market practices (consistent with the philosophy described for other
executives), experience, achievement of strategic goals, and the financial
success of Coastal (considering the factors described under the annual bonus
plan above).
David A. Arledge
Mr. Arledge's annual salary was increased to $725,000 in 1996. This action
moved his salary closer to, but still below, the market median levels of salary
for the CEO position in companies of comparable size.
Mr. Arledge's bonus for 1996 was $300,000, payable in 1997. This award was
below targeted levels (and below market median levels) since Coastal's aggregate
performance on the measures described in the annual bonus section of this report
were below the aggressive Coastal targets.
The Committee granted stock options for 150,000 shares to Mr. Arledge in
1996 in recognition of his performance and as an incentive to continue his
efforts to increase shareholder value. These awards are tied to performance in
that the executive only realizes income from stock options if the stock price
rises. The grant is below market median levels for the executive positions held
by him.
$1 Million Pay Deductibility Cap
Under Section 162(m) of the Internal Revenue Code, public companies are
precluded from receiving a tax deduction on compensation paid to executive
officers in excess of $1 million. To address the $1 million pay deductibility
cap issue, Coastal's 1996 LTIP is structured so that stock option awards (which
are intended to be the primary long-term incentive vehicle for the present time)
qualify for an exemption from the $1 million pay deductibility limit.
15
<PAGE>
Also, at the present time, the Chairman of the Board of Directors and the
CEO are the only executives whose base salary plus target bonus exceeds $1
million. In order to preserve Coastal's tax deduction for base salary plus bonus
for these individuals, Coastal has established a nonqualified deferred
compensation program. Under this program, any annual incentive awards that bring
cash compensation to a level over $1 million may be deferred so that payments
occur after the individual is no longer a Named Executive Officer, thus
preserving the deductibility of the pay for Coastal.
Compensation and Executive Development Committee
John M. Bissell, Chairman
Roy D. Chapin, Jr.
Jerome S. Katzin
16
<PAGE>
Pension Plan
The following table shows for illustration purposes the estimated annual
benefits payable currently under the Pension Plan and Coastal's Replacement
Pension Plan described below upon retirement at age 65 based on the compensation
and years of credited service indicated.
Pension Plan Table
<TABLE>
<CAPTION>
Years of Credited Service
----------------------------------------------------------------------
5-Year Final
Average Pay 15 Years 20 Years 25 Years 30 Years 35 Years
----------- ----------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
$ 125,000................. $ 33,920 $ 45,226 $ 56,533 $ 67,840 $ 67,044
150,000................. 41,420 55,226 69,033 82,840 82,044
200,000................. 41,420 55,226 69,033 82,840 82,044
250,000................. 41,420 55,226 69,033 82,840 82,044
300,000................. 41,420 55,226 69,033 82,840 82,044
350,000................. 41,420 55,226 69,033 82,840 82,044
400,000................. 41,420 55,226 69,033 82,840 82,044
500,000................. 41,420 55,226 69,033 82,840 82,044
600,000................. 41,420 55,226 69,033 82,840 82,044
1,000,000................. 41,420 55,226 69,033 82,840 82,044
1,200,000................. 41,420 55,226 69,033 82,840 82,044
<FN>
(A) Compensation covered under the Pension Plan for employees of Coastal and
Coastal Replacement Pension Plan generally includes only base salary and
is limited to $150,000 for 1996.
(B) Federal legislation has reduced the benefit which may be earned due to
future service; however, benefits previously earned may not be reduced. At
December 31, 1996 each of the individuals named in the Summary Compensation
Table had covered salary for future benefit accrual of $150,000 and the
following years of credited service and pension payable at age 65 (or
current age, if over 65): Mr. Wyatt, 41 years, $460,768; Mr. Arledge, 16
years, $59,289; Mr. Cordes, 19 years, $81,059; Mr. King, 4 years $14,798
(not vested); and Mr. Bullock, 4 years, $14,132 (not vested). Mr. Wyatt
reached age 70 1/2 in January, 1995 and because of IRS requirements
concerning Coastal's qualified pension plan, he began receiving pension
payments in April 1996. These payments amounted to $282,775 in 1996.
(C) The normal form of retirement income is a straight life annuity. Benefits
payable under the Pension Plan are subject to offset by 1.5% of applicable
monthly social security benefits multiplied by the number of years of
credited service (up to 33 1/3 years).
</FN>
</TABLE>
The Employee Retirement Income Security Act of 1974, as amended by
subsequent legislation, limits the retirement benefits payable under the
tax-qualified Pension Plan. Where this occurs, Coastal will provide to certain
executives, including persons named in the Summary Compensation Table,
additional nonqualified retirement benefits under a Coastal Replacement Pension
Plan. These benefits, plus payments under the Pension Plan, will not exceed the
maximum amount which Coastal would have been required to provide under the
Pension Plan before application of the legislative limitations, and are
reflected in the above table and footnote (B).
17
<PAGE>
PERFORMANCE GRAPH - SHAREHOLDER RETURN ON COMMON STOCK
<TABLE>
<CAPTION>
Five-Year Cumulative Values
$100 Invested 12/31/91
Dividends Reinvested
DOLLAR VALUE OF $100 INVESTMENT AT DECEMBER 31,
-----------------------------------------------------------------------
1991 1992 1993 1994 1995 1996
---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
Coastal $ 100 $ 99 $ 118 $ 109 $ 157 $ 207
S&P 500 100 108 118 120 165 203
Index<F1><F2> 100 112 132 119 128 196
<FN>
<F1> The Index is based on Value Line's Diversified Natural Gas Group - the
Performance Graph reflects total shareholder return weighted to reflect the
market capitalization of the peer companies. The peer group is comprised
of: Burlington Res., Cabot, Columbia, Consolidated Nat. Gas, Eastern
Enterprises, Enron, Enserch, Equitable Res., KN Energy, Mitchell Energy,
National Fuel Gas, Noram Energy, Panhandle Eastern, Questar, Seagull
Energy, Sonat, Southwestern Energy, Valero and Williams Cos.
<F2> Coastal is excluded from the Index.
</FN>
</TABLE>
Transactions with Management and Others
In 1987, Coastal Mart, Inc. ("Coastal Mart"), a subsidiary of Coastal,
entered into a ten-year lease/purchase agreement with Pester Marketing Company
("Pester Marketing") for 220 gasoline service stations (subsequently reduced to
182 stations through disposition of assets) located in the midwestern region of
the United States. Jack Pester, a principal stockholder and Chief Executive
Officer of Pester Marketing, subsequently became an employee, officer and
director of Coastal Mart and was elected a Senior Vice President of Coastal. Mr.
Pester is no longer active in the management of Pester Marketing, and his stock
interest in that company has been placed in trust. In 1994, the lease
transaction was terminated pursuant to an agreement under which Coastal Mart
acquired ownership of and title to 175 of the gasoline service stations and
Pester Marketing retained the seven remaining stations.
During 1996, Coastal and/or its subsidiaries sold approximately 14,576,400
gallons of gasoline to Pester Marketing at prevailing market prices totaling
approximately $10,036,200.
18
<PAGE>
The following table sets forth ownership of units of limited partnership
interests in the Coastal 1987 Drilling Program, Ltd., by directors and all
directors and executive officers as a group.
Directors Units
- --------- -----
O. S. Wyatt, Jr. .................................................. 750
Harold Burrow ..................................................... 100
David A. Arledge .................................................. -
John M. Bissell ................................................... -
George L. Brundrett, Jr. .......................................... -
Roy D. Chapin, Jr. ................................................ 20
James F. Cordes ................................................... -
Roy L. Gates ...................................................... -
Kenneth O. Johnson ................................................ -
Jerome S. Katzin .................................................. -
Thomas R. McDade................................................... -
L. D. Wooddy, Jr................................................... -
All directors and executive
officers as a group (31 persons,
including the above) ............................................ 890
Item 12. Security Ownership of Certain Beneficial Owners and Management.
(a) Security ownership of certain beneficial owners.
The following is information, as of March 12, 1997, on each person known or
believed by Colorado to be the beneficial owner of 5% or more of any class of
its voting securities:
<TABLE>
<CAPTION>
Amount and Nature
Name and Address of Beneficial Percent
Title of Class of Beneficial Owner Ownership of Class
- -------------- ------------------- ----------------- --------
<S> <C> <C> <C>
Common Stock, Coastal Natural Gas Company 10 shares direct 100%
$5 par value per share Nine Greenway Plaza
Houston, Texas 77046
</TABLE>
(b) Security ownership of management.
Colorado is an indirectly, wholly-owned subsidiary of Coastal. Information
concerning the security ownership of certain beneficial owners and management of
Coastal is contained in this section.
The total number of shares of stock of Coastal outstanding as of March 12,
1997 is 105,995,018 consisting of: 59,068 shares of $1.19 Cumulative Convertible
Preferred Stock, Series A (the "Series A Preferred Stock"), 72,398 shares of
$1.83 Cumulative Convertible Preferred Stock, Series B (the "Series B Preferred
Stock"), and 31,940 shares of $5.00 Cumulative Convertible Preferred Stock,
Series C (the "Series C Preferred Stock") (the Series A Preferred Stock, Series
B Preferred Stock and Series C Preferred Stock are referred to herein
collectively as the "Preferred Stock"), 105,451,513 shares of Common Stock, and
380,099 shares of Class A Common Stock.
Each voting share of Common Stock or Preferred Stock entitles the holder to
one vote with respect to all matters to come before a shareholders' meeting
while each share of Class A Common Stock entitles the holder to 100 votes.
However, 25% of Coastal's directors standing for election at each annual meeting
will be determined solely by holders of the Common Stock and voting Preferred
Stock voting as a class.
19
<PAGE>
The following table sets forth information, as of March 12, 1997, with
respect to each person known or believed by Coastal to be the beneficial owner,
who has or shares voting and/or investment power (other than as set forth
below), of more than five percent (5%) of any class of its voting securities.
<TABLE>
<CAPTION>
Name and Address Percent (%)
of Beneficial Owner Title of Class Number of Shares of Class (<F1>
------------------- -------------- ---------------- ------------
<S> <C> <C> <C>
O. S. Wyatt, Jr. Class A Common Stock 154,577 <F2> 40.4
Chairman of the Board
of Coastal
Nine Greenway Plaza
Houston, Texas 77046-0995
Trustee/Custodian under the Common Stock 12,344,644 <F3> 11.7
Thrift Plan, ESOP and Class A Common Stock 64,429 <F3> 16.8
Pension Plan of Coastal
and its subsidiaries
Texas Commerce Bank
National Association
600 Travis, 10th Floor
Houston, Texas 77002
FMR Corp. Common Stock 7,411,815 7.0
82 Devonshire Street
Boston, Massachusetts 02109
Isabel H. Long Series A Preferred Stock 28,976 49.1
485 S. Parkview Ave.,
Columbus, Ohio 43209-1075
The DeZurik Family Series C Preferred Stock 31,940 <F4> 100.0
c/o David DeZurik
2460 S.E. 8th St.
Pompano Beach, Florida 33062
<FN>
- ----------
<F1> Class includes presently exercisable stock options held by directors and
executive officers.
<F2> Includes 7,354 shares of Class A Common Stock owned by the spouse and a son
of Mr. Wyatt, as to which shares beneficial ownership is disclaimed.
<F3> The Trustee/Custodian is the record owner of these shares; and also is the
record owner of 742 shares of the Series B Preferred Stock, each of which
is convertible into 3.6125 shares of Common Stock and 0.1 share of Class A
Common Stock. Voting instructions are requested from each participant in
the Thrift Plan and ESOP and from the trustees under a Pension Trust.
Absent timely voting instructions, the Trustee is permitted to vote Thrift
Plan and ESOP shares on any matter, but has no authority to vote Pension
Plan shares. Nor does the Trustee/Custodian have any authority to dispose
of shares except pursuant to instructions of the administrator of the
Thrift Plan and ESOP or pursuant to instructions from the trustees under
the Pension Trust.
<F4> Members of the DeZurik family acquired the Series C Preferred Stock in
connection with a 1972 Agreement of Merger involving the acquisition of
Colorado, a subsidiary of Coastal.
</FN>
</TABLE>
20
<PAGE>
The following table sets forth information, as of March 12, 1997, regarding
each of the current directors, including Class II directors standing for
election, and all directors and executive officers as a group. Each director has
furnished the information with respect to age, principal occupation and
ownership of shares of stock of Coastal. Messrs. Arledge, Brundrett, Wooddy and
Wyatt are Class II directors whose terms expire in 1997; Messrs. Cordes, Gates,
Johnson and McDade are Class III directors whose terms expire in 1998; and
Messrs. Bissell, Burrow, Chapin and Katzin are Class I directors whose terms
expire in 1999.
<TABLE>
<CAPTION>
Number of Shares
Name, (Age), Year Offices with Coastal Beneficially Percent (%)
First Became Director and/or Principal Occupation Title of Class Owned<F1> of Class*
--------------------- --------------------------- -------------- ---------------- -----------
<S> <C> <C> <C> <C>
O. S. Wyatt, Jr. Chairman of the Board Common Stock 2,858,863 <F2> 2.7
(72), 1955 Class A Common Stock 154,577 <F2> 40.4
Harold Burrow Vice Chairman of the Board; Common Stock 137,127 <F2>
(82), 1973 Chairman of Colorado and ANR Class A Common Stock 13,601 3.6
David A. Arledge President and Common Stock 181,112
(52), 1988 Chief Executive Officer Class A Common Stock 2,352
John M. Bissell Chairman of the Board Common Stock 5,080
(66), 1985 of Bissell Inc. Class A Common Stock -0-
George L. Brundrett, Jr. Attorney Common Stock 4,910
(75), 1973 Class A Common Stock 2,290
Roy D. Chapin, Jr. Former Chairman and Common Stock 3,250 <F2>
(81), 1988 Chief Executive Officer Class A Common Stock -0-
of American Motors Corporation
James F. Cordes Retired; former Executive Vice Common Stock 18,708
(56), 1985 President of Coastal Class A Common Stock -0-
Roy L. Gates Ranching and Investments Common Stock 4,095
(68), 1969 Class A Common Stock 2,736
Kenneth O. Johnson Senior Vice President Common Stock 40,020
(76), 1988 Class A Common Stock 9,604 2.5
Jerome S. Katzin Retired Investment Banker Common Stock 41,803
(78), 1983 Class A Common Stock -0-
Thomas R. McDade Senior Partner, Law Firm of McDade, Common Stock 500
(64), 1993 Fogler, Maines & Lohse L.L.P., Houston Class A Common Stock -0-
L. D. Wooddy, Jr. Retired; Former President of Exxon Common Stock 3,000
(70), 1992 Pipeline Company Class A Common Stock -0-
All directors and executive officers as a group Common Stock 3,711,260 <F3> 3.5
(33 persons, including the above) Class A Common Stock 186,568 <F3> 48.8
(See footnotes on following page)
<FN>
* Less than one percent unless otherwise indicated. Class includes
outstanding shares and presently exercisable stock options held by
directors and executive officers. Excluding presently exercisable
stock options, directors and executive officers as a group would own
184,288 shares of Class A Common Stock, which would constitute 48.5%
of the shares of such class.
<F1> Except for the shares referred to in Notes 2 and 3 below, and the
shares represented by presently exercisable stock options, the
holders are believed by Coastal to have sole voting and investment
power as to the shares indicated. Amounts include shares in Coastal
ESOP and Thrift Plan, and presently exercisable stock options held by
Messrs. Arledge (162,093 shares of Common Stock and 2,280 shares of
Class A Common Stock), Cordes (8,000 shares of Common Stock), and
Johnson (7,848 shares of Common Stock).
21
<PAGE>
<F2> Includes shares owned by the spouse and a son of Mr. Wyatt (266,895
shares of Common Stock and 7,354 shares of Class A Common Stock), by
the spouse of Mr. Burrow (5,000 shares of Common Stock) and by the
spouse of Mr. Chapin (1,000 shares of Common Stock), as to which
shares beneficial ownership is disclaimed.
<F3> Includes presently exercisable stock options to purchase 453,829
shares of Common Stock and 2,280 shares of Class A Common Stock; also
includes 280,928 shares of Common Stock and 7,354 shares of Class A
Common Stock owned by spouses and children, as to which shares
beneficial ownership is disclaimed. In addition, one executive
officer owns 8 shares of Series B Preferred Stock, each of which is
convertible into 3.6125 shares of Common Stock and 0.1 share of Class
A Common Stock.
</FN>
</TABLE>
No incumbent director is related by blood, marriage or adoption to another
director or to any executive officer of Coastal or its subsidiaries or
affiliates.
Except as hereafter indicated, the above table includes the principal
occupation of each of the directors during the past five years. The listed
executive officers have held various executive positions with Coastal, ANR, ANR
Pipeline and/or Colorado during the five-year period.
Mr. Bissell is a member of the Boards of Directors of Old Kent Financial
Corporation and Batts Inc.
Mr. Cordes is a member of the Board of Directors of Comerica Inc.
Mr. Katzin is a member of the Board of Directors of Qualcomm Incorporated.
Mr. McDade is a trial lawyer and the founding senior partner of the Houston
law firm of McDade, Fogler, Maines & Lohse L.L.P. Prior to forming McDade,
Fogler, Maines & Lohse L.L.P., he was a senior partner in the Houston law firm
of Fulbright & Jaworski. He is a member of the Board of Directors of Equity
Corporation International.
Messrs. Arledge and Burrow are directors of Colorado and ANR Pipeline. Both
of these subsidiaries of Coastal are subject to the reporting requirements of
the Securities Exchange Act of 1934, as amended.
Item 13. Certain Relationships and Related Transactions.
(a) Transactions with management and others.
The Company participates in a program which matches short-term cash
excesses and requirements of participating affiliates, thus minimizing total
borrowings from outside sources. At December 31, 1996 the Company had advanced
$139.4 million to associated companies at a market rate of interest. Such amount
is repayable on demand.
Additional information called for by this item is set forth under Item 11,
"Executive Compensation" and Notes 8 and 13 of Notes to Consolidated Financial
Statements included herein.
(b) Certain business relationships.
None.
(c) Indebtedness of management.
None.
(d) Transactions with promoters.
Not applicable.
22
<PAGE>
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a) The following documents are filed as part of this Annual Report or
incorporated herein by reference:
1. Financial Statements and Supplemental Information.
The following Consolidated Financial Statements of Colorado and
Subsidiaries and Supplemental Information are included in response to
Item 8 hereof on the attached pages as indicated:
<TABLE>
<CAPTION>
Page
----
<S> <C>
Independent Auditors' Report.................................................................... F-6
Consolidated Balance Sheet at December 31, 1996 and 1995........................................ F-7
Statement of Consolidated Earnings for the Years Ended December 31, 1996, 1995 and 1994......... F-9
Statement of Consolidated Retained Earnings and Additional Paid-In Capital for the Years
Ended December 31, 1996, 1995 and 1994....................................................... F-9
Statement of Consolidated Cash Flows for the Years Ended December 31, 1996, 1995 and 1994....... F-10
Notes to Consolidated Financial Statements...................................................... F-11
Supplemental Information on Oil and Gas Producing Activities (Unaudited)........................ F-24
</TABLE>
2. Financial Statement Schedules.
Schedules are omitted as not applicable or not required, or the
required information is shown in the Consolidated Financial
Statements or Notes thereto.
3. Exhibits.
(3.1)+ Certificate of Incorporation of the Company (Exhibit to
the Company's Annual Report on Form 10-K for the fiscal
year ended December 31, 1980).
(3.2)+ By-laws of the Company (Filed as Module CIGBY-LAWS on
March 29, 1994).
(3.3)+ Certificate of Amendment of Certification of
Incorporation of the Company (Exhibit 3.1 to the
Company's Annual Report on Form 10-K for the fiscal year
ended December 31, 1989).
(4) With respect to instruments defining the rights of
holders of long-term debt, the Company will furnish to
the Securities and Exchange Commission any such document
on request.
(10)+ Agreement for Consulting Services between Colorado
Interstate Gas Company and Harold Burrow dated January
1, 1996 (Exhibit 10 to the Company's Annual Report on
Form 10 for the fiscal year ended December 31, 1995).
(21)* Subsidiaries of the Company.
(23)* Consent of Deloitte & Touche LLP.
(24)* Power of Attorney (included on signature pages herein).
(27)* Financial Data Schedule.
- ----------------------
Note:
+ Indicates documents incorporated by reference from the prior filing
indicated.
* Indicates documents filed herewith.
(b) Reports on Form 8-K.
No reports on Form 8-K were filed during the quarter ended December 31,
1996.
23
<PAGE>
POWER OF ATTORNEY
Each person whose signature appears below hereby appoints David A. Arledge,
Dan A. Homec and Austin M. O'Toole and each of them, any one of whom may act
without the joinder of the others, as his attorney-in-fact to sign on his behalf
and in the capacity stated below and to file all amendments to this Annual
Report on Form 10-K, which amendment or amendments may make such changes and
additions thereto as such attorney-in-fact may deem necessary or appropriate.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
COLORADO INTERSTATE GAS COMPANY
(Registrant)
By: JON R. WHITNEY
--------------------------------------
Jon R. Whitney
President and Chief Executive Officer
March 27, 1997
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
By: JEFFREY A. CONNELLY
--------------------------------------
Jeffrey A. Connelly
Director
March 27, 1997
By: HAROLD BURROW
--------------------------------------
Harold Burrow
Director
March 27, 1997
By: JON R. WHITNEY
--------------------------------------
Jon R. Whitney
Director
March 27, 1997
By: DAVID A. ARLEDGE
--------------------------------------
David A. Arledge
Principal Financial Officer and Director
March 27, 1997
24
<PAGE>
By: DAN A. HOMEC
--------------------------------------
Dan A. Homec
Principal Accounting Officer
March 27, 1997
By: C. SCOTT HOBBS
--------------------------------------
C. Scott Hobbs
Director
March 27, 1997
25
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Management's Discussion and Analysis of Financial Condition and Results of
Operations includes certain forward-looking statements reflecting the Company's
expectations in the near future; however, many factors which may affect the
actual results, including natural gas prices, market conditions, industry
competition and changing regulations, are difficult to predict. Accordingly,
there is no assurance that the Company's expectations will be realized.
The Notes to Consolidated Financial Statements contain information that is
pertinent to the following analysis.
Liquidity and Capital Resources
The Company uses the following consolidated ratios to measure liquidity and
ability to meet future funding needs and debt service requirements.
<TABLE>
<CAPTION>
1996 1995 1994
------ ------ ------
<S> <C> <C> <C>
Cash flow from operating activities to capital expenditures and debt
service requirements................................................... 133.4% 147.5% 374.5%
Total debt to total capitalization..................................... 35.5% 28.0% 30.3%
Times interest earned (before tax and extraordinary item).............. 7.5 8.3 7.4
</TABLE>
The Company's primary needs for cash are capital expenditures and debt
service requirements. Capital expenditures, debt retirements and other cash
needs in each of the years 1994 through 1996 and the sources of capital used to
finance these expenditures are summarized in the Statement of Consolidated Cash
Flows. Management believes the Company's stable financial position and earnings
ability will enable it to continue to generate and obtain capital for financing
needs in the foreseeable future.
Cash flow from operating activities amounted to $127.6 million in 1996,
$86.6 million in 1995 and $195.7 million in 1994. The 1996 increase can be
attributed primarily to decreases for working capital requirements. Liquidity
needs were met in 1996 by internally generated funds and a $50.0 million
borrowing under a term loan.
The Company has adopted a capital expenditure budget of approximately $76.0
million for 1997, a decrease from the capital additions of $95.6 million in
1996. The anticipated decrease in 1997 is the result of a $17.7 million decrease
for natural gas projects and a $1.9 million decrease for exploration and
production projects. Alternatives to finance capital expenditures and other cash
needs are primarily limited by the terms of one of the Company's debt
instruments. As of December 31, 1996, the Company could incur approximately
$403.9 million of additional indebtedness.
In December 1996, the Company invested $41.0 million in a new affiliate,
Coastal Medical Services, Inc. The affiliate has assumed the responsibility for
facilitating the funding and management of a portion of the medical obligations
of the Company and other Coastal subsidiaries.
The Company participates in a program which matches short-term cash
excesses and requirements of participating affiliates, thus minimizing
borrowings from outside sources. At December 31, 1996, the Company had advanced
$139.4 million to associated companies at a market rate of interest. Such amount
is repayable on demand.
The Company is responding to the extensive changes in the natural gas
industry by continuing to take steps to operate its facilities at their maximum
efficient capacity, renegotiating the remaining gas purchase contracts which are
above market in an effort to lower its cost of gas, pursuing innovative
marketing strategies and applying strict cost-cutting measures.
F-1
<PAGE>
The Company's operations are subject to extensive and evolving federal,
state and local environmental laws and regulations which may affect such
operations and costs as a result of their effect on the construction, operation,
and maintenance of its pipeline facilities. The Company spent approximately $1.2
million on environmental capital projects in 1996 and anticipates annual
environmental capital expenditures of $1 to $2 million over the next several
years aimed at maintaining compliance with such laws and regulations.
Additionally, appropriate governmental authorities may enforce the laws and
regulations with a variety of civil and criminal enforcement measures, including
monetary penalties and remediation requirements.
The Comprehensive Environmental Response, Compensation and Liability Act,
also known as "Superfund", as reauthorized, imposes liability, without regard to
fault or the legality of the original act, for disposal of a "hazardous
substance." The Company is not presently, and has not been in the past, a
potentially responsible party ("PRP") in any "Superfund" waste disposal sites.
However, the Company has received notice from a committee formed from a group of
55 companies who are named as PRPs at one site requesting the Company pay a de
minimis share (approximately $36,000) of the associated clean-up costs.
Future information and developments will require the Company to continually
reassess the expected impact of all applicable environmental laws and
regulations. Compliance with all applicable environmental protection laws and
regulations is not expected to have a material adverse impact on the Company's
liquidity, consolidated financial position or results of operations.
Results of Operations
Operating Revenues
The following table reflects the increase (decrease) in operating revenues
experienced by segment during the past two years (millions of dollars):
<TABLE>
<CAPTION>
Increase (Decrease)
From Prior Year
-------------------
1996 1995
------ ------
<S> <C> <C>
Natural gas.................................................................... $ 26 $ 6
Exploration and production..................................................... 7 (13)
Adjustments and eliminations................................................... (3) 3
------- ------
$ 30 $ (4)
======= ======
</TABLE>
Natural Gas
1996 Versus 1995. Revenues from natural gas operations increased in 1996
due to a $30 million increase related to average gas sales prices, an $11
million increase related to increased gas transportation volumes, an $8 million
increase resulting from increased gas sales volumes and increased extracted
product revenues of $6 million offset by a $24 million change in reservations
and other decreases of $5 million.
1995 Versus 1994. Revenues from natural gas operations increased in 1995
due to changes in reservations of $61 million offset by a $17 million decrease
resulting from reduced average gas sales prices, a $17 million decrease related
to reduced sales volumes, decreased transportation and gathering revenues of $14
million and other decreases of $7 million.
The daily average volumes of natural gas sold were 244 MMcf, 229 MMcf and
259 MMcf for 1996, 1995 and 1994, respectively. However, it is expected that
customers will reduce their contractual sales entitlement pursuant to the
provisions of Order 636. Transportation volumes increased by 7% in 1996 over the
1995 level and the 1997 transportation volumes are estimated to be slightly
higher than in 1996.
F-2
<PAGE>
Exploration and Production
1996 Versus 1995. Revenues from exploration and production increased in
1996 as a result of higher natural gas sales prices generating a $5 million
increase and $2 million from increased natural gas volumes.
1995 Versus 1994. Revenues from exploration and production decreased in
1995 as a result of natural gas sales volumes generating a $6 million decrease,
natural gas sales prices decreasing $4 million and other net decreases of $3
million.
Other Income - Net
The decrease in 1996 and the increase in 1995 primarily reflect changes in
interest income resulting from loans to affiliated companies.
Cost of Gas Sold
1996 Versus 1995. The increase is due primarily to higher average gas
purchase rates of $31 million and $5 million in net system balancing
requirements.
1995 Versus 1994. The decrease is due primarily to reduced average gas
purchase rates of $20 million and other decreases of $1 million partially offset
by increased gas used costs of $9 million and increased purchase volumes of $3
million.
Operation and Maintenance
1996 Versus 1995. Operation and maintenance expense decreased in 1996
primarily due to a $3 million decrease in payroll and employee benefits due to
an early retirement incentive program in 1995.
1995 Versus 1994. Operation and maintenance expense increased in 1995 due
primarily to the discontinuance of a production incentive fee credit in the
amount of $5 million partially offset by other net decreases of $2 million.
Depreciation, Depletion and Amortization
1996 Versus 1995. The increase in 1996 is due primarily to a $2 million
increase as a result of increased depreciable plant in the natural gas segment
and a $1 million increase related to higher production volumes in the
exploration and production segment.
1995 Versus 1994. The decrease in 1995 of approximately $3 million is due
primarily to a $4 million decrease related to reduced production volumes and a
$1 million decrease due to a lower depreciation, depletion and amortization rate
in the exploration and production segment offset by a $2 million increase as a
result of increased depreciable plant in the natural gas segment.
Operating Profit
The following table reflects the increase (decrease) in operating profit
experienced by segment during the past two years (millions of dollars):
<TABLE>
<CAPTION>
Increase (Decrease)
From Prior Year
--------------------
1996 1995
-------- --------
<S> <C> <C>
Natural gas.................................................................... $ (12) $ 11
Exploration and production..................................................... 7 (7)
------- ------
$ (5) $ 4
======= ======
</TABLE>
F-3
<PAGE>
Natural Gas
1996 Versus 1995. The natural gas segment's operating profit decrease in
1996 is due to a $36 million increase in the cost of gas sold and $2 million in
other items offset by a $26 million increase in operating revenues.
1995 Versus 1994. The natural gas segment's operating profit increase in
1995 is due to increased operating revenues of $6 million, decreased gas related
costs of $9 million and other increases of $2 million partially offset by a $4
million increase in operation and maintenance expenses and a $2 million increase
in depreciation, depletion and amortization expense.
Exploration and Production
1996 Versus 1995. The exploration and production segment's operating profit
increase in 1996 is due to increased revenues of $7 million.
1995 Versus 1994. The exploration and production segment's operating profit
decrease in 1995 is due to decreased revenues of $13 million partially offset by
decreased depreciation, depletion and amortization expense of $5 million and
other decreases of $1 million.
Interest Expense
1996 Versus 1995. The increase in 1996 is due to interest on a $50 million
senior term loan, due 1999, which was entered into August 27, 1996.
1995 Versus 1994. The slight decrease in 1995 is due to a reduction in
interest on provisions for rate refunds.
Taxes on Income
Income taxes fluctuated primarily as a result of changing levels of income
before taxes and changes in the effective income tax rate. The effective federal
income tax rate for the Company was 32% in 1996, 32% in 1995 and 33% in 1994.
Extraordinary Item - Loss from Discontinuance of FAS 71
The Company is subject to the regulations and accounting procedures of the
FERC and has historically followed the reporting and accounting requirements of
FAS No. 71 "Accounting for the Effects of Certain Types of Regulation" ("FAS
71"). FAS 71 provides that rate regulated enterprises account for and report
assets and liabilities consistent with the economic effect of the way in which
regulators establish rates, if the rates established are designed to recover the
costs of providing the regulated service and if the competitive environment
makes it reasonable to assume that such rates can be charged and collected. As a
result of FERC Order 636 (which unbundled pipeline services giving customers
more options for transporting their gas), the effect of discounted rates, and
new competitive developments on the horizon, the Company has concluded that the
competitive environment is no longer consistent with the form of regulation
contemplated by FAS 71. Accordingly, effective November 1, 1996, the Company has
ceased to apply the provisions of FAS 71 to its transactions and balances, which
accounting change has been implemented pursuant to the guidance contained in FAS
101, "Regulated Enterprises - Accounting for the Discontinuance of Application
of FASB Statement No. 71." The Company does not expect the change to have a
material adverse impact on financial results in future periods, and believes
this accounting change will result in financial reporting which better reflects
the results of operations in the economic environment in which the Company now
operates. See Note 10 of the Notes to Consolidated Financial Statements.
This accounting change has resulted in the elimination from the
Consolidated Balance Sheet the effects of actions of regulators, which effects
have been recognized as regulatory assets and liabilities recorded pursuant to
FAS 71, and the revaluation of certain other assets. The impact of these changes
was a charge to earnings of $6.3 million, net of related income taxes of $(1.5)
million, and is shown as an extraordinary item in the Statement of Consolidated
Earnings.
F-4
<PAGE>
The charge to earnings was noncash and will have no direct effect on the
Company's ability to include the underlying deferred items in future rates
proceedings or on its ability to collect the rates set thereby.
Recent Pronouncements
The FASB has issued FAS No. 125, "Accounting for Transfers and Servicing of
Financial Assets and Extinguishments of Liabilities" ("FAS 125") to be effective
in 1997. Under FAS 125, which uses a "financial-components approach," an entity
recognizes the financial assets it controls and liabilities it has incurred,
derecognizes financial assets when control has been surrendered and derecognizes
liabilities when extinguished. The application of the new standard is not
expected to have a material effect on the Company's consolidated financial
position, results of operations or cash flows in 1997.
The Accounting Standards Executive Committee of the AICPA issued Statement
of Position 96-1 ("SOP 96-1") on Environmental Remediation Liabilities to be
effective in 1997. SOP 96-1 provides additional guidance on accrual measurement
and the disclosure of environmental liabilities. The Company is currently
evaluating the impact of SOP 96-1.
F-5
<PAGE>
INDEPENDENT AUDITORS' REPORT
Board of Directors and Stockholder
Colorado Interstate Gas Company
Colorado Springs, Colorado
We have audited the accompanying consolidated balance sheets of Colorado
Interstate Gas Company (an indirect, wholly-owned subsidiary of The Coastal
Corporation) and subsidiaries as of December 31, 1996 and 1995, and the related
consolidated statements of earnings, retained earnings and additional paid-in
capital and cash flows for each of the three years in the period ended December
31, 1996. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of Colorado Interstate Gas Company
and subsidiaries as of December 31, 1996 and 1995, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1996 in conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Denver, Colorado
January 31, 1997
F-6
<PAGE>
COLORADO INTERSTATE GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
<TABLE>
<CAPTION>
December 31,
---------------------------
ASSETS 1996 1995
------------ ------------
<S> <C> <C>
Plant, Property and Equipment, at cost:
Gas pipeline................................................................... $ 1,134,592 $ 1,061,497
Gas and oil properties, at full-cost........................................... 125,024 138,067
------------ ------------
1,259,616 1,199,564
Accumulated depreciation, depletion and amortization........................... 676,873 658,327
------------ ------------
582,743 541,237
------------ ------------
Current Assets:
Cash........................................................................... 539 883
Notes receivable from affiliates............................................... 139,390 209,449
Receivables.................................................................... 51,961 44,518
Receivables from affiliates.................................................... 51,056 12,335
Inventories.................................................................... 9,671 9,494
Prepaid expenses............................................................... 417 280
Current portion of deferred income taxes....................................... 26,782 25,359
------------ ------------
279,816 302,318
------------ ------------
Other Assets:
Investments in affiliates...................................................... 41,056 114
Other deferred charges......................................................... 5,307 17,779
------------ ------------
46,363 17,893
------------ ------------
$ 908,922 $ 861,448
============ ============
</TABLE>
See Notes to Consolidated Financial Statements.
F-7
<PAGE>
COLORADO INTERSTATE GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
<TABLE>
<CAPTION>
December 31,
---------------------------
STOCKHOLDER'S EQUITY AND LIABILITIES 1996 1995
------------ ------------
<S> <C> <C>
Common Stock and Other Stockholder's Equity:
Common stock, $5 par value, authorized 10,000 shares; issued and
outstanding 10 shares at stated value....................................... $ 27,561 $ 27,561
Additional paid-in capital..................................................... 19,037 19,035
Retained earnings.............................................................. 370,054 413,212
------------ ------------
416,652 459,808
------------ ------------
Mandatory Redemption Preferred Stock, $100 par value, authorized 550,000 shares:
5.50% Series................................................................ - 556
------------ ------------
Debt:
Long-term debt................................................................. 229,373 179,299
------------ ------------
Current Liabilities:
Accounts payable and accrued expenses.......................................... 132,641 115,599
Accounts payable to affiliates................................................. 25,356 11,352
Taxes on income................................................................ 13,162 1,594
------------ ------------
171,159 128,545
------------ ------------
Deferred Credits:
Deferred income taxes.......................................................... 85,849 88,298
Other.......................................................................... 5,889 4,942
------------ ------------
91,738 93,240
------------ ------------
$ 908,922 $ 861,448
============ ============
</TABLE>
See Notes to Consolidated Financial Statements.
F-8
<PAGE>
COLORADO INTERSTATE GAS COMPANY AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED EARNINGS
(Thousands of Dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------------
1996 1995 1994
---------- ---------- ---------
<S> <C> <C> <C>
Revenues:
Operating revenues:
Nonaffiliates....................................................... $ 338,824 $ 332,963 $ 324,765
Affiliates.......................................................... 73,653 49,237 61,788
---------- ---------- ---------
412,477 382,200 386,553
Other income-net....................................................... 12,987 14,331 8,735
---------- ---------- ---------
425,464 396,531 395,288
---------- ---------- ---------
Costs and Expenses:
Cost of gas sold:
Nonaffiliates....................................................... 75,129 39,540 46,729
Affiliates.......................................................... 5,102 4,591 6,292
---------- ---------- ---------
80,231 44,131 53,021
Operation and maintenance.............................................. 160,708 163,832 160,487
Depreciation, depletion and amortization............................... 42,301 39,037 41,655
Interest expense....................................................... 18,861 18,092 18,932
Taxes on income........................................................ 41,305 43,723 42,686
---------- ---------- ---------
343,406 308,815 316,781
---------- ---------- ---------
Earnings before Extraordinary Item........................................ $ 82,058 $ 87,716 $ 78,507
Extraordinary Item - Loss from Discontinuance of FAS 71,
Net of Income Taxes.................................................... (6,301) - -
---------- ---------- ---------
Net Earnings.............................................................. $ 75,757 $ 87,716 $ 78,507
========== ========== =========
</TABLE>
STATEMENT OF CONSOLIDATED RETAINED EARNINGS AND
ADDITIONAL PAID-IN CAPITAL
(Thousands of Dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------------
1996 1995 1994
---------- ---------- ---------
<S> <C> <C> <C>
Retained Earnings:
Beginning balance......................................................... $ 413,212 $ 364,827 $ 311,451
Net earnings........................................................... 75,757 87,716 78,507
Less dividends:
Preferred stock:
5.50% Series..................................................... 15 31 31
Common stock........................................................ 118,900 39,300 25,100
---------- ---------- ---------
118,915 39,331 25,131
---------- ---------- ---------
Ending balance............................................................ $ 370,054 $ 413,212 $ 364,827
========== ========== =========
Additional Paid-In Capital:
Beginning balance......................................................... $ 19,035 $ 19,035 $ 19,035
Gain on redemption of preferred stock.................................. 2 - -
---------- ---------- ---------
Ending balance............................................................ $ 19,037 $ 19,035 $ 19,035
========== ========== =========
</TABLE>
See Notes to Consolidated Financial Statements.
F-9
<PAGE>
COLORADO INTERSTATE GAS COMPANY AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CASH FLOWS
(Thousands of Dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
1996 1995 1994
---------- ---------- ---------
<S> <C> <C> <C>
Net Cash Flow From Operating Activities:
Earnings before extraordinary item..................................... $ 82,058 $ 87,716 $ 78,507
Add (subtract) items not requiring (providing) cash:
Depreciation, depletion and amortization............................ 42,301 39,037 41,655
Deferred income taxes............................................... 216 21,602 (17,002)
Producer contract reformation cost recoveries....................... 135 140 3,056
Other............................................................... 6,716 3,821 8,511
Working capital and other changes, excluding changes relating to cash and
non-operating activities:
Receivables......................................................... (7,443) 73,835 54,434
Receivables from affiliates......................................... (38,721) 13,571 14,821
Inventories......................................................... (177) (340) 391
Prepaid expenses.................................................... (137) 348 351
Accounts payable and accrued expenses............................... 17,042 (132,688) 14,485
Accounts payable to affiliates...................................... 14,004 (3,029) (21,203)
Taxes on income..................................................... 11,568 (17,419) 17,738
---------- ---------- ---------
127,562 86,594 195,744
---------- ---------- ---------
Cash Flow from Investing Activities:
Purchases of plant, property and equipment............................. (95,597) (58,716) (52,263)
Proceeds from sale of plant, property and equipment.................... 7,934 1,756 1,187
Investments in affiliates.............................................. (40,942) (1,341) 1,226
Net (increase) decrease in notes receivable from affiliates............ 70,059 11,254 (113,250)
Gas supply prepayments and settlements................................. - (12) (28)
Recovery of gas supply prepayments..................................... 109 314 375
---------- ---------- ---------
(58,437) (46,745) (162,753)
---------- ---------- ---------
Cash Flow from Financing Activities:
Redemption of preferred stock.......................................... (556) - -
Gain on redemption of preferred stock.................................. 2 - -
Proceeds from long-term debt issue..................................... 50,000 - -
Preferred dividends paid............................................... (15) (38) (23)
Common dividends paid.................................................. (118,900) (39,300) (33,300)
---------- ---------- ---------
(69,469) (39,338) (33,323)
---------- ---------- ---------
Net Increase (Decrease) in Cash........................................... (344) 511 (332)
Cash at Beginning of Year................................................. 883 372 704
---------- ---------- ---------
Cash at End of Year....................................................... $ 539 $ 883 $ 372
========== ========== =========
</TABLE>
See Notes to Consolidated Financial Statements.
F-10
<PAGE>
COLORADO INTERSTATE GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
- - Basis of Presentation
Colorado is a subsidiary of Coastal Natural Gas, a wholly-owned subsidiary
of Coastal. The stock of the Company was contributed by Coastal to Coastal
Natural Gas effective April 30, 1982. The financial statements presented
herewith are presented on the basis of historical cost and do not reflect the
basis of cost to Coastal Natural Gas. The preparation of financial statements in
conformity with generally accepted accounting principles requires the Company to
make estimates and assumptions that affect the reported amounts of assets,
liabilities, revenues and expenses. Actual results could differ from the
estimates and assumptions used.
The Company is regulated by, and subject to, the regulations and accounting
procedures of the FERC and has historically followed the reporting and
accounting requirements of FAS No. 71, "Accounting for the Effects of Certain
Types of Regulation" ("FAS 71"). Effective November 1, 1996, Colorado
discontinued the application of FAS 71. Additional information is set forth in
Note 10 of Notes to Consolidated Financial Statements included herein.
- - Principles of Consolidation
The Consolidated Financial Statements include the accounts of the Company
and its subsidiaries after eliminating all significant intercompany
transactions.
- - Statement of Cash Flows
For purposes of this Statement, cash equivalents include time deposits,
certificates of deposit and all highly liquid instruments with original
maturities of three months or less. The Company made cash payments for interest,
net of amounts capitalized, of $18.6 million, $19.3 million and $17.5 million in
1996, 1995 and 1994, respectively. Cash payments for income taxes amounted to
$29.1 million, $39.5 million and $41.9 million in 1996, 1995 and 1994,
respectively.
- - Inventories
Materials and supplies inventories are carried principally at average cost.
- - Plant, Property and Equipment
Property additions and betterments are capitalized at cost. In accordance
with accounting requirements of the FERC, an allowance for equity and borrowed
funds used during construction ("AFUDC") is included in the cost of the natural
gas segment's additions and betterments. This cost amounted to $1.2 million, $.9
million and $1.9 million in 1996, 1995 and 1994, respectively. Effective
November 1, 1996, the Company discontinued the application of FAS 71 and no
longer capitalizes equity costs. All costs incurred in the acquisition,
exploration and development of gas and oil properties, including unproductive
wells, are capitalized under the full-cost method of accounting. Such costs
include the costs of all unproved properties and internal costs directly related
to acquisition and exploration activities. All other general and administrative
costs, as well as production costs, are expensed as incurred.
The Company generally provides for depreciation on a straight-line basis
with rates that vary by type of property. The depreciation rates for production
and gathering, products extraction, storage and transmission plant are 1.55%,
3.85%, 2.90% and 2.60%, respectively. Depreciation, depletion and amortization
of gas and oil properties are provided on the unit-of-production basis whereby
the unit rate for depreciation, depletion and amortization is determined by
dividing the total unrecovered carrying value of gas and oil properties plus
estimated future development costs by the estimated proved reserves included
therein, as estimated by an independent engineer. The average amortization rate
per
F-11
<PAGE>
equivalent unit of a thousand cubic feet of gas production for oil and gas
operations was $.88 for the year 1996, $.89 for the year 1995 and $.96 for the
year 1994. Unamortized costs of proved properties are subject to a ceiling which
limits such costs to the estimated future net cash flows from proved gas and oil
properties, net of related income tax effects, discounted at 10 percent. If the
unamortized costs are greater than this ceiling, any excess will be charged to
depreciation, depletion and amortization expense. No such charge was required in
the periods presented.
The cost of minor property units replaced or retired, net of salvage, is
credited to plant accounts and charged to accumulated depreciation, depletion
and amortization. Since provisions for depreciation, depletion and amortization
expense are made on a composite basis, no adjustments to accumulated
depreciation, depletion and amortization are made in connection with retirements
or other dispositions occurring in the ordinary course of business. Gain or loss
on sales of major property units is credited or charged to income.
The Company adopted Statement of Financial Accounting Standards No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
Be Disposed Of" in 1996. The application of the new standard, which does not
apply to costs capitalized pursuant to the full-cost method, did not have a
material effect on the Company's consolidated financial position, results of
operations or cash flows.
- - Income Taxes
The Company follows the liability method of accounting for deferred federal
income taxes as required by the provisions of FAS No. 109, "Accounting for
Income Taxes." The Company is a member of a consolidated group which files a
consolidated federal income tax return. Members of the consolidated group with
taxable income are charged with the amount of income taxes as if they filed
separate federal income tax returns, and members providing deductions and
credits which result in income tax savings are allocated credits for such
savings.
- - Revenue Recognition
The Company recognizes revenues for the sale of their products in the
period of delivery. Revenue for services are recognized in the period the
services are provided.
- - New Accounting Standards
The FASB has issued FAS No. 125, "Accounting for Transfers and Servicing of
Financial Assets and Extinguishments of Liabilities ("FAS 125"), to be effective
in 1997. Under FAS 125, which uses a "financial-components approach," an entity
recognizes the financial assets it controls and liabilities it has incurred,
derecognizes financial assets when control has been surrendered and derecognizes
liabilities when extinguished. The application of the new standard is not
expected to have a material effect on the Company's consolidated financial
position, results of operations or cash flows in 1997.
The Accounting Standards Executive Committee of the AICPA issued Statement
of Position 96-1 ("SOP 96-1") on Environmental Remediation Liabilities to be
effective in 1997. SOP 96-1 provides additional guidance on accrual measurement
and the disclosure of environmental liabilities. The Company is currently
evaluating the impact of SOP 96-1.
- - Reclassification of Prior Period Statements
Certain minor reclassifications of prior period statements have been made
to conform with current reporting practices. The effect of the reclassifications
was not material to the Company's consolidated financial position, results of
operations or cash flows.
F-12
<PAGE>
2. Long-Term Debt
Balances at December 31 were as follows (thousands of dollars):
<TABLE>
<CAPTION>
1996 1995
--------- --------
<S> <C> <C>
10% Senior Debentures, due 2005................................................... $ 179,373 $ 179,299
Senior Term Loan, due 1999........................................................ 50,000 -
--------- ---------
$ 229,373 $ 179,299
========= =========
</TABLE>
The 10% Senior Debentures, due 2005, are not redeemable prior to maturity
and have no sinking fund provisions.
On August 27, 1996, the Company entered into a $50 million senior term loan
agreement with a commercial bank which expires on August 30, 1999. The loan
carries a variable interest rate equal to the corporate base rate or a margin
over the London Interbank Offered Rate, with the interest rate option selected
by the Company.
Alternatives to finance capital expenditures and other cash needs are
primarily limited by the terms of one of the Company's debt instruments. As of
December 31, 1996, the Company could incur approximately $403.9 million of
additional indebtedness.
3. Common Stock and Other Stockholders' Equity
All of the Company's common stock is owned by Coastal Natural Gas.
At December 31, 1996, $269.3 million of retained earnings were available
for dividends on common stock.
4. Mandatory Redemption Preferred Stock
All of the remaining shares of the Company's mandatory Redemption Preferred
Stock were redeemed on July 31, 1996 at par value.
5. Fair Value of Financial Instruments
The estimated fair value amounts of the Company's financial instruments
have been determined by the Company, using appropriate market information and
valuation methodologies. Considerable judgment is required to develop the
estimates of fair value, thus, the estimates provided herein are not necessarily
indicative of the amounts that could be realized in a current market exchange.
<TABLE>
<CAPTION>
December 31, 1996 December 31, 1995
-------------------------- -------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- --------- -------- ---------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Financial assets:
Cash....................................... $ 539 $ 539 $ 883 $ 883
Notes receivable from affiliates........... 139,390 139,390 209,449 209,449
Financial liabilities:
Long-term debt............................. 229,373 264,600 179,299 223,819
Mandatory redemption preferred stock....... - - 556 556
</TABLE>
The carrying values of cash and notes receivable from affiliates are
reasonable estimates of their fair values. The estimated value of the Company's
long-term debt and mandatory redemption preferred stock is based on interest
rates at December 31, 1996 and 1995, respectively, for new issues with similar
remaining maturities.
F-13
<PAGE>
6. Taxes On Income
Provisions for income taxes (benefits) before extraordinary item are
composed of the following (thousands of dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
1996 1995 1994
-------- -------- --------
<S> <C> <C> <C>
Current Income Taxes:
Federal............................................................. $ 39,127 $ 22,406 $ 54,194
State............................................................... 1,962 (285) 5,494
-------- -------- --------
41,089 22,121 59,688
-------- -------- --------
Deferred Income Taxes:
Federal............................................................. 87 19,328 (15,439)
State............................................................... 129 2,274 (1,563)
-------- -------- --------
216 21,602 (17,002)
-------- -------- --------
Taxes on Income........................................................ $ 41,305 $ 43,723 $ 42,686
======== ======== ========
</TABLE>
Coastal and the Internal Revenue Service ("IRS") Appeals Office have
concluded a tentative settlement of all adjustments proposed through early 1997
to federal income tax returns filed for the years 1985 through 1987. Coastal's
federal income tax returns filed for the years 1988 through 1990 have been
examined by the IRS and Coastal has received notice of proposed adjustments to
the returns for each of those years. Coastal currently is contesting certain of
these adjustments with the IRS Appeals Office. Examination of Coastal's federal
income tax returns for 1991, 1992 and 1993 is expected to begin in 1997. It is
the opinion of management that adequate provisions for federal income taxes have
been reflected in the Company's consolidated financial statements.
Provisions for federal income taxes were different from the amount computed
by applying the statutory U.S. federal income tax rate to earnings before tax.
The reasons for these differences are (thousands of dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------
1996 1995 1994
-------- -------- --------
<S> <C> <C> <C>
Tax expense computed by applying the U.S. federal income
tax rate of 35%..................................................... $ 43,177 $ 45,992 $ 42,407
Increases (reductions) in taxes resulting from:
State income tax cost............................................... 1,359 1,293 2,556
Tight sands gas credit.............................................. (2,586) (2,896) (4,344)
Other............................................................... (645) (666) 2,067
------- -------- --------
Taxes on Income........................................................ $ 41,305 $ 43,723 $ 42,686
======== ======== ========
</TABLE>
F-14
<PAGE>
Deferred tax liabilities (assets) which are recognized for the estimated
future tax effects attributable to temporary differences are (thousands of
dollars):
<TABLE>
<CAPTION>
December 31,
---------------------
1996 1995
-------- ---------
<S> <C> <C>
Excess of book basis over tax basis of plant, property and equipment............... $ 88,417 $ 86,920
AFUDC equity income tax gross-up pursuant to FAS No. 109........................... - 1,786
Other.............................................................................. (2,568) (408)
-------- ---------
Deferred tax liabilities....................................................... 85,849 88,298
-------- ---------
Provisions for rate refunds and contested claims................................... (19,756) (20,413)
Accrued expenses................................................................... (4,236) (4,714)
Other.............................................................................. (2,790) (232)
-------- ---------
Deferred tax assets............................................................ (26,782) (25,359)
-------- ---------
Deferred income taxes.......................................................... $ 59,067 $ 62,939
======== =========
</TABLE>
7. Benefit Plans
The Company participates in the non-contributory pension plan of Coastal
(the "Plan") which covers substantially all employees. The Plan provides
benefits based on final average monthly compensation and years of service. As of
December 31, 1996, the Plan did not have an unfunded accumulated benefit
obligation. The Company's funding policy is to contribute the amount necessary
for the plan to maintain its qualified status under the Employment Retirement
Income Security Act of 1974, as amended. Colorado made no contributions to the
Plan for 1996, 1995 or 1994. Assets of the Plan are not segregated or restricted
by participating subsidiaries and pension obligations for Company employees
would remain the obligation of the Plan if the Company were to withdraw.
In 1995, the Company offered an early retirement incentive program to all
of its eligible employees, (age 55 before January 1, 1996 and having five or
more years of service before January 1, 1996), who were employed through
December 31, 1995. All benefits provided under this program are being funded by
the Plan and did not have a material impact on the Company's consolidated cash
flow or financial position.
The Company also makes contributions to a thrift plan, which is a trusteed,
voluntary and contributory plan for eligible employees of the Company. The
Company's contributions, which are based on matching employee contributions,
amounted to approximately $2.5 million for each of the years 1996 and 1995 and
$2.8 million for 1994.
The Company provides certain health care and life insurance benefits for
retired employees. The estimated costs of retiree benefit payments are accrued
during the years the employee provides services. Certain costs have been
deferred and were fully amortized as of October 31, 1996. Effective November 1,
1996, such costs will no longer be deferred as a result of the Company's
discontinuing application of FAS 71.
F-15
<PAGE>
The following tables set forth the accumulated postretirement benefit asset
recognized in the Company's Consolidated Balance Sheet for the years ended
December 31, 1996 and 1995 and the benefit cost for the years ended December 31,
1996, 1995 and 1994 (millions of dollars):
<TABLE>
<CAPTION>
December 31,
---------------------
1996 1995
-------- --------
<S> <C> <C>
Accumulated postretirement benefit obligation:
Retirees...................................................................... $ (10.9) $ (11.3)
Fully eligible plan participants.............................................. - (.3)
Other active plan participants................................................ (3.9) (6.4)
-------- --------
(14.8) (18.0)
Plan assets at fair value.......................................................... 5.9 5.9
-------- --------
Accumulated postretirement benefit obligation in excess of plan assets............. (8.9) (12.1)
Unrecognized net transition obligation............................................. 13.9 15.4
Unrecognized net gain from past experience different from that assumed............. (4.0) (2.5)
-------- --------
Postretirement benefit asset included in consolidated balance sheet................ $ 1.0 $ .8
======== ========
</TABLE>
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------
1996 1995 1994
-------- -------- --------
<S> <C> <C> <C>
Net postretirement benefit cost consisted of the following components:
Service cost - benefits earned during the period.................... $ .2 $ .3 $ .3
Interest cost on accumulated postretirement benefit obligation...... 1.0 1.2 1.2
Amortization of transition obligation............................... .9 .9 .9
Return on assets, net of deferrals.................................. (.4) (.3) (.2)
Deferred regulatory amount.......................................... .6 1.1 1.0
-------- -------- --------
Net postretirement benefit cost..................................... $ 2.3 $ 3.2 $ 3.2
======== ======== ========
</TABLE>
The assumed health care cost trend rate used in measuring the accumulated
postretirement benefit obligation was 10.4% in 1996, declining gradually to 6.0%
by the year 2004. The assumed health care cost trend rate used in measuring the
accumulated postretirement benefit obligation was 11.2% in 1995 and 12.0% in
1994. A one percentage point increase in the assumed health care cost trend rate
for each year would increase the accumulated postretirement benefit obligation
as of December 31, 1996 by approximately 3.2% and the net postretirement health
care cost by approximately 3.0%. The assumed discount rate used in determining
the accumulated postretirement benefit obligation was 7.50%.
8. Commitments
The Company and its subsidiaries had rental expense of approximately $4.7
million, $5.0 million and $7.3 million in 1996, 1995 and 1994, respectively
(excluding leases covering natural resources). The aggregate minimum lease
payments under existing noncapitalized long-term leases are estimated to be $3.3
million, $3.1 million, $3.0 million, $2.9 million and $2.8 million for the years
1997-2001, respectively, and $7.2 million thereafter.
F-16
<PAGE>
The Company has executed a service agreement with WIC, an affiliate,
providing for the availability of pipeline transportation capacity through
December 31, 2003. Under the service agreement, the Company is required to make
minimum payments on a monthly basis. The estimated amounts of minimum annual
payments are as follows (thousands of dollars):
1997........................................ $ 4,200
1998........................................ 3,700
1999........................................ 3,700
2000........................................ 3,600
2001........................................ 3,700
Later years................................. 7,400
The Company expensed approximately $4.7 million related to the minimum
payments under this agreement in 1996.
Colorado has executed precedent agreements with WIC and with Trailblazer
Pipeline Company for 99 thousand and 10 thousand dekatherms per day of firm
transportation capacity, respectively. Both agreements have a ten-year term.
Colorado has undertaken these commitments in order to: 1) provide current and
future customers of Colorado with direct access to points of delivery from these
pipeline systems without the customer having to contract separately for and
administer contracts on multiple pipeline systems; and 2) to enhance Colorado's
own operational reliability across the portion of its pipeline system which
generally parallels the WIC system. Colorado made the appropriate filings at the
FERC to hold this capacity in late March 1996 and approval was granted on
September 11, 1996.
9. Litigation and Regulatory Matters
- - Litigation Matters
In December 1992, certain of Colorado's natural gas lessors in the West
Panhandle Field filed a complaint in the U.S. District Court for the Northern
District of Texas claiming underpayment, breach of fiduciary duty, fraud and
negligent misrepresentation. Management believes that Colorado has numerous
defenses to the lessors' claims, including (i) that the royalties were properly
paid, (ii) that the majority of the claims were released by written agreement,
and (iii) that the majority of the claims are barred by the statute of
limitations. In March of 1995, the Trial Court granted a partial summary
judgment in favor of Colorado, holding that the four-year statute of limitations
had not been tolled, that the releases are valid, and dismissing all tort claims
and claims for breach of any duty of disclosure. The remaining claim for
underpayment of royalties was tried to a jury which, in May 1995, made findings
favorable to Colorado. On June 7, 1995, the Trial Court entered a judgment that
the lessors recover no monetary damages from Colorado and permanently estopping
the lessors from asserting any claim based on an interpretation of the contract
different than that asserted by Colorado in the litigation. The lessors' motion
for a new trial is pending. On June 7, 1996, the same Plaintiffs sued Colorado
in state court in Amarillo, Texas for underpayment of royalties. Colorado
removed the second lawsuit to federal court which granted a stay of the second
lawsuit pending the outcome of the first lawsuit.
A natural gas producer has filed a claim on behalf of the U.S. government
in the U.S. District Court for the District of Columbia under the federal False
Claims Act. The Second Amended Complaint filed on May 24, 1996, against seventy
(70) defendants, including Colorado, alleges that the defendants' methods of
measuring the heating content and volume of natural gas purchased from
federally-owned or Indian properties have caused underpayment of royalties to
the U.S. government. Colorado, together with the other pipeline defendant's, has
filed a motion to dismiss.
Other lawsuits and other proceedings which have arisen in the ordinary
course of business are pending or threatened against the Company or its
subsidiaries.
Although no assurances can be given and no determination can be made at
this time as to the outcome of any particular lawsuit or proceeding, the Company
believes there are meritorious defenses to substantially all of the above claims
and that any liability which may finally be determined should not have a
material adverse effect on the Company's consolidated financial position,
results of operations or cash flows.
F-17
<PAGE>
- - Rate Matters
On January 31, 1996, the FERC issued a "Statement of Policy and Request for
Comments" ("Policy Statement") with respect to a pipeline's ability to negotiate
and charge rates for individual customers' services which would not be limited
to the "cost-based" rates established by the FERC in traditional rate making.
Under this Policy Statement, a pipeline and a customer will be allowed to
negotiate a contract which provides for rates and charges that exceed the
pipeline's posted maximum tariff rates, provided that the shipper agreeing to
such negotiated rates has the ability to elect to receive service at the
pipeline's posted maximum rate (known as a "recourse rate"). To implement this
Policy Statement, a pipeline must make an initial tariff filing with the FERC to
indicate that it intends to contract for services under this Policy Statement,
and subsequent tariff filings will indicate each time the pipeline negotiates a
rate for service which exceeds the recourse rate. The FERC is also considering
comments on whether this "negotiated rate" program should be extended to other
terms and conditions of pipeline transportation services.
On July 31, 1996, the FERC also issued a "Notice of Proposed Rulemaking"
requesting comments on various aspects of secondary market transactions on
interstate natural gas pipelines, including the comparability of pipeline
capacity with released capacity.
On March 29, 1996, Colorado filed with the FERC under Docket No. RP96-190
to increase its rates by approximately $30 million annually and to realign
certain transportation services. On April 25, 1996, the FERC accepted the filing
to become effective October 1, 1996, subject to refund. In the event that the
case cannot be settled, a hearing before a FERC Administrative Law Judge is
currently scheduled for late 1997.
The FERC April 25, 1996 order also accepted tariff sheets filed by Colorado
to establish its rights to enter into negotiated rates consistent with the
negotiated rate Policy Statement. Colorado's tariff sheets became effective May
1, 1996, and continue to be effective despite the fact that certain parties have
sought judicial review of the FERC's actions with respect to Colorado's
negotiated rate provisions.
On June 26, 1996, the FERC approved Colorado's request for authority to
transfer to its subsidiary, CIGFS all of Colorado's gathering facilities except
for those in the Panhandle Field. The transferred facilities had a net book
value of approximately $42 million. The June 26, 1996 order further confirmed
that the facilities transferred to CIGFS would be considered non-jurisdictional.
The FERC issued a related order on September 26, 1996, accepting Colorado's
filing under Section 4 of the NGA confirming that Colorado no longer offered
gathering services through the transferred facilities. The FERC orders accepting
Colorado's spin-down and related Section 4 filings were not appealed and are now
final. Colorado completed the transfer to CIGFS effective October 1, 1996.
Certain of the above regulatory matters and other regulatory issues remain
unresolved among the Company, its customers, its suppliers and the FERC. The
Company has made provisions which represent management's assessment of the
ultimate resolution of these issues. As a result, the Company anticipates that
these regulatory matters will not have a material adverse effect on its
consolidated financial position, results of operations or cash flows. While the
Company estimates the provisions to be adequate to cover potential adverse
rulings on these and other issues, it cannot estimate when each of these issues
will be resolved.
10. Extraordinary Item
The Company is subject to the regulations and accounting procedures of the
FERC and has historically followed the reporting and accounting requirements of
FAS 71. FAS 71 provides that rate regulated enterprises account for and report
assets and liabilities consistent with the economic effect of the way in which
regulators establish rates, if the rates established are designed to recover the
costs of providing the regulated service and if the competitive environment
makes it reasonable to assume that such rates can be charged and collected. As a
result of FERC Order 636 (which unbundled pipeline services giving customers
more options for transporting their gas), the effect of discounted rates, and
new competitive developments on the horizon, the Company has concluded that the
competitive environment is no longer consistent with the form of regulation
contemplated by FAS 71. Accordingly, effective November 1, 1996, the Company has
ceased to apply the provision of FAS 71 to its transactions and balances, which
accounting change has been implemented pursuant to the guidance contained in FAS
101, "Regulated Enterprises - Accounting for the
F-18
<PAGE>
Discontinuance of Application of FASB Statement No. 71." The Company believes
this accounting change will result in financial reporting which better reflects
the results of operations in the economic environment in which the Company now
operates.
This accounting change has resulted in the elimination from the
Consolidated Balance Sheet of the effects of actions of regulators, which
effects have been recognized as regulatory assets and liabilities recorded
pursuant to FAS 71, and the revaluation of certain other assets. The impact of
these changes was a charge to earnings of $6.3 million, net of related income
taxes of $(1.5) million, and is shown as an extraordinary item in the Statement
of Consolidated Earnings. The charge to earnings was noncash and will have no
direct effect on the Company's ability to include the underlying deferred items
in future rates proceedings or on its ability to collect the rates set thereby.
11. Quarterly Results of Operations (Unaudited)
The results of operations by quarter for the years ended December 31, 1996
and 1995 were (thousands of dollars):
<TABLE>
<CAPTION>
1996 Quarter Ended
----------------------------------------------
March 31, June 30, Sept. 30, Dec. 31,
--------- -------- --------- --------
<S> <C> <C> <C> <C>
Revenues................................................. $ 116,575 $ 92,427 $ 106,392 $ 110,070
Cost of gas sold......................................... 18,375 10,785 20,736 30,335
--------- --------- ---------- ---------
Revenues less cost of gas sold........................ 98,200 81,642 85,656 79,735
Other costs and expenses................................. 66,235 63,233 68,297 65,410
--------- --------- ---------- ---------
Earnings before extraordinary item....................... 31,965 18,409 17,359 14,325
Extraordinary item-loss from discontinuance of
FAS 71................................................ - - - (6,301)
--------- --------- ---------- ---------
Net earnings.......................................... $ 31,965 $ 18,409 $ 17,359 $ 8,024
========= ========== ========== =========
</TABLE>
<TABLE>
<CAPTION>
1995 Quarter Ended
----------------------------------------------
March 31, June 30, Sept. 30, Dec. 31,
--------- -------- --------- --------
<S> <C> <C> <C> <C>
Revenues................................................. $ 106,984 $ 92,944 $ 92,557 $ 104,046
Cost of gas sold......................................... 10,975 9,576 9,652 13,928
--------- --------- ---------- ---------
Revenues less cost of gas sold........................ 96,009 83,368 82,905 90,118
Other costs and expenses................................. 67,748 66,648 64,482 65,806
--------- --------- ---------- ---------
Net earnings.......................................... $ 28,261 $ 16,720 $ 18,423 $ 24,312
========= ========== ========== =========
</TABLE>
12. Segment Reporting
Natural gas system operations and gas and oil exploration and production
are the two segments of the Company's operations.
Natural gas system operations involve the production, purchase, gathering,
storage, transportation and sale of natural gas, principally to and for public
utilities, industrial customers, other pipelines, and other gas customers, as
well as the operation of natural gas liquids extraction plants.
Gas and oil exploration and production operations involve primarily the
development and production of natural gas, crude oil, condensate and natural gas
liquids. Sales are made to affiliated companies, industrial users, interstate
pipelines and distribution companies in the Rocky Mountain, Central and
Southwest United States.
Operating revenues by segment include both sales to unaffiliated customers,
as reported in the Company's statement of consolidated earnings, and
intersegment sales, which are accounted for on the basis of contract, current
market, or internally established transfer prices. The intersegment sales are
from the exploration and production segment to the natural gas segment.
F-19
<PAGE>
Operating profit is total revenues less interest income from affiliates and
operating expenses. Operating expenses exclude income taxes, corporate general
and administrative expenses and interest.
Identifiable assets by segment are those assets that are used in the
Company's operations in each segment.
The Company's operating revenues and operating profit (loss) for the years
ended December 31, 1996, 1995 and 1994, and identifiable assets as of December
31, 1996, 1995 and 1994, by segment, are shown below (thousands of dollars):
<TABLE>
<CAPTION>
Operating
Operating Profit Identifiable
Revenues (Loss) Assets
-------------- -------------- --------------
<S> <C> <C> <C>
1996
- ----
Natural gas............................................ $ 400,423 $ 131,645 $ 880,807
Exploration and production............................. 20,273 3,001 28,115
Adjustments and eliminations........................... (8,219) - -
-------------- -------------- --------------
Segment totals...................................... 412,477 134,646 908,922
Other income-net....................................... 12,987 12,988 -
Corporate general and administrative expenses.......... - (5,410) -
Interest............................................... - (18,861) -
Income taxes........................................... - (41,305) -
Extraordinary item..................................... - (6,301) -
-------------- -------------- --------------
Consolidated Totals................................. $ 425,464 $ 75,757 $ 908,922
============== ============== ==============
1995
- ----
Natural gas............................................ $ 374,273 $ 143,598 $ 823,013
Exploration and production............................. 13,064 (3,524) 38,435
Adjustments and eliminations........................... (5,137) - -
-------------- -------------- --------------
Segment totals...................................... 382,200 140,074 861,448
Other income-net....................................... 14,331 14,331 -
Corporate general and administrative expenses.......... - (4,874) -
Interest............................................... - (18,092) -
Income taxes........................................... - (43,723) -
-------------- -------------- --------------
Consolidated Totals................................. $ 396,531 $ 87,716 $ 861,448
============== ============== ==============
1994
- ----
Natural gas............................................ $ 368,604 $ 132,355 $ 914,195
Exploration and production............................. 26,198 4,086 47,916
Adjustments and eliminations........................... (8,249) - -
-------------- -------------- --------------
Segment totals...................................... 386,553 136,441 962,111
Other income-net....................................... 8,735 8,735 -
Corporate general and administrative expenses.......... - (5,051) -
Interest............................................... - (18,932) -
Income taxes........................................... - (42,686) -
-------------- -------------- --------------
Consolidated Totals................................. $ 395,288 $ 78,507 $ 962,111
============== ============== ==============
</TABLE>
F-20
<PAGE>
Capital expenditures and depreciation, depletion and amortization expense
by segment for the years ended December 31, 1996, 1995 and 1994, were (thousands
of dollars):
<TABLE>
<CAPTION>
Depreciation,
Depletion and
Capital Amortization
Segment Expenditures Expense
------- ------------ -------------
<S> <C> <C>
1996
----
Natural gas................................................. $ 90,392 $ 30,851
Exploration and production.................................. 5,205 11,450
1995
----
Natural gas................................................. $ 55,017 $ 29,182
Exploration and production.................................. 3,699 9,855
1994
----
Natural gas................................................. $ 45,218 $ 26,980
Exploration and production.................................. 7,045 14,675
</TABLE>
Revenues from sales and transportation of natural gas to individual
customers amounting to 10% or more of the Company's consolidated revenues were
as indicated below:
<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------------
1996 1995 1994
---------- --------- ---------
<S> <C> <C> <C>
Public Service Company of Colorado
Amount (thousands of dollars)....................................... $ 167,222 $ 160,523 $ 198,002
========== ========= =========
Percent............................................................. 39% 40% 50%
========== ========= =========
</TABLE>
Revenues from sales and transportation of natural gas to any other single
customer did not amount to 10% or more of the Company's consolidated revenues
for the years ended December 31, 1996, 1995 and 1994. The Company does not have
any foreign operations.
Gas sales are made primarily to public utilities which resell the gas to
residential, commercial and industrial customers and to end-users in Colorado
and southeastern Wyoming. Deliveries from the Company's field system are made to
markets in the Texas Panhandle region. Transportation services are provided for
brokers, producers, marketers, distributors, end-users and other pipelines. The
Company extends credit for sales and transportation services provided to certain
qualifying companies.
F-21
<PAGE>
13. Transactions with Affiliates
The Statement of Consolidated Earnings includes the following major
transactions with affiliates (thousands of dollars):
<TABLE>
<CAPTION>
1996 1995 1994
------------------ ------------------ -----------------
Percent Percent Percent
Amount of Total Amount of Total Amount of Total
------ -------- ------ -------- ------ --------
<S> <C> <C> <C> <C> <C> <C>
Revenues
Gathering and Transportation -
Coastal Chem, Inc.......................... $ 2,281 1.2% $ 2,005 1.0% $ 2,522 1.3%
Coastal Gas Marketing Company.............. 8,268 4.2 9,257 4.6 10,582 5.4
Coastal Oil & Gas Corporation ............. 2,521 1.3 2,439 1.2 6,753 3.5
CIG Resources Company<F1>.................. 3,440 1.8 - - - -
Gas Sales -
Coastal Gas Marketing Company.............. $ 7,295 4.5% $ 6,348 5.1% $ 9,607 7.0%
CIG Resources Company<F2>.................. 9,429 5.9 323 0.3 - -
Extracted Products and Gas Processing -
Coastal Refining & Marketing, Inc.......... $ 24,791 92.5% $ 26,047 97.6% $ 28,991 96.0%
Coastal States Trading, Inc.<F3>........... - - 351 1.3 923 3.1
Coastal Field Services Company<F4>......... 1,461 5.4 - - - -
Incidental Gasoline, Oil and Condensate
Sales -
Coastal Refining & Marketing, Inc.......... $ 1,473 29.1% $ 1,348 35.0% $ 857 23.5%
Coastal States Trading, Inc................ 1,294 25.5 1,342 34.8 1,185 32.5
Contract Storage -
Coastal Gas Marketing Company<F5>.......... $ - -% $ - -% $ 456 4.6%
Natural Gas Production -
Coastal Gas Marketing Company.............. $ 6,878 33.9% $ 5,671 43.4% $ 9,100 34.7%
Coastal States Trading, Inc................ 268 1.3 241 1.8 16 0.1
Miscellaneous -
Coastal Refining & Marketing, Inc.......... $ 210 10.6% $ 285 11.2% $ 194 10.3%
Costs and Expenses
Gas Purchases -
Coastal Gas Marketing Company.............. $ 258 .2% $ 1,345 1.9% $ 1,582 1.7%
Coastal Limited Ventures, Inc.<F6>......... 290 .2 - - 205 .2
Coastal Oil & Gas Corporation.............. 6,077 5.8 3,156 4.5 4,505 4.9
Gathering, Transportation and Compression -
WIC........................................ $ 4,778 67.3% $ 4,425 55.6% $ 4,934 55.3%
ANR Pipeline Company<F7>................... 766 10.8 178 2.2 - -
<FN>
<F1> The 1995 amount was immaterial and 1994 had no activity.
<F2> 1994 had no activity.
<F3> The 1996 amount was immaterial.
<F4> 1995 and 1994 had no activity.
<F5> The 1996 and 1995 amounts were immaterial.
<F6> The 1995 amount was immaterial.
<F7> The 1994 amount was immaterial.
</FN>
</TABLE>
F-22
<PAGE>
Services provided by the Company at cost for affiliated companies were $7.0
million for 1996, $5.9 million for 1995 and $8.3 million for 1994. Services
provided by affiliated companies for the Company at cost were $8.2 million for
1996, $7.6 million for 1995 and $7.7 million for 1994. The services provided by
the Company to affiliates, and by affiliates to the Company, primarily reflect
the allocation of costs relating to the sharing/operating of facilities and
general and administrative functions. Such costs are allocated using a three
factor formula consisting of revenue, property and payroll, or other methods
which have been applied on a reasonable and consistent basis.
In 1989, the Company entered into two separate five-year lease agreements
with ANR Western Storage Company, an affiliate, for the rental of certain
pipeline facilities. Under the conditions of the lease agreements, the terms are
automatically extended at the option of the Company. Rental expense of
approximately $.9 million for 1996, $1.3 million in 1995 and $1.4 million in
1994 was recorded in conjunction with the terms of the lease agreements. The
lease was terminated in 1996 and the related facilities were purchased by the
Company.
The Company participates in a program which matches short-term cash
excesses and requirements of participating affiliates, thus minimizing total
borrowings from outside sources. At December 31, 1996, the Company had advanced
$139.4 million to associated companies at a market rate of interest. Such amount
is repayable on demand.
F-23
<PAGE>
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
Reserves, capitalized costs, costs incurred in oil and gas acquisition,
exploration and development activities, results of operations and the
standardized measure of discounted future net cash flows are presented for the
exploration and production segment. Natural gas system reserves and the related
standardized measure of discounted future net cash flows are presented
separately for natural gas operations. All reserves are located in the United
States. Most of the Company-owned gas reserves are dedicated to Colorado's
system.
<TABLE>
<CAPTION>
Estimated Quantities of Proved Reserves
Natural Gas Exploration
Company-Owned Reserves System and Production
---------------------- ----------- --------------------------
Developed Developed Undeveloped Total
----------- --------- ----------- -----
<S> <C> <C> <C> <C>
Natural Gas (MMcf):
-----------------
1996............................................. 267,927 74,963 39,803 382,693
1995............................................. 302,420 66,282 7,090 375,792
1994............................................. 334,597 76,917 2,598 414,112
Oil, Condensate and Natural Gas Liquids (000 barrels):
-----------------------------------------------------
1996............................................. 391 427 282 1,100
1995............................................. 126 323 36 485
1994............................................. 11 409 3 423
</TABLE>
Changes in proved reserves since the end of 1993 are shown in the following
table:
<TABLE>
<CAPTION>
Natural Gas Oil, Condensate and NGL
(MMcf) (000 barrels)
-------------------------- -------------------------
Natural Exploration Natural Exploration
Gas and Gas and
Total Proved Reserves System Production System Production
- --------------------- ------- ---------- ------- -----------
<S> <C> <C> <C> <C>
Total, end of 1993.............................. 379,795 95,993 7 411
------- ------- ------- -------
Production during 1994.......................... (46,288) (14,758) (1) (81)
Extensions and discoveries...................... - 5,304 - 58
Acquisitions.................................... - - - -
Revisions of previous quantity estimates and
other.......................................... 1,090 (7,024) 5 24
------- ------- ------- -------
Total, end of 1994.............................. 334,597 79,515 11 412
------- ------- ------- -------
Production during 1995.......................... (41,638) (10,703) (16) (67)
Extensions and discoveries...................... - 2,749 - 45
Acquisitions.................................... - 522 118 2
Revisions of previous quantity estimates and
other.......................................... 9,461 1,289 13 (33)
------- ------- ------- -------
Total, end of 1995.............................. 302,420 73,372 126 359
------- ------- ------- -------
Production during 1996.......................... (39,405) (12,304) (23) (115)
Extensions and discoveries...................... 264 38,714 265 320
Acquisitions.................................... - 1,100 - 10
Sales of reserves in-place...................... - (1,580) - (21)
Revisions of previous quantity estimates and
other.......................................... 4,648 15,464 23 156
------- ------- ------- -------
Total, end of 1996.............................. 267,927 114,766 391 709
======= ======= ======= =======
</TABLE>
F-24
<PAGE>
Total proved reserves for the natural gas system exclude storage gas and
liquids volumes. The natural gas system storage gas volumes are 38,842, 39,215
and 39,984 MMcf and storage liquids volumes are approximately 192,000, 138,000
and 172,000 barrels at December 31, 1996, 1995 and 1994, respectively. Volumes
are based on Huddleston's report and include estimates which differ slightly
from actuals.
<TABLE>
<CAPTION>
Capitalized Costs Relating to Exploration and Production Activities
(thousands of dollars)
December 31,
-------------------------
1996 1995
---------- -----------
Proved and Unproved Properties
- ------------------------------
<S> <C> <C>
Proved Properties................................................................... $ 124,368 $ 137,606
Unproved Properties................................................................. 656 461
----------- -----------
125,024 138,067
Accumulated depreciation, depletion and amortization................................ (101,080) (104,249)
----------- -----------
$ 23,944 $ 33,818
=========== ===========
</TABLE>
The Company follows the full-cost method of accounting for oil and gas
properties.
<TABLE>
<CAPTION>
Costs Excluded from Amortization
(thousands of dollars)
The following table summarizes the costs related to unevaluated properties
which are excluded from amounts subject to amortization at December 31, 1996.
The Company regularly evaluates these costs to determine whether impairment has
occurred.
Years Costs Incurred
---------------------------------------------------------------------
Prior
Total 1996 1995 1994 to 1994
----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Property Acquisition...................... $ 2 $ 2 $ - $ - $ -
Exploration............................... 84 65 19 - -
----------- ----------- ----------- ----------- -----------
$ 86 $ 67 $ 19 $ - $ -
=========== =========== =========== =========== ===========
</TABLE>
<TABLE>
<CAPTION>
Costs Incurred in Oil and Gas Acquisition, Exploration and Development Activities
(thousands of dollars)
Year Ended December 31,
--------------------------------
1996 1995 1994
-------- -------- --------
<S> <C> <C> <C>
Property acquisition costs:
Proved................................................................. $ 51 $ 436 $ 5
Unproved............................................................... 2 - -
Exploration costs............................................................ 107 40 323
Development costs............................................................ 5,040 3,200 6,717
</TABLE>
F-25
<PAGE>
<TABLE>
<CAPTION>
Results of Operations for Exploration and Production Activities
(thousands of dollars)
Year Ended December 31,
--------------------------------
1996 1995 1994
-------- -------- --------
<S> <C> <C> <C>
Revenues:
Sales..................................................................... $ 1,994 $ 2,313 $ 4,167
Transfers................................................................. 17,256 10,799 21,984
-------- -------- --------
Total.................................................................. 19,250 13,112 26,151
Production costs............................................................. (4,606) (5,022) (5,627)
Operating expenses........................................................... (1,215) (1,710) (1,810)
Depreciation, depletion and amortization..................................... (11,450) (9,855) (14,675)
-------- -------- --------
1,979 (3,475) 4,039
Income tax benefit .......................................................... 1,893 4,112 2,930
-------- -------- --------
Results of operations for producing activities (excluding corporate
overhead and interest costs).............................................. $ 3,872 $ 637 $ 6,969
======== ======== ========
</TABLE>
The average amortization rate per equivalent Mcf was $0.88 in 1996, $0.89
in 1995 and $0.96 in 1994.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil
and Gas Reserve Quantities
Future cash inflows from the sale of proved reserves and estimated
production and development costs, as calculated by the Company's independent
engineers, are discounted at 10% after they are reduced by the Company's
estimate for future income taxes. The calculations are based on year-end prices
and costs, statutory tax rates and nonconventional fuel source tax credits that
relate to existing proved oil and gas reserves in which the Company has mineral
interests.
The standardized measure is not intended to represent the market value of
reserves and, in view of the uncertainties involved in the reserve estimation
process, including the instability of energy markets as evidenced by recent
declines in both natural gas and crude oil prices, may be subject to material
future revisions (thousands of dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------------------------------------------------
1996 1995 1994
------------------------ ----------------------- -----------------------
Natural Exploration Natural Exploration Natural Exploration
Gas and Gas and Gas and
System Production System Production System Production
-------- ----------- ------- ------------ ------- -----------
<S> <C> <C> <C> <C> <C> <C>
Future cash inflows.......... $ 430,290 $ 440,567 $ 286,853 $ 104,369 $ 235,101 $ 133,850
Future production and
development costs......... (85,619) (139,864) (82,282) (49,586) (65,388) (51,623)
Future income tax expenses... (117,047) (93,337) (68,163) (6,872) (57,958) (13,339)
----------- ----------- ----------- ---------- ---------- -----------
Future net cash flows........ 227,624 207,366 136,408 47,911 111,755 68,888
10% annual discount for
estimated timing of cash
flows..................... (87,979) (88,165) (61,368) (14,278) (43,983) (22,358)
----------- ----------- ----------- ---------- ---------- -----------
Standardized measure of
discounted future net
cash flows................ $ 139,645 $ 119,201 $ 75,040 $ 33,633 $ 67,772 $ 46,530
=========== =========== =========== =========== =========== ===========
</TABLE>
F-26
<PAGE>
Principal sources of change in the standardized measure of discounted
future net cash flows during each year are as follows (thousands of dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------------------------------------------------------------
1996 1995 1994
------------------------- ------------------------- -------------------------
Natural Exploration Natural Exploration Natural Exploration
Gas and Gas and Gas and
System Production System Production System Production
----------- ----------- ----------- ---------- ---------- -----------
<S> <C> <C> <C> <C> <C> <C>
Sales and transfers, net of
production costs.......... $ (44,992) $ (14,644) $ (30,580) $ (7,726) $ (39,272) $ (18,115)
Net changes in prices and
production costs.......... 94,990 73,599 45,874 (10,302) (15,493) (31,746)
Extensions and discoveries... 3,548 48,073 - 1,149 - 3,597
Acquisitions................. - 2,169 941 388 - -
Sales of reserves in-place... - (1,668) - - - -
Development costs incurred
during the period that
reduced estimated future
development costs......... - 167 - 496 - 3,750
Revisions of previous quantity
estimates, timing and other 38,935 22,054 (15,449) (4,573) 1,449 (17,781)
Accretion of discount........ 6,680 2,142 7,325 4,497 10,793 8,718
Net change in income taxes... (34,556) (46,324) (843) 3,174 15,489 13,581
----------- ----------- ----------- ----------- ----------- -----------
Net change.............. $ 64,605 $ 85,568 $ 7,268 $ (12,897) $ (27,034) $ (37,996)
=========== =========== =========== =========== =========== ===========
</TABLE>
None of the amounts include any value for storage gas and liquids volumes,
which were approximately 38.8 Bcf and 192 thousand barrels, respectively, at the
end of 1996. Volumes are based on Huddleston's report and include estimates
which differ slightly from actuals.
F-27
<PAGE>
EXHIBIT INDEX
Exhibit
Number Document
- ------ -----------------------------------------------------------------
(3.1)+ Certificate of Incorporation of the Company (Exhibit to the
Company's Annual Report on Form 10-K for the fiscal year ended
December 31, 1980).
(3.2)+ By-laws of the Company (Filed as Module CIGBY-LAWS on March 29,
1994).
(3.3)+ Certificate of Amendment of Certification of Incorporation of the
Company (Exhibit 3.1 to the Company's Annual Report on Form 10-K
for the fiscal year ended December 31, 1989).
(4) With respect to instruments defining the rights of holders of
long-term debt, the Company will furnish to the Securities and
Exchange Commission any such document on request.
(10)+ Agreement for Consulting Services between Colorado Interstate Gas
Company and Harold Burrow dated January 1, 1996 (Exhibit 10 to the
Company's Annual Report on Form 10-K for the fiscal year ended
December 31, 1995).
(21)* Subsidiaries of the Company.
(23)* Consent of Deloitte & Touche LLP.
(24)* Power of Attorney (included on signature pages herein).
(27)* Financial Data Schedule.
- ----------------------------------
Note:
+ Indicates documents incorporated by reference from prior filing
indicated.
* Indicates documents filed herewith.
EXHIBIT 21
SUBSIDIARIES OF COLORADO INTERSTATE GAS COMPANY
State of
Incorporation
CIG Exploration, Inc............................................ Delaware
CIG Field Services Company...................................... Delaware
Colorado Water Supply Company................................... Delaware
Subsidiary:
Colorado Interstate Production Company.................... Delaware
CONSENT OF DELOITTE & TOUCHE LLP
We consent to the incorporation by reference in Registration Statement No.
333-11525 of Colorado Interstate Gas Company on Form S-3 of our report dated
January 31, 1997, appearing in this Annual Report on Form 10-K of Colorado
Interstate Gas Company for the year ended December 31, 1996.
DELOITTE & TOUCHE LLP
Houston, Texas
March 25, 1997
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND> THE SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION
EXTRACTED FROM COLORADO INTERSTATE GAS COMPANY FORM
10-K ANNUAL REPORT FOR THE PERIOD ENDED DECEMBER
31, 1996 AND IS QUALIFIED IN ITS ENTIRETY BY
REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> DEC-31-1996
<CASH> 539
<SECURITIES> 0
<RECEIVABLES> 242,407
<ALLOWANCES> 0
<INVENTORY> 9,671
<CURRENT-ASSETS> 279,816
<PP&E> 1,259,616
<DEPRECIATION> 676,873
<TOTAL-ASSETS> 908,922
<CURRENT-LIABILITIES> 171,159
<BONDS> 229,373
0
0
<COMMON> 27,561
<OTHER-SE> 389,091
<TOTAL-LIABILITY-AND-EQUITY> 908,922
<SALES> 412,477
<TOTAL-REVENUES> 425,464
<CGS> 80,231
<TOTAL-COSTS> 283,240
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 18,861
<INCOME-PRETAX> 123,363
<INCOME-TAX> 41,305
<INCOME-CONTINUING> 82,058
<DISCONTINUED> 0
<EXTRAORDINARY> (6,301)
<CHANGES> 0
<NET-INCOME> 75,757
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
</TABLE>
