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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, 1997 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
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Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
10% Senior Debentures, due 2005 } New York Stock Exchange
6.85% Senior Debentures, due 2037
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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 11, 1998, there were outstanding 10 shares of common stock of
the Registrant, $5.00 par value per share, its only class of common stock. None
of the voting stock of the Registrant is held by non-affiliates.
Documents incorporated by reference: None
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<PAGE>
TABLE OF CONTENTS
Item No. Page
Glossary........................................................(ii)
PART I
1. Business........................................................ 1
Introduction.................................................. 1
Natural Gas System............................................ 1
Operations................................................. 1
General................................................. 1
Gas Sales, Storage and Transportation................... 1
Gas Gathering and Processing............................ 2
Competition............................................. 2
Gas System Reserves........................................ 3
General................................................. 3
Reserves................................................ 3
Reserves Dedicated to a Particular Customer............. 3
Regulations Affecting Gas System........................... 3
General................................................. 3
Rate Matters............................................ 4
Gas and Oil Exploration and Production........................ 5
Environmental................................................. 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
7A. Quantitative and Qualitative Disclosures About Market Risk...... 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 from natural gas
storage fields and use by the Company's customers
NOTES:
This Annual Report includes certain forward-looking statements reflecting
the Company's expectations and objectives in the near future; however, many
factors which may affect the actual results, including natural gas and liquids
prices, market and economic conditions, industry competition and changing
regulations, are difficult to predict. Accordingly, there is no assurance that
the Company's expectations and objectives will be realized.
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, 1997, the Company had 875 employees.
The revenues and operating profit of the Company by industry segment for
each of the three years in the period ended December 31, 1997, and the related
identifiable assets as of December 31, 1997, 1996 and 1995, 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, purchase, gathering, processing,
transportation, storage and sale of natural gas. 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.
Public Service Company of Colorado ("PSCo") was the Company's only customer
accounting for revenue that equaled or exceeded 10% of the Company's
consolidated revenues for the years 1997, 1996 and 1995 (See Note 12 of Notes to
Consolidated Financial Statements). In 1997, the Company joined PSCo in a
project to increase the delivery capacity of natural gas into the Denver and
Front Range areas.
The Company's principal transmission and storage pipeline facilities,
including certain facilities in the Panhandle Field of Texas ("Panhandle
Field"), at December 31, 1997 consisted of 4,160 miles of pipeline and 59
compressor stations with approximately 302,000 installed horsepower. At December
31, 1997, the design peak day gas delivery capacity of the transmission system
was approximately 2.0 Bcf per day. The underground gas 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 2,327 miles of gathering lines and
approximately 50,700 horsepower of compression. Colorado owned and operated five
gas processing plants in 1997. 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.
Gas Sales, Storage and Transportation
Colorado's unincorporated Merchant Division conducts most of the Company's
sales activity. The gas sales volumes reported include those sales which
continue to be made by Colorado together with those of its Merchant Division.
Additionally, Colorado engages in "open access" storage and transportation of
gas owned by third parties.
1
<PAGE>
Pursuant to an operating agreement with an affiliate, the Company operates
the Young Gas Storage Field located in northeastern Colorado. When fully
developed in the 1998-99 heating season, the field will have a working gas
storage capacity of 5.3 Bcf, with a peak day delivery capacity of approximately
200 MMcf per day. Such capacity is fully subscribed under 30-year contracts.
Colorado's deliveries for the years 1997, 1996 and 1995 were as follows:
Total System Daily Average
Year Deliveries System Deliveries
(Bcf) (MMcf)
1997 486 1,333
1996 475 1,298
1995 456 1,248
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 two regulated
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.
The gas processing plants recovered approximately 55 million gallons of
liquid hydrocarbons in 1997 compared to 66 million gallons in 1996, and 81
million gallons in 1995, as well as 500 long tons of sulfur in 1997, compared to
3,100 long tons in 1996 and 4,600 long tons in 1995. Additionally, Colorado
processed approximately 24 million gallons of liquid hydrocarbons owned by
others in 1997 compared to approximately 6 million gallons in both 1996 and
1995.
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.
Competition
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.
In recent years the FERC has issued orders which have resulted in more
competition within the natural gas industry. This competition has intensified
resulting in more rate competition among pipelines in order to increase and
maintain market share and maximize capacity utilization. The Company's
transportation and storage services are influenced by its customers' access to
alternative service providers and the price of such services. The FERC's orders
have also resulted in competition between the Company and its customers by
allowing the customers to resell their unused capacity. Additionally, the
Company competes with interstate and intrastate pipeline companies in the sale,
transportation and storage of natural gas and with independent producers,
brokers, marketers, and other pipelines in the gathering, processing and sale of
gas within its service area.
2
<PAGE>
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, 1997, 1996, and 1995, as prepared by Huddleston,
Colorado's independent engineers.
<TABLE>
<CAPTION>
1997 1996 1995
---- ---- ----
<S> <C> <C> <C>
Owned or controlled by Colorado (Bcf).................................... 284 307 346
</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, 1997, Colorado maintained under its own account 3.1 Bcf of
natural gas in underground storage fields 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, 1997, and vary slightly from the
Huddleston report which includes estimates for November and December 1997.
Reserves Dedicated to a Particular Customer
Colorado is committed to sell gas to Pioneer Natural Resources USA, Inc.,
("Pioneer"), formerly Mesa Operating Company, 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 Pioneer.
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.
3
<PAGE>
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. The matter is pending review, following rounds
of extensive public comments.
In late 1997, the FERC initiated a public conference in order to solicit
comments from interested parties addressing the financial health of the pipeline
industry in the new competitive environment created by Order 636. Among other
things, the FERC is reviewing its current policies for setting the rates of
return on pipeline investment for possible improvements.
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.
Colorado has made such filing and the FERC has accepted that tariff filing.
Under the Policy Statement, a pipeline must also make subsequent tariff filings
each time the pipeline negotiates a rate for service which is outside of the
minimum and maximum range for the pipeline's cost-based recourse rates. Some
parties have sought judicial review of the FERC's acceptance of the Company's
tariff filing to implement negotiated rates, but Colorado's tariff sheet remains
in effect pending review. Colorado has filed for judicial review of the FERC's
holding that pipelines which have entered into "negotiated rate" contracts will
not be allowed discount adjustments in connection with such contracts. 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 March 29, 1996, Colorado filed with the FERC under Docket No. RP96-190
to increase its rates by approximately $30 million annually, to realign certain
transportation services and to add tariff language that would allow Colorado to
enter into "negotiated rates" (rates which could exceed the Company's
"cost-based" rates) in certain circumstances, subject to FERC policies. On April
25, 1996, the FERC accepted the rate change filing and the transportation
service realignment to become effective October 1, 1996, subject to refund, and
also accepted the "negotiated rate" tariff provision to become effective May 1,
1996. Certain parties sought judicial review of the acceptance of the
"negotiated rate" tariff provisions. On October 16, 1997, the FERC approved an
unopposed settlement filed by Colorado that resolves all issues in this general
rate case except the issues that are on appeal relating to the "negotiated rate"
tariff provisions. The final settlement modifies the services provided by
Colorado, and the charges for those services. The final settlement became
effective on November 17, 1997, and is no longer subject to review by the FERC
or subject to any judicial review. Colorado has now made refunds of amounts
collected which were in excess of the final settlement rates. The appeal of the
"negotiated rate" provision has been consolidated with other appeals involving
the same issues, and is being held in abeyance by the United States Court of
Appeals for the D. C. Circuit. Pending completion of judicial review, the
"negotiated rate" tariff provisions are fully effective, although during 1997
Colorado did not enter into any "negotiated rate" transactions.
In July 1996, the United States Court of Appeals for the D.C. Circuit
upheld the basic structure of the FERC's Order 636 (issued in April 1992), but
remanded to the FERC, for further consideration, certain limited aspects of the
Order, including the 20-year term established in Order 636 as the "cap" to be
applied to evaluation of bids for renewal contracts on existing facilities. On
remand in February 1997, the FERC reduced the term "cap" to five years. Colorado
and others have sought rehearing of this change and on other aspects of the
Order on remand. Colorado argued in its rehearing request inter alia that its
FERC-approved settlement of its Order 636 compliance proceeding precludes
applying this change to Colorado's existing contracts entered into pursuant to
Colorado's FERC-approved tariff.
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 or results of operations. While the Company
estimates the
4
<PAGE>
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, 1997:
<TABLE>
<CAPTION>
1997 1996 1995
-------- -------- --------
<S> <C> <C> <C>
Exploration and Production
Gas (MMcf)...................................................... 12,365 12,304 10,703
Oil (000 barrels)............................................... 10 2 5
Condensate (000 barrels)........................................ 50 61 60
Natural Gas Liquids (000 barrels)............................... 69 51 2
Natural Gas System
Gas (MMcf)...................................................... 38,135 39,405 41,638
Oil (000 barrels)............................................... 57 23 15
Condensate (000 barrels)........................................ - - 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, 1997:
<TABLE>
<CAPTION>
1997 1996 1995
-------- -------- --------
<S> <C> <C> <C>
Average sales price:
Gas - per Mcf................................................... $ 1.96 $ 1.51 $ 1.08
Oil - per barrel................................................ 19.05 19.91 16.47
Condensate - per barrel......................................... 19.74 21.39 17.34
Natural Gas Liquids - per barrel................................ 10.66 8.19 10.22
Average production cost per unit (equivalent Mcf).................... $ 0.43 $ 0.28 $ 0.37
</TABLE>
Acreage held under gas and oil mineral leases as of December 31, 1997 is
summarized as follows:
<TABLE>
<CAPTION>
Undeveloped Developed
------------------------ -------------------------
Area Gross Net Gross Net
-------------------------------------------------------- ----------- ----------- ---------- -----------
<S> <C> <C> <C> <C>
Exploration and Production.............................. 29,029 11,596 66,435 42,385
Natural Gas System...................................... - - 263,754 260,556
----------- ----------- ----------- -----------
29,029 11,596 330,189 302,941
=========== =========== =========== ===========
</TABLE>
The net developed acreage is concentrated principally in Texas (80%),
Oklahoma (6%), Wyoming (6%) and Utah (6%). The net undeveloped acreage is
principally in Wyoming (64%), Utah (15%) and Texas (14%).
5
<PAGE>
Information on wells drilled in the three years ended December 31, 1997, is
summarized as follows:
<TABLE>
<CAPTION>
1997 1996 1995
------------------------ ------------------------ -------------------------
Gross Net Gross Net Gross Net
----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Exploration and Production
Development Wells
Oil........................ - - - - - -
Gas........................ 29 20.82 5 1.86 7 2.44
Dry Holes.................. - - - - - -
----------- ----------- ----------- ----------- ----------- -----------
29 20.82 5 1.86 7 2.44
----------- ----------- ----------- ----------- ----------- -----------
Natural Gas System
Development Wells
Oil........................ - - 2 2.00 - -
Gas........................ 3 3.00 8 8.00 1 1.00
Dry Holes.................. - - - - - -
----------- ----------- ----------- ----------- ----------- -----------
3 3.00 10 10.00 1 1.00
----------- ----------- ----------- ----------- ----------- -----------
Total.................. 32 23.82 15 11.86 8 3.44
=========== =========== =========== =========== =========== ===========
</TABLE>
Productive wells as of December 31, 1997 are as follows:
<TABLE>
<CAPTION>
Type of Well Gross Net
--------------------------------------------------------------------------------- ----------- -----------
<S> <C> <C>
Exploration and Production
Oil.......................................................................... 3 2.09
Gas.......................................................................... 309 216.10
----------- -----------
Total Exploration and Production...................................... 312 218.19
----------- -----------
Natural Gas System
Oil.......................................................................... 9 8.24
Gas.......................................................................... 717 713.34
----------- -----------
Total Natural Gas System.............................................. 726 721.58
----------- -----------
Total..................................................... 1,038 939.77
=========== ===========
</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.
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.
6
<PAGE>
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
million on environmental capital projects in 1997 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
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 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 new trial was denied on July 18, 1997, and both parties have filed appeals.
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.
Other lawsuits and other proceedings which have arisen in the ordinary
course of business are pending or threatened against the Company or its
subsidiaries.
7
<PAGE>
Although no assurances can be given and no determination can be made at
this time as to the outcome of any particular lawsuit or proceeding, the Company
believes there are meritorious defenses to substantially all of the above claims
and that any liability which may finally be determined should not have a
material adverse effect on the Company's consolidated financial position or
results of operations.
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, 1997, there were no restrictions on retained earnings as to its availability
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.
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, 1996, 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,
-----------------------------------------------------------------
1997 1996* 1995 1994 1993
----------- ----------- ----------- ----------- ----------
<S> <C> <C> <C> <C> <C>
Operating revenues........................... $ 449,076 $ 412,477 $ 382,200 $ 386,553 $ 438,890
Earnings before extraordinary item........... 80,224 82,058 87,716 78,507 73,178
Total assets................................. 1,063,430 908,922 861,448 962,111 901,627
Long-term debt, excluding current maturities. 279,447 229,373 179,299 179,225 179,145
Mandatory redemption preferred stock......... - - 556 556 556
Common stock and other stockholder's equity.. 459,376 416,652 459,808 411,423 358,047
- ----------------------
<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 7A. Quantitative and Qualitative Disclosures About Market Risk.
Not applicable.
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 11, 1998, were
as follows:
Name (Age), Year First Elected Positions and Offices
Director and/or Officer with the Registrant
---------------------------------- ----------------------------------
Jon R. Whitney (53), 1987 and 1974 President, Chief Executive Officer
and Director
Jeffrey A. Connelly (51), 1996 Director
David A. Arledge (53), 1981 Director
Harold Burrow (83), 1974 Director
C. Scott Hobbs (44), 1985 Executive Vice President, Chief
Operating Officer and Director
Coby C. Hesse (50), 1986 Executive Vice President
Daniel F. Collins (56), 1986 Senior Vice President
Donald H. Gullquist (54),1994 Senior Vice President
Rebecca H. Noecker (46), 1988 Senior Vice President and General
Counsel
Austin M. O'Toole (62), 1984 Senior Vice President and Secretary
Richard G. Smead (51), 1988 Senior Vice President
Donald J. Zinko (53), 1988 Senior Vice President
Steven J. Coffin (42), 1990 Vice President
Thomas E. Jackson, Jr. (58), 1989 Vice President
Jeffrey B. Levos (37), 1997 Vice President
Ronald D. Matthews (50), 1994 Vice President and Treasurer
Thomas L. Price (42), 1997 Vice President
Robert O. Reid (51), 1985 Vice President
William H. Sparger (55), 1992 Vice President
Dan A. Homec (49), 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 1998. Each of the directors or officers named above have been directors or
officers of Colorado, ANR Pipeline and/or Coastal or subsidiaries thereof 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. Levos was elected Vice President and Controller of Coastal in March
1997. He has served as Vice President of Coastal States Management Corporation,
a subsidiary of Coastal, since December 1995 and also served as General Auditor
since July 1994. Prior thereto, he was a Certified Public Accountant with the
Houston office of Deloitte & Touche LLP since January 1986.
Mr. Price was elected as Vice President of Colorado in March 1997. He
joined Colorado in 1980 and has held positions in the Design and Evaluation and
Planning and Evaluation departments. He has served as Assistant Vice President
of Transmission and Storage since 1994.
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, 1997, 1996 and 1995 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 five other most
highly compensated executive officers (the "Named Executive Officers").
<TABLE>
Summary Compensation Table
<CAPTION>
Long Term Compensation
-----------------------------
Annual Compensation(1) Awards Payouts
------------------------------------- ---------- ------------
Securities All Other
Underlying LTIP Compen-
Name and Options/ Payouts sation
Principal Position Year Salary ($) Bonus ($)(F2) SARs (#)(F3) ($)(F4) $(F5)
- ------------------ ---- ---------- ------------- ------------ ------------- -------------
<S> <C> <C> <C> <C> <C> <C>
David A. Arledge, 1997 722,527 400,000 50,000 57,802
Chairman of the Board, 1996 707,194 300,000 150,000 56,576
President and CEO 1995 622,867 300,000 50,000 85,875 49,829
O. S. Wyatt, Jr., (F6) 1997 593,158 -- -0- 36,800
Director and former 1996 849,093 300,000 -0- 67,928
Chairman of the Board 1995 849,093 300,000 -0- 67,928
Coby C. Hesse, 1997 297,213 140,000 30,000 23,777
Executive V.P. - 1996 254,973 120,000 15,000 20,349
Administration 1995 243,321 90,000 15,000 19,466
James A. King, 1997 343,823 90,000 10,000 17,138
Executive V.P. - 1996 343,823 80,000 10,000 13,572
Refining 1995 343,823 80,000 10,000 10,141
Jeffrey A. Connelly 1997 300,893 120,000 20,000 24,071
Senior V.P. - Natural 1996 288,014 100,000 10,000 23,041
Gas 1995 269,807 85,000 8,000 20,610 21,584
Carl A. Corrallo 1997 297,635 100,000 20,000 23,811
Senior V.P. and 1996 281,536 90,000 10,000 22,523
General Counsel 1995 266,645 80,000 10,000 20,610 21,332
- ------------------------
<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.
11
<PAGE>
<F4>
During 1995, Messrs. Arledge, Connelly and Corrallo 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.
<F5>
All Other Compensation for 1997 consists of: (i) Company contributions to the
Coastal Thrift Plan (David A. Arledge $12,800; O. S. Wyatt, Jr. $12,800; Coby
C. Hesse $12,800; James A. King $6,400; Jeffrey A. Connelly $12,800; and Carl
A. Corrallo $12,800); (ii) certain payments in lieu of Thrift Plan
contributions (David A. Arledge $45,002; Coby C. Hesse $10,977; James A. King
$10,738; Jeffrey A. Connelly $11,271; and Carl A. Corrallo $11,011); 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; and (iii) directors' fees of
$24,000 paid to Mr. Wyatt.
<F6>
Mr. Wyatt retired as an officer of Coastal effective July 15, 1997.
</FN>
</TABLE>
Stock Options
The following table sets forth information with respect to stock options
granted on March 5, 1997 for the fiscal year ended December 31, 1997 to the
Named Executive Officers.
<TABLE>
Option/SAR Grants in Last Fiscal Year (1997)
<CAPTION>
Number of Percent of Total
Securities Options/SARs
Underlying Granted to Exercise Grant Date
Options/SARs Employees in Price Expiration Present
Name Granted(1) Fiscal Year(2) ($/Sh) Date Value ($)(3)
---- ----------------- --------------------- ---------- -------------- --------------
<S> <C> <C> <C> <C> <C>
David A. Arledge 50,000 6.58 47.06 3/4/07 818,609
O. S. Wyatt, Jr. -0- -0- -0- -0- -0-
Coby C. Hesse 30,000 3.95 47.06 3/4/07 491,165
James A. King 10,000 1.31 47.06 3/4/07 163,722
Jeffrey A. Connelly 20,000 2.63 47.06 3/4/07 327,443
Carl A. Corrallo 20,000 2.63 47.06 3/4/07 327,443
- ---------------------
<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 15% of the option shares on the first anniversary
date of the date of grant, 20% on each of the second, third and fourth
anniversary dates and 25% on the fifth anniversary date.
<F2>
The options do not carry any stock appreciation rights.
<F3>
Based on the Black-Scholes option pricing model expressed as a ratio .3479 x
xercise 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
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 .2205, calculated
using monthly stock prices for the three years prior to the grant date, (ii) an
interest rate of 6.90%, (iii) a dividend yield of 0.85% and (iv) an expected
option holding period of eight years. 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, 1997.
<TABLE>
Aggregated Option/SAR Exercises In Last Fiscal Year
And FY-End Option/SAR Values (1997)
<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>
David A. Arledge 40,000 1,034,728 171,373 / 254,000 5,423,414 / 6,238,520
O. S. Wyatt, Jr. -0- -0- -0- / -0- -0- / -0-
Coby C. Hesse 6,000 167,280 42,000 / 61,000 1,360,740 / 1,335,300
James A. King -0- -0- 30,000 / 30,000 1,045,680 / 724,120
Jeffrey A. Connelly 21,000 524,610 34,600 / 40,400 1,118,264 / 884,696
Carl A. Corrallo 6,000 190,800 41,500 / 42,000 1,247,385 / 937,240
- ------------------
<FN>
<F1>
$-based on the market price of $61.34 at December 31, 1997.
</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 1997 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). Certain other
executive benefits are also provided. 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 1997 in aggregate were at 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 selected publicly traded peer companies,
as reflected in these companies' proxy statements. There is no effort made to
assess how Coastal's executive pay levels compare to the levels of pay provided
by the companies in Value Line's Diversified Natural Gas Group which is used in
Coastal's total shareholder return graph since these companies vary
significantly in size and scope of operations. 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 philosophy is to provide 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 1997 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 and capable of creating added stockholder
value.
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.
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 1997, 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 1997 Coastal's EBIT performance was
slightly below target, resulting in the EBIT portion of the bonus paid being
slightly below target. The remaining 50% of the annual bonus opportunity in 1997
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 selected peers from among Value Line's Diversified Natural Gas Group
included in the shareholder return graph), return on total capital compared to
this selected group of 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 slightly below target by the
Committee, in spite of the fact that
14
<PAGE>
Coastal's return on equity was equal to the peer group average and that
Coastal's return on total capital was actually slightly above the peer group
average. The Committee established the pool slightly below target because
certain other areas of operation performance were not at target levels. As a
result, actual bonus payments for 1997 were slightly 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 the most recent grants
are fully exercisable within 5 years of the grant date.
Stock options were granted to certain of the Named Executive Officers in
1997 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. The number of stock options granted by
Coastal in 1997 was overall, slightly below market median levels.
The Committee believes stock options are an important part of Coastal's
total executive pay program, since employees only receive income from the
options if Coastal's share price rises. In addition, shareholder approval is
being sought for a new 1998 employee stock option plan. The intention of this
plan is to provide enough shares for Coastal to continue making stock option
awards to key employees.
1997 Chief Executive Officer Pay
As previously described, the Committee considers several factors in
developing an executive's compensation package. For the CEO, these include
competitive market practices (consistent with the philosophy described for other
executives), experience, achievement of strategic goals, and the financial
success of Coastal (considering the factors described under the annual bonus
plan above).
Mr. Arledge's annual salary was not adjusted in 1997, at his request. This
leaves the CEO's base salary below the market median.
Mr. Arledge's bonus for 1997 was $400,000, payable in 1998. This award was
slightly 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 slightly below the aggressive Coastal targets.
The Committee granted stock options for 50,000 shares to Mr. Arledge in
1997 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 well below market median level for the executive position
held by him.
15
<PAGE>
Executive Benefits
In 1997, Coastal approved a supplemental retirement plan for Coastal's
executives. This plan is intended to ensure that pensions otherwise payable to
executives under Coastal's qualified pension plan, are in fact paid in spite of
limits placed by the tax code on the tax deductibility of qualified retirement
plans for highly paid individuals.
$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 proposed 1998 Incentive Stock Plan is structured so that
stock option awards (which are intended to be the primary long-term incentive
vehicle for the present time) qualify for an exemption from the $1 million pay
deductibility limit.
Also, at the present time, the Chairman of the Board of Directors and CEO
is the only executive whose base salary plus target bonus exceeds $1 million. In
order to preserve Coastal's tax deduction for base salary plus bonus for this
individual, 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.
<TABLE>
Pension Plan Table
<CAPTION>
Years of Credited Service
5-Year Final --------------------------------------------------------------------
Average Pay 15 Years 20 Years 25 Years 30 Years 35 Years
----------- --------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
$ 125,000................. $ 33,877 $ 45,169 $ 56,461 $ 67,753 $ 66,948
150,000................. 41,377 55,169 68,961 82,753 81,948
175,000................. 48,877 65,169 81,461 97,753 96,948
200,000................. 56,377 75,169 93,961 112,753 111,948
225,000................. 63,877 85,169 106,461 127,753 126,948
250,000................. 71,377 95,169 118,961 142,753 141,948
300,000................. 86,377 115,169 143,961 172,753 171,948
350,000................. 101,377 135,169 168,961 202,753 201,948
400,000................. 116,377 155,169 193,961 232,753 231,948
450,000................. 131,377 175,169 218,961 262,753 261,948
500,000................. 146,377 195,169 243,961 292,753 291,948
600,000................. 146,377 195,169 243,961 292,753 291,948
700,000................. 146,377 195,169 243,961 292,753 291,948
800,000................. 146,377 195,169 243,961 292,753 291,948
900,000................. 146,377 195,169 243,961 292,753 291,948
1,000,000................. 146,377 195,169 243,961 292,753 291,948
1,100,000................. 146,377 195,169 243,961 292,753 291,948
1,200,000................. 146,377 195,169 243,961 292,753 291,948
<FN>
(A) Compensation covered under the Pension Plan and the Replacement Pension
Plan generally includes only base salary and is limited to $160,000 for
1997. During 1997 the Board of Directors amended Coastal's Replacement
Pension Plan to include compensation (generally base salary only) of up to
$500,000 (indexed for inflation) on a prospective basis in the five year
average compensation used to calculate benefits
(B) At December 31, 1997 each of the individuals named in the Summary
Compensation Table who had not retired had five year average pay of
$152,000 for future benefit accrual and the following years of credited
service and pension payable at age 65: Mr. Arledge, 17 years, $61,968; Mr.
Hesse, 11 years, $36,454; Mr. King, 5 years, $17,584; Mr. Connelly, 30
years, $101,373; and Mr. Corrallo, 11 years $29,813. 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. Mr. Wyatt retired in 1997. His payments from the plans
aggregated $377,249 in 1997.
(C) The normal form of retirement income is a straight life annuity. The
calculation of benefits payable under the Pension Plan includes an offset
of 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>
17
<PAGE>
PERFORMANCE GRAPH - SHAREHOLDER RETURN ON COMMON STOCK
[GRAPH]
<TABLE>
Five-Year Cumulative Values
$100 Invested 12/31/92
Dividends Reinvested
<CAPTION>
DOLLAR VALUE OF $100 INVESTMENT AT DECEMBER 31,
-----------------------------------------------------------------
1992 1993 1994 1995 1996 1997
---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
Coastal $ 100 $ 120 $ 111 $ 160 $ 211 $ 268
S&P 500 100 110 112 153 189 252
Index(F1)(F2) 100 119 110 127 184 195
<FN>
<F1>
The Index is based on Value Line's Diversified Natural Gas Group - the
Performance Graph reflects total shareholder returns weighted to reflect the
market capitalizations of the peer companies. The peer group is comprised of:
Cabot, Columbia Gas, Consolidated Nat'l. Gas, Eastern Enterprises, El Paso
Nat'l. Gas, Enron, Equitable Resources, KN Energy, Mapco, Mitchell Energy,
National Fuel Gas, Questar, Seagull Energy, Sonat, Southwestern Energy, Union
Pacific, and Williams Co's.
<F2>
Coastal is excluded from the Index.
</FN>
</TABLE>
Transactions with Officers and Directors
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 1997, Coastal
and/or its subsidiaries sold approximately 14 million gallons of gasoline to
Pester Marketing at prevailing market prices totaling approximately $9.97
million.
During 1997, Coastal subsidiaries sold a total of approximately 30 million
gallons of jet fuel to Laker Airways, Inc. ("Laker") and L. B. Limited, a
charter airline, at prevailing market prices totaling approximately $18.8
million. O. S. Wyatt, Jr. owned approximately 51% of the stock of Laker which he
disposed of in 1997; and he owns approximately one-third of the shares of L. B.
Limited. A balance of approximately $4.8 million of Laker indebtedness to
Coastal is guaranteed by Mr. Wyatt.
18
<PAGE>
Item 12. Security Ownership of Certain Beneficial Owners and Management.
(a) Security ownership of certain beneficial owners.
The following is information, as of March 11, 1998, 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 11,
1998 is 106,297,156 consisting of: 57,537 shares of $1.19 Cumulative Convertible
Preferred Stock, Series A (the "Series A Preferred Stock"), 66,744 shares of
$1.83 Cumulative Convertible Preferred Stock, Series B (the "Series B Preferred
Stock"), and 29,204 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"), 105,779,387 shares of Common Stock, and
364,284 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 11, 1998, with
respect to each person known or believed by Coastal to be the beneficial owner,
who has or shares voting and/or investment power (other than as set forth
below), of more than five percent (5%) of any class of its voting securities.
<TABLE>
<CAPTION>
Name and Address Percent (%)
of Beneficial Owner Title of Class Number of Shares of Class (1)
------------------- -------------- ----------------
<S> <C> <C> <C> <C>
O. S. Wyatt, Jr. Class A Common Stock 154,577 (2) 42.2
Eight Greenway Plaza
Houston, Texas 77046-0995
Trustee/Custodian under the Common Stock 11,522,361 (3) 10.8
Thrift Plan, ESOP and Class A Common Stock 58,447 (3) 15.9
Pension Plan of Coastal
and its subsidiaries
Chase Bank of Texas, N.A.
600 Travis, 10th Floor
Houston, Texas 77002
FMR Corp. Common Stock 9,846,399 9.3
82 Devonshire Street
Boston, Massachusetts 02109
Isabel H. Long Series A Preferred Stock 28,976 50.4
485 S. Parkview Ave.,
Columbus, Ohio 43209-1075
The DeZurik Family Series C Preferred Stock 29,204 (4) 100.0
c/o David DeZurik
309F The Island Club
777 S. Federal Hwy.
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 423 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 the 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 the Coastal.
</FN>
</TABLE>
20
<PAGE>
The following table sets forth information, as of March 11, 1998, regarding
each of the current directors, including Class III directors standing for
election, and all directors and executive officers as a group. Each director has
furnished the information with respect to age, principal occupation and
ownership of shares of stock of Coastal. Messrs. Cordes, Gates, Johnson, MacNeil
and McDade are Class III directors whose terms expire in 1998; Messrs. Bissell,
Burrow, Chapin and Katzin are Class I directors whose terms expire in 1999; and
Messrs. Arledge, Brundrett, Wooddy and Wyatt are Class II directors whose terms
expire in 2000.
<TABLE>
<CAPTION>
Number of Shares
Name, (Age), Year Offices with Coastal Beneficially Percent (%)
First Became Director and/or Principal Occupation Title of Class Owned(1) of Class(*)
--------------------- --------------------------- -------------- ---------------- -----------
<S> <C> <C> <C> <C> <C>
David A. Arledge Chairman of the Board, President Common Stock 247,792
(53), 1988 and Chief Executive Officer Class A Common Stock 2,352
Harold Burrow Retired; Vice Chairman of the Board Common Stock 134,177 (2)
(83), 1973 of Coastal Class A Common Stock 13,601 3.7
John M. Bissell Chairman of the Board Common Stock 5,096
(67), 1985 of Bissell Inc. Class A Common Stock -0-
George L. Brundrett, Jr. Attorney Common Stock 4,910
(76), 1973 Class A Common Stock 2,290
Roy D. Chapin, Jr. Former Chairman and Common Stock 3,250 (2)
(82), 1988 Chief Executive Officer Class A Common Stock -0-
of American Motors Corporation
James F. Cordes Retired; former Executive Vice Common Stock 10,835
(57), 1985 President of Coastal Class A Common Stock -0-
Roy L. Gates Ranching and Investments Common Stock 4,128
(69), 1969 Class A Common Stock 2,736
Kenneth O. Johnson Senior Vice President Common Stock 36,843
(77), 1988 Class A Common Stock 9,604 2.6
Jerome S. Katzin Retired Investment Banker Common Stock 41,803 (2)
(79), 1983 Class A Common Stock -0-
J. Carleton MacNeil, Jr. Securities Brokerage and Investments Common Stock 1,000
(63), 1997 Class A Common Stock -0-
Thomas R. McDade Senior Partner, Law Firm of McDade, Common Stock 2,500 (2)
(65), 1993 Fogler, Maines & Lohse L.L.P., Houston Class A Common Stock -0-
L. D. Wooddy, Jr. Former President of Exxon Common Stock 5,000
(71), 1992 Pipeline Company Class A Common Stock -0-
O. S. Wyatt, Jr. Retired; Chairman of the Executive Common Stock 2,399,505 (2) 2.3
(73), 1955 Committee of Coastal Class A Common Stock 154,577 (2) 42.1
All directors and executive officers as a group Common Stock 3,351,390 (3) 3.1
(34 persons, including the above) Class A Common Stock 186,394 (3) 50.8
(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
184,114 shares of Class A Common Stock, which would constitute 50.5%
of the shares of such class.
21
<PAGE>
<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 (225,873 shares of Common
Stock and 2,280 shares of Class A Common Stock) and Johnson (3,848 shares of
Common Stock).
<F2>
Includes shares owned by the spouse of Mr. Burrow (5,000 shares of Common
Stock), by the spouse of Mr. Chapin (1,000 shares of Common Stock), by the
spouse of Mr. Katzin (928 shares of Common Stock), by the spouse of Mr. McDade
(1,000 shares of Common Stock) and by the spouse and a son of Mr. Wyatt
(265,995 shares of Common Stock and 7,354 shares of Class A Common Stock), as
to which shares beneficial ownership is disclaimed.
<F3>
Includes presently exercisable stock options to purchase 544,459 shares of
Common Stock and 2,280 shares of Class A Common Stock; also includes 281,112
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 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, 1997 the Company had advanced
$219.7 million to associated companies at a market rate of interest. Such amount
is repayable on demand.
Additional information called for by this item is set forth under Item 11,
"Executive Compensation" and Notes 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.
<TABLE>
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:
<CAPTION>
Page
----
<S> <C>
Independent Auditors' Report.................................................................... F-6
Consolidated Balance Sheet at December 31, 1997 and 1996........................................ F-7
Statement of Consolidated Earnings for the Years Ended December 31, 1997, 1996 and 1995......... F-9
Statement of Consolidated Retained Earnings and Additional Paid-In Capital for the Years
Ended December 31, 1997, 1996 and 1995....................................................... F-9
Statement of Consolidated Cash Flows for the Years Ended December 31, 1997, 1996 and 1995....... F-10
Notes to Consolidated Financial Statements...................................................... F-11
Supplemental Information on Oil and Gas Producing Activities (Unaudited)........................ F-25
</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,
1997.
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, 1998
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, 1998
By: HAROLD BURROW
Harold Burrow
Director
March 27, 1998
By: JON R. WHITNEY
Jon R. Whitney
Director
March 27, 1998
By: DAVID A. ARLEDGE
David A. Arledge
Principal Financial Officer and Director
March 27, 1998
24
<PAGE>
By: DAN A. HOMEC
Dan A. Homec
Principal Accounting Officer
March 27, 1998
By: C. SCOTT HOBBS
C. Scott Hobbs
Director
March 27, 1998
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 and objectives in the near future; however, many factors which may
affect the actual results, including natural gas and liquids prices, market and
economic conditions, industry competition and changing regulations, are
difficult to predict. Accordingly, there is no assurance that the Company's
expectations and objectives will be realized. The forward-looking statements
contained herein are intended to qualify for the safe harbor provisions of
Section 21E of the Securities Exchange Act of 1934.
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>
1997 1996 1995
-------- -------- --------
<S> <C> <C> <C>
Cash flow from operating activities to capital expenditures and debt
service requirements................................................... 193.2% 133.4% 147.5%
Total debt to total capitalization..................................... 37.8% 35.5% 28.0%
Times interest earned (before tax and extraordinary item).............. 6.1 7.5 8.3
</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 1995 through 1997 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 $136.5 million in 1997,
$127.6 million in 1996 and $86.6 million in 1995. The 1997 increase can be
attributed primarily to decreases for working capital requirements. Liquidity
needs were met in 1997 by internally generated funds and through the issuance of
$100 million in senior debentures, as discussed below.
The Company has adopted a capital expenditure budget of approximately
$111.6 million for 1998, an increase from the capital additions of $70.7 million
in 1997. The anticipated increase in 1998 is the result of a $44.3 million
increase for natural gas projects and a $3.4 million decrease for exploration
and production projects. Alternatives to finance capital expenditures and other
cash needs are primarily limited by the terms of a Coastal Natural Gas debt
instrument. As of December 31, 1997, the Company and certain affiliates could
incur an aggregate of approximately $2.7 billion of additional indebtedness.
In June 1997, the Company issued $100.0 million of 6.85% senior debentures
due in 2037. The net proceeds from the sale of the debentures were used to
retire the Company's $50.0 million senior term loan and for general corporate
purposes. The 6.85% senior debentures are not redeemable prior to maturity; but
each holder has the right to require the Company to redeem such debentures, in
whole or in part, on June 15, 2007, at a redemption price equal to 100% of the
aggregate principal amount thereof plus accrued and unpaid interest.
The FASB has issued Statement of Financial Accounting Standards No. 131,
"Disclosures about Segments of an Enterprise and Related Information" ("FAS
131") to be effective for fiscal years beginning after December 15, 1997. FAS
131 establishes standards for the way that public business enterprises report
information about operating segments in annual financial statements and requires
that those enterprises report selected information about operating segments in
interim financial reports. It also establishes standards for related disclosures
about products and services, geographic areas, and major customers. The Company
does not believe that the application of the new standard will have a material
effect on its consolidated financial statements.
The Company, like most other companies, is faced with the Year 2000 Issue.
The Year 2000 Issue is the result of computer programs written with two digits
rather than four to define the applicable year. Any of the Company's computer
F-1
<PAGE>
programs that have date-sensitive software may recognize a date using "00" as
the year 1900 instead of the year 2000. This could result in a system failure or
miscalculations causing disruptions to operations, including, among other
things, a temporary inability to process transactions, send invoices, or engage
in similar normal business activities. The Company has determined that it will
be necessary to modify or replace portions of its software so that its computer
systems will properly utilize dates beyond December 31, 1999. The Company
believes that with modifications and conversions to new software, the Year 2000
Issue can be mitigated. However, if such modifications and conversions are not
made, or are not completed timely, the Year 2000 Issue could have a material
impact on the operations of the Company. There can also be no assurance that the
systems of other companies on which the Company's systems rely will be timely
converted, or that any such failure to convert by another company would not have
an adverse effect on the Company's systems.
The Company has been using both external and internal resources to
reprogram or replace its software for the Year 2000 Issue. To date, the amounts
incurred and expensed for developing and carrying out the plan have not had a
material effect on the Company's operations. The Company plans to complete the
Year 2000 modifications, including testing, by early 1999. The total remaining
cost for the Year 2000 Issue of approximately $3 million, which is based on
management's current estimates, is not expected to be material to the Company's
operations. All remaining Year 2000 Issue costs will be funded through operating
cash flows.
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, 1997, the Company had advanced
$219.7 million to associated companies at a market rate of interest. Such amount
is repayable on demand.
The Company is responding to the extensive changes in the natural gas
industry by continuing to take steps to operate its facilities at their maximum
efficient capacity, renegotiating the remaining gas purchase contracts which are
above market in an effort to lower its cost of gas, pursuing innovative
marketing strategies and applying strict cost-cutting measures.
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
million on environmental capital projects in 1997 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
consolidated financial position or results of operations.
F-2
<PAGE>
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
-------------------
1997 1996
------ ------
<S> <C> <C>
Natural gas.................................................................... $ 37 $ 26
Exploration and production..................................................... 6 7
Adjustments and eliminations................................................... (6) (3)
------- ------
$ 37 $ 30
======= ======
</TABLE>
Natural Gas
The Company is subject to the regulations and accounting procedures of the
FERC and 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, the Company ceased to apply the provisions of FAS
71. This accounting change has no direct effect on either the Company's ability
to include the previously deferred items in future rate proceedings, or on its
ability to collect the rates set thereby. The Company believes this accounting
change results in financial reporting which better reflects the results of
operations in the economic environment in which the Company now operates.
The Company operates under FERC Order 636. The intent of Order 636 is to
insure that interstate pipeline transportation services are equal in quality for
all gas supplies, whether the buyer purchases gas from the pipeline or from any
other gas supplier. The FERC requires the use of the straight fixed variable
("SFV") rate setting methodology. In general, SFV provides that all fixed costs
of providing service to firm customers (including an authorized return on rate
base and associated taxes) are to be received through fixed monthly reservation
charges, which are not a function of volumes transported, and provides that the
pipeline's variable operating costs are received through the commodity billing
component. Order 636 provides mechanisms for the recovery of any transition
costs incurred by pipelines within a reasonable time period.
1997 Versus 1996. Revenues from natural gas operations increased in 1997
due to a $28 million increase resulting from increased gas sales volumes, a $19
million increase related to average gas transportation prices, a $16 million
increase resulting from increased gas transportation volumes and an $11 million
increase related to average gas sales prices offset by a $30 million change in
reservations and other net decreases of $7 million.
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.
Exploration and Production
1997 Versus 1996. Revenues from exploration and production increased in
1997 as a result of higher natural gas sales prices generating a $6 million
increase.
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.
Other Income - Net
The decreases in 1997 and 1996 primarily reflect changes in interest income
resulting from loans to affiliated companies.
F-3
<PAGE>
Cost of Gas Sold
1997 Versus 1996. The increase is due primarily to higher average gas
purchase rates of $29 million and increased purchase volumes of $13 million
partially offset by $18 million in net system balancing requirements.
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.
Operation and Maintenance
1997 Versus 1996. Operation and maintenance expense increased in 1997 due
primarily to a $10 million increase in gas used in operations and other net
increases of $1 million.
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.
Depreciation, Depletion and Amortization
1997 Versus 1996. The 1997 decrease of $3 million is primarily due to
depreciation rate adjustments pursuant to the Company's settlement of FERC
Docket No. RP96-190 and the revision of depreciation rates for certain regulated
assets.
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.
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
-------------------
1997 1996
------- ------
<S> <C> <C>
Natural gas.................................................................... $ 2 $ (12)
Exploration and production..................................................... 3 7
------- ------
$ 5 $ (5)
======= ======
</TABLE>
Natural Gas
1997 Versus 1996. The natural gas segment's operating profit increase of $2
million is due to increased operating revenues of $37 million and a $3 million
decrease in depreciation, depletion and amortization expense partially offset by
a $24 million increase in cost of gas sold, increased operating and maintenance
expenses of $9 million and other net changes of $5 million.
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.
Exploration and Production
1997 Versus 1996. The exploration and production segment's 1997 operating
profit increase of $3 million is due to increased revenues of $6 million offset
by $2 million increase in operating expenses and $1 million in other net
changes.
1996 Versus 1995. The exploration and production segment's operating profit
increase in 1996 is due to increased revenues of $7 million.
F-4
<PAGE>
Interest Expense
1997 Versus 1996. The increase in 1997 is a result of interest on a $50
million senior term loan entered into on August 27, 1996, and the issuance of
$100 million senior debentures in June 1997. See discussion under "Liquidity and
Capital Resources" pertaining to the issuance and retirement of debt.
1996 Versus 1995. The increase in 1996 is due to interest on a $50 million
senior term loan, which was entered into August 27, 1996.
Taxes on Income
Income taxes fluctuated primarily as a result of changing levels of income
before taxes and changes in the effective income tax rate. The effective federal
income tax rate for the Company was 33% in 1997, and 32% in both 1996 and 1995.
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, 1997 and 1996, 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, 1997. 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, 1997 and 1996, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1997 in conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Denver, Colorado
February 3, 1998
F-6
<PAGE>
<TABLE>
COLORADO INTERSTATE GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
<CAPTION>
December 31,
---------------------------
ASSETS 1997 1996
---------- ------------
<S> <C> <C>
Current Assets:
Cash........................................................................... $ 3,508 $ 539
Notes receivable from affiliates............................................... 219,655 139,390
Receivables.................................................................... 63,319 51,961
Receivables from affiliates.................................................... 39,057 51,056
Materials and supplies......................................................... 8,841 9,671
Prepaid expenses............................................................... 93 417
Current portion of deferred income taxes....................................... 38,626 26,782
------------ ------------
373,099 279,816
------------ ------------
Plant, Property and Equipment, at cost:
Gas pipeline................................................................... 1,162,907 1,134,592
Gas and oil properties, at full-cost........................................... 130,500 125,024
------------ ------------
1,293,407 1,259,616
Accumulated depreciation, depletion and amortization........................... 689,690 676,873
------------ ------------
603,717 582,743
------------ ------------
Other Assets:
Investments in related parties................................................. 44,217 41,056
Other deferred charges......................................................... 42,397 5,307
------------ ------------
86,614 46,363
------------ ------------
$ 1,063,430 $ 908,922
============ ============
</TABLE>
See Notes to Consolidated Financial Statements.
F-7
<PAGE>
<TABLE>
COLORADO INTERSTATE GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
<CAPTION>
December 31,
---------------------------
LIABILITIES AND STOCKHOLDER'S EQUITY 1997 1996
------------ ------------
<S> <C> <C>
Current Liabilities:
Accounts payable and accrued expenses.......................................... $ 138,708 $ 132,641
Accounts payable to affiliates................................................. 26,460 25,356
Taxes on income................................................................ 5,429 13,162
------------ ------------
170,597 171,159
------------ ------------
Debt:
Long-term debt................................................................. 279,447 229,373
------------ ------------
Deferred Credits:
Deferred income taxes.......................................................... 112,063 85,849
Other.......................................................................... 41,947 5,889
------------ ------------
154,010 91,738
------------ ------------
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 19,037
Retained earnings.............................................................. 412,778 370,054
------------ ------------
459,376 416,652
------------ ------------
$ 1,063,430 $ 908,922
============ ============
</TABLE>
See Notes to Consolidated Financial Statements.
F-8
<PAGE>
<TABLE>
COLORADO INTERSTATE GAS COMPANY AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED EARNINGS
(Thousands of Dollars)
<CAPTION>
Year Ended December 31,
----------------------------------
1997 1996 1995
---------- ---------- ---------
<S> <C> <C> <C>
Revenues:
Operating revenues:
Nonaffiliates....................................................... $ 326,694 $ 338,824 $ 332,963
Affiliates.......................................................... 122,382 73,653 49,237
---------- ---------- ---------
449,076 412,477 382,200
Other income-net....................................................... 12,547 12,987 14,331
---------- ---------- ---------
461,623 425,464 396,531
---------- ---------- ---------
Costs and Expenses:
Cost of gas sold:
Nonaffiliates....................................................... 91,657 75,129 39,540
Affiliates.......................................................... 12,623 5,102 4,591
---------- ---------- ---------
104,280 80,231 44,131
Operation and maintenance.............................................. 171,961 160,708 163,832
Depreciation, depletion and amortization............................... 39,327 42,301 39,037
Interest expense....................................................... 23,816 18,861 18,092
Taxes on income........................................................ 42,015 41,305 43,723
---------- ---------- ---------
381,399 343,406 308,815
---------- ---------- ---------
Earnings before Extraordinary Item........................................ 80,224 82,058 87,716
Extraordinary Item - Loss from Discontinuance of FAS 71,
Net of Income Taxes.................................................... - (6,301) -
---------- ---------- ---------
Net Earnings.............................................................. $ 80,224 $ 75,757 $ 87,716
========== ========== =========
</TABLE>
<TABLE>
STATEMENT OF CONSOLIDATED RETAINED EARNINGS AND
ADDITIONAL PAID-IN CAPITAL
(Thousands of Dollars)
<CAPTION>
Year Ended December 31,
----------------------------------
1997 1996 1995
---------- ---------- ---------
<S> <C> <C> <C>
Retained Earnings:
Beginning balance......................................................... $ 370,054 $ 413,212 $ 364,827
Net earnings........................................................... 80,224 75,757 87,716
Less dividends:
Preferred stock:
5.50% Series..................................................... - 15 31
Common stock........................................................ 37,500 118,900 39,300
---------- ---------- ---------
37,500 118,915 39,331
---------- ---------- ---------
Ending balance............................................................ $ 412,778 $ 370,054 $ 413,212
========== ========== =========
Additional Paid-In Capital:
Beginning balance......................................................... $ 19,037 $ 19,035 $ 19,035
Gain on redemption of preferred stock.................................. - 2 -
---------- ---------- ---------
Ending balance............................................................ $ 19,037 $ 19,037 $ 19,035
========== ========== =========
</TABLE>
See Notes to Consolidated Financial Statements.
F-9
<PAGE>
<TABLE>
COLORADO INTERSTATE GAS COMPANY AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CASH FLOWS
(Thousands of Dollars)
<CAPTION>
Year Ended December 31,
----------------------------------
1997 1996 1995
--------- ---------- ---------
<S> <C> <C> <C>
Net Cash Flow From Operating Activities:
Earnings before extraordinary item..................................... $ 80,224 $ 82,058 $ 87,716
Add items not requiring cash:
Depreciation, depletion and amortization............................ 39,327 42,301 39,037
Deferred income taxes............................................... 13,177 216 21,602
Producer contract reformation cost recoveries....................... 14 135 140
Other............................................................... 2,524 6,716 3,821
Working capital and other changes, excluding changes relating to cash and
non-operating activities:
Receivables......................................................... (11,358) (7,443) 73,835
Receivables from affiliates......................................... 11,999 (38,721) 13,571
Materials and supplies.............................................. 830 (177) (340)
Prepaid expenses.................................................... 324 (137) 348
Accounts payable and accrued expenses............................... 6,067 17,042 (132,688)
Accounts payable to affiliates...................................... 1,104 14,004 (3,029)
Taxes on income..................................................... (7,733) 11,568 (17,419)
--------- ---------- ---------
136,499 127,562 86,594
--------- ---------- ---------
Cash Flow from Investing Activities:
Purchases of plant, property and equipment............................. (70,661) (95,597) (58,716)
Proceeds from sale of plant, property and equipment.................... 8,374 7,934 1,756
Investments in related parties......................................... (3,161) (40,942) (1,341)
Net (increase) decrease in notes receivable from affiliates............ (80,265) 70,059 11,254
Gas supply prepayments and settlements................................. - - (12)
Recovery of gas supply prepayments..................................... 79 109 314
--------- ---------- ---------
(145,634) (58,437) (46,745)
---------- ---------- ---------
Cash Flow from Financing Activities:
Redemption of preferred stock.......................................... - (556) -
Gain on redemption of preferred stock.................................. - 2 -
Issuance of Senior Debentures.......................................... 99,604 - -
Preferred dividends paid............................................... - (15) (38)
Common dividends paid.................................................. (37,500) (118,900) (39,300)
Term loan.............................................................. (50,000) 50,000 -
---------- --------- ---------
12,104 (69,469) (39,338)
---------- --------- ---------
Net Increase (Decrease) in Cash........................................... 2,969 (344) 511
Cash at Beginning of Year................................................. 539 883 372
---------- --------- ---------
Cash at End of Year....................................................... $ 3,508 $ 539 $ 883
========== ========== =========
</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 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. This accounting change has no direct effect on either the
Company's ability to include the previously deferred items in future rate
proceedings or on its ability to collect the rates set thereby. The Company
believes this accounting change results in financial reporting which better
reflects the results of operations in the economic environment in which the
Company operates. Further, the Company has reexamined the useful lives of its
assets, and during 1997, revised the depreciation rates for certain of its
assets. The impact on earnings from the revised rates was not material in 1997.
- - 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 $24.9 million, $18.6 million and $19.3 million in
1997, 1996 and 1995, respectively. Cash payments for income taxes amounted to
$32.9 million, $29.1 million and $39.5 million in 1997, 1996 and 1995,
respectively.
- - Materials and Supplies
Materials and supplies are carried principally at average cost.
- - Plant, Property and Equipment
Property additions and betterments are capitalized at cost. Property
additions include capitalized interest costs allocable to construction. Such
costs amounted to $.2 million, $1.2 million and $.9 million in 1997, 1996 and
1995, respectively. As a result of the Company's discontinued application of FAS
71 effective November 1, 1996, the Company records capitalized interest based on
the provisions of Statement of Financial Accounting Standards No. 34,
"Capitalization of Interest Cost". Prior to November 1, 1996, and as allowed
under the provisions of FAS 71, such interest costs reflected an allowance for
equity and borrowed funds used during construction. 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.
F-11
<PAGE>
The Company provides for depreciation of gas system facilities on a
straight-line basis with rates that vary by type of property (2% to 10% during
1997). 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 (excluding costs related to unevaluated
properties) plus estimated future development costs by the estimated proved
reserves included therein, as estimated by an independent engineer. The average
amortization rate per equivalent unit of a thousand cubic feet of gas production
for oil and gas operations was $.91 for the year 1997, $.88 for the year 1996
and $.89 for the year 1995. 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 generally 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.
- - Accounting Standards
The Company adopted Statement of Financial Accounting Standards No. 125,
"Accounting for Transfers and Servicing of Financial Assets and Extinguishments
of Liabilities" in 1997. The application of the new standard did not have a
material effect on the Company's consolidated financial position, results of
operations or cash flows.
The Company adopted Statement of Position 96-1 on Environmental Remediation
Liabilities in 1997. The application of the statement did not have a material
effect on the Company's consolidated financial position, results of operations
or cash flows.
The FASB has issued Statement of Financial Accounting Standards No. 131,
"Disclosures about Segments of an Enterprise and Related Information" ("FAS
131") to be effective for fiscal years beginning after December 15, 1997. FAS
131 establishes standards for the way that public business enterprises report
information about operating segments in annual financial statements and requires
that those enterprises report selected information about operating segments in
interim financial reports. It also establishes standards for related disclosures
about products and services, geographic areas, and major customers. The Company
does not believe that the application of the new standard will have a material
effect on its consolidated financial statements.
- - 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.
- - 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 or results of
operations.
F-12
<PAGE>
2. Long-Term Debt
Balances at December 31 were as follows (thousands of dollars):
<TABLE>
<CAPTION>
1997 1996
--------- ---------
<S> <C> <C>
6.85% Senior Debentures, due 2037................................................. $ 100,000 $ -
10% Senior Debentures, due 2005................................................... 179,447 179,373
Senior Term Loan, due 1999........................................................ - 50,000
--------- ---------
$ 279,447 $ 229,373
========= =========
</TABLE>
The 10% Senior Debentures, due 2005, are not redeemable prior to maturity
and have no sinking fund provisions.
In June 1997, the Company issued $100.0 million of 6.85% senior debentures
due in 2037. The net proceeds from the sale of the senior debentures were used
to retire the Company's $50.0 million senior term loan and for general corporate
purposes. The 6.85% senior debentures are not redeemable prior to maturity; but
each holder of such senior debentures has the right to require the Company to
redeem such debentures, in whole or in part, on June 15, 2007, at a redemption
price equal to 100% of the aggregate principal amount thereof plus accrued and
unpaid interest.
Alternatives to finance capital expenditures and other cash needs are
primarily limited by the terms of a Coastal Natural Gas debt instrument. As of
December 31, 1997, the Company and certain affiliates could incur an aggregate
of approximately $2.7 billion 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, 1997, there were no restrictions on retained earnings as to
its availability 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, 1997 December 31, 1996
------------------------ -----------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- ----- -------- -----
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Financial assets:
Cash....................................... $ 3,508 $ 3,508 $ 539 $ 539
Notes receivable from affiliates........... 219,655 219,655 139,390 139,390
Financial liabilities:
Long-term debt............................. 279,447 321,866 229,373 264,600
</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 is based on interest rates at December 31, 1997 and 1996,
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,
--------------------------------
1997 1996 1995
-------- -------- --------
<S> <C> <C> <C>
Current Income Taxes:
Federal............................................................. $ 25,697 $ 39,127 $ 22,406
State............................................................... 3,141 1,962 (285)
-------- -------- --------
28,838 41,089 22,121
-------- -------- --------
Deferred Income Taxes:
Federal............................................................. 13,059 87 19,328
State............................................................... 118 129 2,274
-------- -------- --------
13,177 216 21,602
-------- -------- --------
Taxes on Income........................................................ $ 42,015 $ 41,305 $ 43,723
======== ======== ========
</TABLE>
Coastal and the Internal Revenue Service ("IRS") Appeals Office have
concluded a final settlement of the adjustments originally proposed to federal
income tax returns filed for the years 1985 through 1987. The IRS has
subsequently proposed additional adjustments to those returns, and Coastal will
contest these adjustments before the IRS Appeals Office. 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, 1993 and 1994 began 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,
--------------------------------
1997 1996 1995
-------- -------- --------
<S> <C> <C> <C>
Tax expense computed by applying the U.S. federal income
tax rate of 35%..................................................... $ 42,784 $ 43,177 $ 45,992
Increases (reductions) in taxes resulting from:
State income tax cost............................................... 2,118 1,359 1,293
Tight sands gas credit.............................................. (2,309) (2,586) (2,896)
Other............................................................... (578) (645) (666)
-------- -------- --------
Taxes on Income........................................................ $ 42,015 $ 41,305 $ 43,723
======== ======== ========
</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,
----------------------
1997 1996
--------- --------
<S> <C> <C>
Excess of book basis over tax basis of plant, property and equipment............ $ 111,387 $ 88,417
Other........................................................................... 676 (2,568)
--------- --------
Deferred tax liabilities.................................................... 112,063 85,849
--------- --------
Provisions for rate refunds and contested claims................................ (30,000) (19,756)
Accrued expenses................................................................ (5,999) (4,236)
Other........................................................................... (2,627) (2,790)
--------- --------
Deferred tax assets......................................................... (38,626) (26,782)
--------- --------
Deferred income taxes....................................................... $ 73,437 $ 59,067
========= ========
</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, 1997, 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 Employee Retirement
Income Security Act of 1974, as amended. Colorado made no contributions to the
Plan for 1997, 1996 or 1995. Assets of the Plan are not segregated or restricted
by participating subsidiaries and pension obligations for Company employees
would remain the obligation of the Plan if the Company were to withdraw.
The Company also makes contributions to a thrift plan, which is a trusteed,
voluntary and contributory plan for eligible employees of the Company. The
Company's contributions, which are based on matching employee contributions,
amounted to approximately $2.3 million for 1997 and $2.5 million for each of the
years 1996 and 1995.
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, 1997 and 1996 and the benefit cost for the years ended December 31,
1997, 1996 and 1995 (millions of dollars):
<TABLE>
<CAPTION>
December 31,
----------------------
1997 1996
-------- --------
<S> <C> <C>
Accumulated postretirement benefit obligation:
Retirees...................................................................... $ (9.8) $ (10.9)
Fully eligible plan participants.............................................. - -
Other active plan participants................................................ (4.5) (3.9)
-------- -------
(14.3) (14.8)
Plan assets at fair value.......................................................... 9.0 5.9
-------- -------
Accumulated postretirement benefit obligation in excess of plan assets............. (5.3) (8.9)
Unrecognized net transition obligation............................................. 12.4 13.9
Unrecognized net gain from past experience different from that assumed............. (6.2) (4.0)
-------- --------
Postretirement benefit asset included in consolidated balance sheet................ $ .9 $ 1.0
======== ========
</TABLE>
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------
1997 1996 1995
-------- -------- --------
<S> <C> <C> <C>
Net postretirement benefit cost consisted of the following components:
Service cost - benefits earned during the period.................... $ .2 $ .2 $ .3
Interest cost on accumulated postretirement benefit obligation...... .9 1.0 1.2
Amortization of transition obligation............................... .8 .9 .9
Return on assets, net of deferrals.................................. (.5) (.4) (.3)
Deferred regulatory amount.......................................... - .6 1.1
-------- -------- --------
Net postretirement benefit cost..................................... $ 1.4 $ 2.3 $ 3.2
======== ======== ========
</TABLE>
The assumed health care cost trend rate used in measuring the accumulated
postretirement benefit obligation was 9.7% in 1997, 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 10.4% in 1996 and 11.2% in
1995. 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, 1997 by approximately 3.7% and the net postretirement health
care cost by approximately 3.7%. The assumed discount rate used in determining
the accumulated postretirement benefit obligation was 7.25%.
8. Commitments
The Company and its subsidiaries had rental expense of approximately $5.2
million, $4.7 million and $5.0 million in 1997, 1996 and 1995, respectively
(excluding leases covering natural resources). The aggregate minimum lease
payments under existing noncapitalized long-term leases are estimated to be $3.6
million, $3.3 million, $3.1 million, $3.0 million and $2.3 million for the years
1998-2002, respectively, and $5.0 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, 2005. 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):
1998........................................ $ 7,500
1999........................................ 7,400
2000........................................ 7,200
2001........................................ 7,100
2002........................................ 7,000
Later years................................. 26,600
The Company expensed approximately $6.0 million related to this agreement
in 1997.
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, Environmental 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 new trial was denied on July 18, 1997, and both parties have filed appeals.
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.
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 or
results of operations.
- - Environmental Matters
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
million on environmental capital projects in 1997 and anticipates annual
environmental capital expenditures of $1 to $2 million over the next several
years aimed
F-17
<PAGE>
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
consolidated financial position or results of operations.
- - Regulatory 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.
Colorado has made such filing and the FERC has accepted that tariff filing.
Under the Policy Statement, a pipeline must also make subsequent tariff filings
each time the pipeline negotiates a rate for service which is outside of the
minimum and maximum range for the pipeline's cost-based recourse rates. Some
parties have sought judicial review of the FERC's acceptance of the Company's
tariff filing to implement negotiated rates, but Colorado's tariff sheet remains
in effect pending review. Colorado has filed for judicial review of the FERC's
holding that pipelines which have entered into "negotiated rate" contracts will
not be allowed discount adjustments in connection with such contracts. 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 March 29, 1996, Colorado filed with the FERC under Docket No. RP96-190
to increase its rates by approximately $30 million annually, to realign certain
transportation services and to add tariff language that would allow Colorado to
enter into "negotiated rates" (rates which could exceed the Company's
"cost-based" rates) in certain circumstances, subject to FERC policies. On April
25, 1996, the FERC accepted the rate change filing and the transportation
service realignment to become effective October 1, 1996, subject to refund, and
also accepted the "negotiated rate" tariff provision to become effective May 1,
1996. Certain parties sought judicial review of the acceptance of the
"negotiated rate" tariff provisions. On October 16, 1997, the FERC approved an
unopposed settlement filed by Colorado that resolves all issues in this general
rate case except the issues that are on appeal relating to the "negotiated rate"
tariff provisions. The final settlement modifies the services provided by
Colorado, and the charges for those services. The final settlement became
effective on November 17, 1997, and is no longer subject to review by the FERC
or subject to any judicial review. Colorado has now made refunds of amounts
collected which were in excess of the final settlement rates. The appeal of the
"negotiated rate" provision has been consolidated with other appeals involving
the same issues, and is being held in abeyance by the United States Court of
Appeals for the D. C. Circuit. Pending completion of judicial review, the
"negotiated rate" tariff provisions are fully effective, although during 1997
Colorado did not enter into any "negotiated rate" transactions.
In July 1996, the United States Court of Appeals for the D.C. Circuit
upheld the basic structure of the FERC's Order 636 (issued in April 1992), but
remanded to the FERC, for further consideration, certain limited aspects of the
Order, including the 20-year term established in Order 636 as the "cap" to be
applied to evaluation of bids for renewal contracts on existing facilities. On
remand in February 1997, the FERC reduced the term "cap" to five years. Colorado
and others have sought rehearing of this change and on other aspects of the
Order on remand. Colorado argued in its rehearing
F-18
<PAGE>
request inter alia that its FERC-approved settlement of its Order 636 compliance
proceeding precludes applying this change to Colorado's existing contracts
entered into pursuant to Colorado's FERC-approved tariff.
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 or results of operations. 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 historically followed the reporting and accounting requirements of FAS
71. Effective November 1, 1996, the Company ceased to apply the provision of FAS
71 to its transactions and balances. The Company believes this accounting change
results in financial reporting which better reflects the results of operations
in the economic environment in which the Company now operates. The impact of
these changes was a charge to earnings in 1996 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.
11. Quarterly Results of Operations (Unaudited)
The results of operations by quarter for the years ended December 31, 1997
and 1996 were (thousands of dollars):
<TABLE>
<CAPTION>
1997 Quarter Ended
----------------------------------------------
March 31, June 30, Sept. 30, Dec. 31,
--------- -------- --------- --------
<S> <C> <C> <C> <C>
Revenues................................................. $ 120,809 $ 105,536 $ 116,066 $ 119,212
Cost of gas sold......................................... 29,795 18,993 26,952 28,540
--------- ---------- ---------- ---------
Revenues less cost of gas sold........................ 91,014 86,543 89,114 90,672
Other costs and expenses................................. 69,824 70,411 68,069 68,815
--------- ---------- ---------- ---------
Net earnings.......................................... $ 21,190 $ 16,132 $ 21,045 $ 21,857
========= ========== ========== =========
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>
Pursuant to the Company's FERC Docket No. RP96-190 Settlement, a new rate
and service structure providing for seasonal contractual changes has been put
into place. Under the new structure, the Company's revenues will tend to be
higher in the two heating-season quarters of the year (first and fourth
quarters) than in the other two quarters. No significant difference in the total
annual levels of revenue and earnings is expected to result from this change.
12. Segment Reporting
Natural gas system operations and gas and oil exploration and production
are the two segments of the Company's operations.
F-19
<PAGE>
Natural gas system operations involve the production, purchase, gathering,
storage, transportation and sale of natural gas, principally to and for public
utilities, industrial customers, other pipelines, and other gas customers, as
well as the operation of natural gas liquids extraction plants.
Gas and oil exploration and production operations involve primarily the
development and production of natural gas, crude oil, condensate and natural gas
liquids. Sales are made to affiliated companies, industrial users, interstate
pipelines and distribution companies in the Rocky Mountain, Central and
Southwest United States.
Operating revenues by segment include both sales to unaffiliated customers,
as reported in the Company's statement of consolidated earnings, and
intersegment sales, which are accounted for on the basis of contract, current
market, or internally established transfer prices. The intersegment sales are
from the exploration and production segment to the natural gas segment.
Operating profit is total revenues less interest income from affiliates and
operating expenses. Operating expenses exclude income taxes, corporate general
and administrative expenses and interest.
Identifiable assets by segment are those assets that are used in the
Company's operations in each segment.
F-20
<PAGE>
The Company's operating revenues and operating profit (loss) for the years
ended December 31, 1997, 1996 and 1995, and identifiable assets as of December
31, 1997, 1996 and 1995, by segment, are shown below (thousands of dollars):
<TABLE>
<CAPTION>
Operating
Operating Profit Identifiable
Revenues (Loss) Assets
-------------- -------------- --------------
<S> <C> <C> <C>
1997
- ----
Natural gas............................................ $ 437,445 $ 133,386 $ 1,036,629
Exploration and production............................. 26,280 6,242 26,801
Adjustments and eliminations........................... (14,649) - -
-------------- -------------- --------------
Segment totals...................................... 449,076 139,628 1,063,430
Other income-net....................................... 12,547 12,547 -
Corporate general and administrative expenses.......... - (6,120) -
Interest............................................... - (23,816) -
Income taxes........................................... - (42,015) -
-------------- -------------- --------------
Consolidated Totals................................. $ 461,623 $ 80,224 $ 1,063,430
============== ============== ==============
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
============== ============== ==============
</TABLE>
F-21
<PAGE>
Capital expenditures and depreciation, depletion and amortization expense
by segment for the years ended December 31, 1997, 1996 and 1995, were (thousands
of dollars):
<TABLE>
<CAPTION>
Depreciation,
Depletion and
Capital Amortization
Segment Expenditures Expense
------- ------------ --------------
<S> <C> <C>
1997
----
Natural gas................................................. $ 47,032 $ 27,419
Exploration and production.................................. 18,571 11,908
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
</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,
1997 1996 1995
---------- ---------- ---------
<S> <C> <C> <C>
Public Service Company of Colorado
Amount (thousands of dollars)....................................... $ 165,793 $ 167,222 $ 160,523
========== ========= =========
Percent............................................................. 36% 39% 40%
========== ========= =========
</TABLE>
Revenues from any other single customer did not amount to 10% or more of
the Company's consolidated revenues for the years ended December 31, 1997, 1996
and 1995. The Company does not have any foreign operations.
Gas sales are made primarily to public utilities and natural gas marketers
which resell the gas to residential, commercial and industrial customers and to
end-users in Colorado and southeastern Wyoming. Deliveries from the Company's
field system are made to markets in the Texas Panhandle region. Transportation
services are provided for brokers, producers, marketers, distributors, end-users
and other pipelines. The Company extends credit for sales and transportation
services provided to certain qualifying companies.
F-22
<PAGE>
13. Transactions with Related Parties
The Statement of Consolidated Earnings includes the following major
transactions with related parties (thousands of dollars):
<TABLE>
<CAPTION>
1997 1996 1995
------------------ ------------------- -----------------
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.......................... $ 3,585 1.7% $ 2,281 1.2% $ 2,005 1.0%
Engage Energy US, L.P.(F1)................. 10,551 4.9 8,268 4.2 9,257 4.6
Coastal Oil & Gas Corporation ............. 1,679 .8 2,521 1.3 2,439 1.2
CIG Resources Company...................... 4,935 2.3 3,440 1.8 - -
CIG Merchant Company....................... 3,423 1.6 - - - -
Gas Sales -
Engage Energy US, L.P.(F1)................. $ 7,507 3.9% $ 7,295 4.5% $ 6,348 5.1%
CIG Resources Company...................... 35,981 18.9 9,429 5.9 323 .3
CIG Merchant Company....................... 32,481 17.1 - - - -
Extracted Products and Gas Processing -
Coastal Refining & Marketing, Inc.......... $ 6,415 27.6% $ 24,791 92.5% $ 26,047 97.6%
Coastal States Trading, Inc................ - - - - 351 1.3
Coastal Field Services Company............. 11,295 48.6 1,461 5.4 - -
Incidental Gasoline, Oil and Condensate
Sales -
Coastal Refining & Marketing, Inc.......... $ 2,403 37.0% $ 1,473 29.1% $ 1,348 35.0%
Coastal States Trading, Inc................ 1,560 24.0 1,294 25.5 1,342 34.8
Natural Gas Production -
Engage Energy US, L.P.(F1)................. $ 3,161 13.3% $ 6,878 33.9% $ 5,671 43.4%
Coastal States Trading, Inc................ - - 268 1.3 241 1.8
Miscellaneous -
Coastal Refining & Marketing, Inc.......... $ 98 3.1% $ 210 10.6% $ 285 11.2%
Costs and Expenses
Gas Purchases -
Engage Energy US, L.P.(F1)................. $ 559 .6% $ 258 .2% $ 1,345 1.9%
Coastal Limited Ventures, Inc.............. 407 .4 290 .2 - -
Coastal Oil & Gas Corporation.............. 11,482 12.2 6,077 5.8 3,156 4.5
Gathering, Transportation and Compression -
WIC........................................ $ 5,969 72.5% $ 4,778 67.3% $ 4,425 55.6%
ANR Pipeline Company....................... - - 766 10.8 178 2.2
- -----------------------
<FN>
<F1>
Formerly Coastal Gas Marketing Company, which became a part of Engage Energy
US, L.P. and Engage Energy Canada, L.P., in February 1997. Coastal has a 50%
interest in these two companies.
</FN>
</TABLE>
F-23
<PAGE>
Services provided by the Company at cost for affiliated companies were $6.3
million for 1997, $7.0 million for 1996 and $5.9 million for 1995. Services
provided by affiliated companies for the Company at cost were $7.5 million for
1997, $8.2 million for 1996 and $7.6 million for 1995. 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. The leases were terminated in 1996 and the related
facilities were purchased by the Company. Rental expense of approximately $.9
million in 1996 and $1.3 million in 1995 was recorded in conjunction with the
terms of the lease agreements.
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, 1997, the Company had advanced
$219.7 million to associated companies at a market rate of interest. Such amount
is repayable on demand.
At December 31, 1997, the Company's investment in an affiliate, Coastal
Medical Services, Inc., was $38.9 million. The affiliate has assumed the
responsibility for facilitating the management of a portion of the medical
obligations of the Company and other Coastal subsidiaries.
F-24
<PAGE>
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
Reserves, capitalized costs, costs incurred in oil and gas acquisition,
exploration and development activities, results of operations and the
standardized measure of discounted future net cash flows are presented for the
exploration and production segment. Natural gas 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>
Estimated Quantities of Proved Reserves
<CAPTION>
Natural Gas Exploration
Company-Owned Reserves System and Production
---------------------- ----------- --------------------------
Developed Developed Undeveloped Total
----------- --------- ----------- -----
<S> <C> <C> <C> <C>
Natural Gas (MMcf):
------------------
1997............................................. 248,248 75,200 38,883 362,331
1996............................................. 267,927 74,963 39,803 382,693
1995............................................. 302,420 66,282 7,090 375,792
Oil, Condensate and Natural Gas Liquids (000 barrels):
-----------------------------------------------------
1997............................................. 349 543 363 1,255
1996............................................. 391 427 282 1,100
1995............................................. 126 323 36 485
</TABLE>
Changes in proved reserves since the end of 1994 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 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
-------- -------- -------- ------
Production during 1997.......................... (38,135) (12,365) (57) (129)
Extensions and discoveries...................... 8,870 18,169 - 284
Acquisitions.................................... - - - -
Sales of reserves in place...................... - (12,924) - (15)
Revisions of previous quantity estimates and
other.......................................... 9,586 6,437 15 57
-------- -------- -------- ------
Total, end of 1997.............................. 248,248 114,083 349 906
======== ======== ======== ======
</TABLE>
F-25
<PAGE>
Total proved reserves for the natural gas system exclude storage gas and
liquids volumes. The natural gas system storage gas volumes are 40,376, 38,842
and 39,215 MMcf and storage liquids volumes are approximately 209,000, 192,000
and 138,000 barrels at December 31, 1997, 1996 and 1995, respectively. Volumes
are based on Huddleston's report and include estimates which differ slightly
from actuals.
<TABLE>
Capitalized Costs Relating to Exploration and Production Activities
(thousands of dollars)
<CAPTION>
December 31,
--------------------------
1997 1996
----------- -----------
<S> <C> <C>
Proved and Unproved Properties
Proved Properties................................................................... $ 129,770 $ 124,368
Unproved Properties................................................................. 730 656
----------- -----------
130,500 125,024
Accumulated depreciation, depletion and amortization................................ (107,489) (101,080)
----------- -----------
$ 23,011 $ 23,944
=========== ===========
</TABLE>
The Company follows the full-cost method of accounting for oil and gas
properties.
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, 1997.
The Company regularly evaluates these costs to determine whether impairment has
occurred.
<TABLE>
<CAPTION>
Years Costs Incurred
---------------------------------------------------------------------
Prior
Total 1997 1996 1995 to 1995
----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Property Acquisition...................... $ - $ - $ - $ - $ -
Exploration............................... 197 174 23 - -
Capitalized Interest...................... 5 5 - - -
----------- ----------- ----------- ----------- -----------
$ 202 $ 179 $ 23 $ - $ -
=========== =========== =========== =========== ============
</TABLE>
<TABLE>
Costs Incurred in Oil and Gas Acquisition, Exploration and Development Activities
(thousands of dollars)
<CAPTION>
Year Ended December 31,
--------------------------------
1997 1996 1995
-------- -------- --------
<S> <C> <C> <C>
Property acquisition costs:
Proved................................................................. $ 27 $ 51 $ 436
Unproved............................................................... 8 2 -
Exploration costs............................................................ 237 107 40
Development costs............................................................ 18,178 5,040 3,200
</TABLE>
F-26
<PAGE>
<TABLE>
Results of Operations for Exploration and Production Activities
(thousands of dollars)
<CAPTION>
Year Ended December 31,
--------------------------------
1997 1996 1995
-------- -------- --------
<S> <C> <C> <C>
Revenues:
Sales..................................................................... $ 5,255 $ 1,994 $ 2,313
Transfers................................................................. 20,847 17,256 10,799
-------- -------- --------
Total.................................................................. 26,102 19,250 13,112
Production costs............................................................. (5,660) (3,656) (4,142)
Operating expenses........................................................... (2,467) (2,165) (2,590)
Depreciation, depletion and amortization..................................... (11,908) (11,450) (9,855)
-------- -------- --------
6,067 1,979 (3,475)
Income tax benefit .......................................................... 186 1,893 4,112
-------- --------- --------
Results of operations for producing activities (excluding corporate
overhead and interest costs).............................................. $ 6,253 $ 3,872 $ 637
======== ======== ========
<FN>
The average amortization rate per equivalent Mcf was $0.91 in 1997, $0.88 in
1996 and $0.89 in 1995.
</FN>
</TABLE>
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,
----------------------------------------------------------------------------------
1997 1996 1995
------------------------- ----------------------- -----------------------
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.......... $ 291,333 $ 239,278 $ 430,290 $ 440,567 $ 286,853 $ 104,369
Future production and
development costs......... (87,111) (112,544) (85,619) (139,864) (82,282) (49,586)
Future income tax expenses... (66,657) (28,622) (117,047) (93,337) (68,163) (6,872)
----------- ----------- ----------- ----------- ----------- -----------
Future net cash flows........ 137,565 98,112 227,624 207,366 136,408 47,911
10% annual discount for
estimated timing of cash
flows..................... (57,330) (37,876) (87,979) (88,165) (61,368) (14,278)
----------- ----------- ----------- ----------- ----------- -----------
Standardized measure of
discounted future net
cash flows................ $ 80,235 $ 60,236 $ 139,645 $ 119,201 $ 75,040 $ 33,633
=========== =========== =========== =========== =========== ===========
</TABLE>
F-27
<PAGE>
<TABLE>
Principal sources of change in the standardized measure of discounted
future net cash flows during each year are as follows (thousands of dollars):
<CAPTION>
Year Ended December 31,
----------------------------------------------------------------------------------
1997 1996 1995
------------------------- ------------------------- --------------------------
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.......... $ (34,454) $ (19,411) $ (44,992) $ (14,644) $ (30,580) $ (7,726)
Net changes in prices and
production costs.......... (52,962) (80,968) 94,990 73,599 45,874 (10,302)
Extensions and discoveries... 10,343 12,625 3,548 48,073 - 1,149
Acquisitions................. - - - 2,169 941 388
Sales of reserves in-place... - (19,840) - (1,668) - -
Development costs incurred
during the period that
reduced estimated future
development costs......... - - - 167 - 496
Revisions of previous quantity
estimates, timing and other (34,149) (4,187) 38,935 22,054 (15,449) (4,573)
Accretion of discount........ 17,924 15,171 6,680 2,142 7,325 4,497
Net change in income taxes... 33,888 37,645 (34,556) (46,324) (843) 3,174
----------- ----------- ----------- ----------- ----------- -----------
Net change.............. $ (59,410) $ (58,965) $ 64,605 $ 85,568 $ 7,268 $ (12,897)
=========== =========== =========== =========== =========== ===========
</TABLE>
None of the amounts include any value for storage gas and liquids volumes,
which were approximately 40.4 Bcf and 209 thousand barrels, respectively, at the
end of 1997. Volumes are based on Huddleston's report and include estimates
which differ slightly from actuals.
F-28
<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
Subsidiary:
*Great Divide Gas Services, LLC (73%)....................... Colorado
Colorado Water Supply Company..................................... Delaware
Subsidiary:
Colorado Interstate Production Company...................... Delaware
* Not consolidated
EXHIBIT 23
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
February 3, 1998, appearing in this Annual Report on Form 10-K of Colorado
Interstate Gas Company for the year ended December 31, 1997.
DELOITTE & TOUCHE LLP
Houston, Texas
March ___, 1998
<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, 1997 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-31-1997
<PERIOD-END> DEC-31-1997
<CASH> 3,508
<SECURITIES> 0
<RECEIVABLES> 102,376
<ALLOWANCES> 0
<INVENTORY> 8,841
<CURRENT-ASSETS> 373,099
<PP&E> 1,293,407
<DEPRECIATION> 689,690
<TOTAL-ASSETS> 1,063,430
<CURRENT-LIABILITIES> 170,597
<BONDS> 279,447
0
0
<COMMON> 27,561
<OTHER-SE> 431,815
<TOTAL-LIABILITY-AND-EQUITY> 1,063,430
<SALES> 449,076
<TOTAL-REVENUES> 461,623
<CGS> 104,280
<TOTAL-COSTS> 315,568
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 23,816
<INCOME-PRETAX> 122,239
<INCOME-TAX> 42,015
<INCOME-CONTINUING> 80,224
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 80,224
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
</TABLE>
