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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, 1998 or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from ______________ to _______________
Commission file number 1-4874
COLORADO INTERSTATE GAS COMPANY
(Exact name of registrant as specified in its charter)
Delaware 84-0173305
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
Two North Nevada Avenue
Colorado Springs, Colorado 80903-1727
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (719) 473-2300
---------------------------
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
--------------------------------- ---------------------------
10% Senior Debentures, due 2005 { New York Stock Exchange
6.85% Senior Debentures, due 2037
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Registrant meets the conditions set forth in General Instructions (I)(1)(a)
and (b) of Form 10-K and is therefore filing this Report with reduced disclosure
format.
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 10, 1999, 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
Reserves............................................... 3
Reserves Dedicated to a Particular Customer............ 3
Regulations Affecting Gas System.......................... 3
General................................................ 3
Rate Matters........................................... 3
Gas and Oil Exploration and Production.................... 4
Environmental............................................. 6
2. Properties...................................................... 6
3. Legal Proceedings............................................... 6
4. Submission of Matters to a Vote of Security Holders............. 7
PART II
5. Market for the Registrant's Common Equity and Related
Stockholder Matters............................................. 8
6. Selected Financial Data......................................... 8
7. Management's Discussion and Analysis of Financial Condition
and Results of Operations....................................... 8
7A. Quantitative and Qualitative Disclosures About Market Risk...... 8
8. Financial Statements and Supplementary Data..................... 8
9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure........................................ 8
PART III
10. Directors and Executive Officers of the Registrant.............. 9
11. Executive Compensation.......................................... 9
12. Security Ownership of Certain Beneficial Owners and Management.. 9
13. Certain Relationships and Related Transactions.................. 9
PART IV
14. Exhibits, Financial Statement Schedules, and Reports on
Form 8-K........................................................ 10
(i)
<PAGE>
GLOSSARY
"AICPA" means American Institute of Certified Public Accountants
"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
"Pioneer" means Pioneer Natural Resources, USA, Inc.
"PSCo" means Public Service Company of Colorado.
"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. The forward-
looking statements reflect the Company's expectations, objectives and goals
with respect to future events and financial performance and are based on
assumptions and estimates which the Company believes are reasonable. However,
actual results could differ materially from anticipated results. Important
factors which may affect the actual results include, but are not limited to,
commodity prices, political developments, market and economic conditions,
industry competition, the weather, changes in financial markets, changing
legislation and regulations, and the impact of the Year 2000 issue. The
forward-looking statements contained in this Report are intended to qualify for
the safe harbor provisions of Section 21E of the Securities Exchange Act of
1934, as amended.
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, 1998, the Company had 811 employees.
Selected financial information of the Company by industry segment is set
forth in Note 11 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. Colorado owns four underground gas storage fields - three located in
Colorado and one in Kansas.
PSCo and Pioneer were the only customers accounting for revenue that
equaled or exceeded 10% of the Company's consolidated revenues for the year
1998. PSCo was the only customer that accounted for more than 10% of the
Company's consolidated revenues in 1997 and 1996. In 1998, the Company completed
construction of the 53-mile Front Range Pipeline. This pipeline, which is to be
owned by an entity jointly owned by affiliates of the Company and the Company's
largest customer, PSCo, can transport up to 256 MMcf per day to accommodate
regional market growth.
The Company's principal transmission and storage pipeline facilities,
including certain facilities in the Panhandle Field of Texas ("Panhandle
Field"), at December 31, 1998 consisted of 4,351 miles of pipeline and 58
compressor stations with approximately 296,300 installed horsepower. At December
31, 1998, the design peak day gas delivery capacity of the transmission system
was approximately 2.2 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 2,372 miles of gathering lines and
approximately 50,700 horsepower of compression. Colorado owned and operated five
gas processing plants in 1998. 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 gas sales consist primarily of Company-owned production.
Effective July 1, 1998, those gas purchases and sales formerly conducted by the
Company's unincorporated Merchant Division were assigned to an affiliate.
Therefore, revenues and cost of gas sold associated with such activities
subsequent to June 30, 1998 are not included
1
<PAGE>
in the Company's consolidated financial statements. Additionally, Colorado
engages in "open access" storage and transportation of gas owned by third
parties.
Pursuant to an operating agreement with an affiliate, the Company operates
the Young Gas Storage Field located in northeastern Colorado. The field has 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 1998, 1997 and 1996 were as follows:
Total System Daily Average
Year Deliveries System Deliveries
---- ------------ -----------------
(Bcf) (MMcf)
1998 480 1,315
1997 486 1,333
1996 475 1,298
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 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 46 million gallons of
liquid hydrocarbons in 1998 compared to 55 million gallons in 1997, and 66
million gallons in 1996, as well as 300 long tons of sulfur in 1998, compared to
500 long tons in 1997 and 3,100 long tons in 1996. Additionally, Colorado
processed approximately 25 million gallons of liquid hydrocarbons owned by
others in 1998 compared to 24 million gallons in 1997 and 6 million gallons in
1996.
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 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
Reserves
The table below represents estimates of the Company's owned or controlled
reserves as of December 31, 1998, 1997 and 1996, as prepared by Huddleston,
Colorado's independent engineers.
<TABLE>
<CAPTION>
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
Owned or controlled by Colorado (Bcf).................................... 243 284 307
</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, 1998, Colorado maintained under its own account 3.5 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, 1998, and vary slightly from the
Huddleston report which includes estimates for November and December 1998.
Reserves Dedicated to a Particular Customer
Colorado is committed to sell gas to Pioneer, 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, 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. The Company is also subject to laws and
regulations associated with environmental matters as discussed on Page 6.
Rate Matters
On January 31, 1996, the FERC issued a "Statement of Policy and Request for
Comments" ("Policy"). Under this Policy, (i) a pipeline and a customer are
allowed to negotiate a contract which provides for rates and charges that exceed
the pipeline's posted maximum tariff rates, provided that the customer 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"), and (ii) a pipeline
must also make subsequent tariff filings each time the pipeline negotiates a
rate for service which is outside of the minimum
3
<PAGE>
and maximum range for the pipeline's cost-based recourse rates. To implement
this Policy, a pipeline must make an initial tariff filing with the FERC to
indicate that it intends to contract for services under this Policy. Colorado
has received FERC authority to enter into negotiated rate transactions.
Separately, the FERC has determined that pipelines who seek to include
negotiated rate transactions in the discount adjustment used to calculate their
rates must file tariff sheets demonstrating that existing customers who purchase
service under the pipeline's cost-of-service rates will not be harmed by
negotiated rate discounts.
On July 29, 1998, the FERC issued a "Notice of Proposed Rulemaking," in
which the FERC has proposed a number of further significant changes to the
industry, including, among other things, removal of price caps in the short-term
market (less than one year), capacity auctions, changed reporting obligations,
the ability to negotiate terms and conditions of all services, elimination of
the requirement of a matching term cap on the renewal of existing contracts, and
a review of its policies for approving capacity construction. On the same day,
the FERC also issued a "Notice of Inquiry" soliciting industry input on various
matters affecting the pricing of long-term service and certificate pricing in
light of changing market conditions. The due date for comments on both of these
matters has been rescheduled twice and is currently scheduled for April 22,
1999. The FERC has indicated that it may consider both proposals together
inasmuch as they raise several common issues.
Certain regulatory issues remain unresolved among the Company, its
customers, its suppliers and the FERC. The Company has made provisions which
represent management's assessment of the ultimate resolution of these issues. 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.
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 and 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, 1998:
<TABLE>
<CAPTION>
1998 1997 1996
------ ------ ------
<S> <C> <C> <C>
Exploration and Production
Gas (MMcf)...................................................... 10,949 12,365 12,304
Oil, Condensate and Natural Gas Liquids (000 barrels)........... 64 129 114
Natural Gas System
Gas (MMcf)...................................................... 39,058 38,135 39,405
Oil, Condensate and Natural Gas Liquids (000 barrels)........... 44 57 23
</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, 1998:
<TABLE>
<CAPTION>
1998 1997 1996
-------- -------- --------
<S> <C> <C> <C>
Average sales price:
Gas - per Mcf................................................... $ 1.69 $ 1.96 $ 1.51
Oil, Condensate and Natural Gas Liquids - per barrel............ 13.36 14.84 15.49
Average production cost per unit (equivalent Mcf).................... $ 0.58 $ 0.43 $ 0.28
</TABLE>
4
<PAGE>
Acreage held under gas and oil mineral leases as of December 31, 1998 is
summarized as follows:
<TABLE>
<CAPTION>
Undeveloped Developed
------------------------ -------------------------
Area Gross Net Gross Net
-------------------------------------------------------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Exploration and Production.............................. 15,818 5,780 40,615 29,217
Natural Gas System...................................... - - 262,474 259,276
----------- ----------- ----------- -----------
15,818 5,780 303,089 288,493
=========== =========== =========== ===========
</TABLE>
The net developed acreage is concentrated principally in Texas (84%),
Oklahoma (6%), Utah (6%) and Wyoming (3%). The net undeveloped acreage is
principally in Wyoming (56%) and Utah (43%).
Information on wells drilled in the three years ended December 31, 1998, is
summarized as follows:
<TABLE>
<CAPTION>
1998 1997 1996
------------------------ ------------------------ -------------------------
Gross Net Gross Net Gross Net
----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Exploration and Production
--------------------------
Development Wells
-----------------
Oil........................ - - - - - -
Gas........................ 20 17.66 29 20.82 5 1.86
Dry Holes.................. - - - - - -
----------- ----------- ----------- ----------- ----------- -----------
20 17.66 29 20.82 5 1.86
----------- ----------- ----------- ----------- ----------- -----------
Natural Gas System
------------------
Development Wells
-----------------
Oil........................ - - - - 2 2.00
Gas........................ 6 6.00 3 3.00 8 8.00
Dry Holes.................. - - - - - -
----------- ----------- ----------- ----------- ----------- -----------
6 6.00 3 3.00 10 10.00
----------- ----------- ----------- ----------- ----------- -----------
Total.................. 26 23.66 32 23.82 15 11.86
=========== =========== =========== =========== =========== ===========
</TABLE>
Productive wells as of December 31, 1998 are as follows:
<TABLE>
<CAPTION>
Type of Well Gross Net
---------------------------------------------------------------------------------- ----------- -----------
<S> <C> <C>
Exploration and Production
Oil.......................................................................... 3 2.09
Gas.......................................................................... 303 223.43
----------- -----------
Total Exploration and Production...................................... 306 225.52
----------- -----------
Natural Gas System
Oil.......................................................................... 9 8.24
Gas.......................................................................... 777 773.34
----------- -----------
Total Natural Gas System.............................................. 786 781.58
----------- -----------
Total..................................................... 1,092 1,007.10
=========== ===========
</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.
5
<PAGE>
The Company competes with major integrated oil companies and independent
oil and gas companies for suitable prospects for oil and gas drilling
operations. The availability of a ready market for gas discovered and produced
depends on numerous factors frequently beyond the Company's control. These
factors include the extent of gas discovery and production by other producers,
crude oil imports, the marketing of competitive fuels, and the proximity,
availability and capacity of gas pipelines and other facilities for the
transportation and marketing of gas. The production and sale of oil and gas is
subject to a variety of federal and state regulations, including regulation of
production levels.
ENVIRONMENTAL
The Company's operations are subject to extensive and evolving federal,
state and local environmental laws and regulations which may affect such
operations and costs as a result of their effect on the construction, operation,
and maintenance of its pipeline and production facilities. Compliance with such
laws and regulations can be costly. Additionally, governmental authorities may
enforce the laws and regulations with a variety of civil and criminal
enforcement measures, including monetary penalties and remediation requirements.
The Company spent approximately $1 million in 1998 on environmental capital
projects and anticipates capital expenditures of $1 to $2 million in 1999 in
order to comply with such laws and regulations.
Future information and developments, including legislative and enforcement
developments, will require the Company to continually reassess the expected
impact of these environmental matters. However, the Company has evaluated its
total environmental exposure based on currently available data, including its
potential joint and several liability, and believes that compliance with all
applicable laws and regulations will not 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 of royalties, breach of fiduciary duty,
fraud and negligent misrepresentation. Management believes that Colorado has
numerous defenses to the lessors' claims, including (i) that the royalties were
properly paid, (ii) that the majority of the claims were released by written
agreement and (iii) that the majority of the claims are barred by the statute of
limitations. In March of 1995, the trial court granted a partial summary
judgment in favor of Colorado, holding that the four-year statute of limitations
had not been tolled, that the releases are valid, and dismissing all tort claims
and claims for breach of any duty of disclosure. The remaining claim for
underpayment of royalties was tried to a jury which, in May 1995, made findings
favorable to Colorado. On June 7, 1995, the trial court entered a judgment that
the lessors recover no monetary damages from Colorado and permanently estopping
the lessors from asserting any claim based on an interpretation of the contract
different than that asserted by Colorado in the litigation. The lessors' motion
for a new trial was denied on July 18, 1997, and both parties 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 suit pending the outcome of the
first lawsuit. Oral arguments were heard before the Fifth Circuit Court of
Appeals on December 4, 1998 and the parties are awaiting the Court's decision.
6
<PAGE>
In 1996, Jack Grynberg filed a claim under the False Claims Act on behalf
of the U.S. government in the U.S. District Court, District of Columbia, against
70 defendants, including Colorado and another subsidiary of Coastal. The suit
sought damages for the alleged underpayment of royalties due to the purported
improper measurement of gas. The 1996 suit was dismissed without prejudice in
March 1997 and the dismissal was affirmed by the D.C. Court of Appeals in
October 1998. In September 1997, Mr. Grynberg filed 77 separate, similar False
Claims Act suits against natural gas transmission companies and producers,
gatherers, and processors of natural gas, seeking unspecified damages. Colorado,
Coastal and several other Coastal subsidiaries have been included in two of the
September 1997 suits. The suits were filed in both the U.S. District Court,
District of Colorado and the U.S. District Court, Eastern District of Michigan.
The United States Department of Justice has notified the Company that it is
reviewing these lawsuits to determine whether or not the United States will
intervene.
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 such 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.
7
<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, 1998, 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, 1997, 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,
-----------------------------------------------------------------
1998* 1997 1996** 1995 1994
----------- ----------- ----------- ----------- ----------
<S> <C> <C> <C> <C> <C>
Operating revenues........................... $ 380,365 $ 449,076 $ 412,477 $ 382,200 $ 386,553
Earnings before extraordinary item........... 77,795 80,224 82,058 87,716 78,507
Total assets................................. 1,116,267 1,063,430 908,922 861,448 962,111
Long-term debt, excluding current maturities. 279,520 279,447 229,373 179,299 179,225
Mandatory redemption preferred stock......... - - - 556 556
Common stock and other stockholder's equity.. 496,471 459,376 416,652 459,808 411,423
<FN>
- ----------------------
* Effective July 1, 1998, those gas purchases and sales formerly conducted
by the Company's unincorporated Merchant Division were assigned to an
affiliate. Therefore, revenues and cost of gas sold associated with such
activities subsequent to June 30, 1998 are not included in the Company's
consolidated financial statements.
** 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-6 herein.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
For the information required by this item, see discussion under
Management's Discussion and Analysis of Financial Condition and Results of
Operations, which is presented on page F-2.
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.
8
<PAGE>
PART III
Item 10. Directors and Executive Officers of the Registrant.
The directors and executive officers of Colorado as of March 10, 1999, were
as follows:
Name (Age), Year First Elected Positions and Offices
Director and/or Officer with the Registrant
---------------------------------- --------------------------
Jon R. Whitney (54), 1987 and 1974 President, Chief Executive
Officer and Director
Jeffrey A. Connelly (52), 1996 Director
David A. Arledge (54), 1981 Director
Harold Burrow (84), 1974 Director
C. Scott Hobbs (45), 1985 Executive Vice President,
Chief Operating Officer
and Director
Daniel F. Collins (57), 1986 Senior Vice President
Donald H. Gullquist (55),1994 Senior Vice President
Rebecca H. Noecker (47), 1988 Senior Vice President and
General Counsel
Austin M. O'Toole (63), 1984 Senior Vice President and
Secretary
Richard G. Smead (52), 1988 Senior Vice President
Donald J. Zinko (54), 1988 Senior Vice President
Thomas E. Jackson, Jr. (59), 1989 Vice President
Jeffrey B. Levos (38), 1997 Vice President
Ronald D. Matthews (51), 1994 Vice President and Treasurer
Thomas L. Price (43), 1997 Vice President
Robert O. Reid (52), 1985 Vice President
William H. Sparger (56), 1992 Vice President
Dan A. Homec (50), 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 1999. 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 of Colorado in May 1997 and 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.
Item 11. Executive Compensation.
The information called for by this item is omitted pursuant to General
Instruction (I) of Form 10-K.
Item 12. Security Ownership of Certain Beneficial Owners and Management.
The information called for by this item is omitted pursuant to General
Instruction (I) of Form 10-K.
Item 13. Certain Relationships and Related Transactions.
The information called for by this item is omitted pursuant to General
Instruction (I) of Form 10-K.
9
<PAGE>
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a) The following documents are filed as part of this Annual Report or
incorporated herein by reference:
1. Financial Statements and Supplemental Information.
The following Consolidated Financial Statements of Colorado and
Subsidiaries and Supplemental Information are included in response to
Item 8 hereof on the attached pages as indicated:
Page
----
Independent Auditors' Report.................................... F-7
Consolidated Balance Sheet at December 31, 1998 and 1997........ F-8
Statement of Consolidated Earnings for the Years Ended
December 31, 1998, 1997 and 1996.............................. F-10
Statement of Consolidated Retained Earnings and Additional
Paid-In Capital for the Years Ended December 31, 1998, 1997
and 1996...................................................... F-10
Statement of Consolidated Cash Flows for the Years Ended
December 31, 1998, 1997 and 1996.............................. F-11
Notes to Consolidated Financial Statements...................... F-12
Supplemental Information on Oil and Gas Producing
Activities (Unaudited)........................................ F-24
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-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 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,
1998.
10
<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 26, 1999
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 By: DAVID A. ARLEDGE
----------------------------- -----------------------------
Jeffrey A. Connelly David A. Arledge
Director Principal Financial Officer
March 26, 1999 and Director
March 26, 1999
By: HAROLD BURROW By: DAN A. HOMEC
----------------------------- -----------------------------
Harold Burrow Dan A. Homec
Director Principal Accounting Officer
March 26, 1999 March 26, 1999
By: JON R. WHITNEY By: C. SCOTT HOBBS
----------------------------- -----------------------------
Jon R. Whitney C. Scott Hobbs
Director Director
March 26, 1999 March 26, 1999
11
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
This report, including Management's Discussion and Analysis of Financial
Condition and Results of Operations, includes certain forward-looking
statements. The forward-looking statements reflect the Company's expectations,
objectives and goals with respect to future events and financial performance,
and are based on assumptions and estimates which the Company believes are
reasonable. However, actual results could differ materially from anticipated
results. Important factors which may affect the actual results include, but are
not limited to, commodity prices, political developments, market and economic
conditions, industry competition, the weather, changes in financial markets,
changing legislation and regulations, and the impact of the Year 2000 issue. The
forward-looking statements contained in this Report are intended to qualify for
the safe harbor provisions of Section 21E of the Securities Exchange Act of
1934, as amended.
The Notes to Consolidated Financial Statements contain information that is
pertinent to the following analysis.
Liquidity and Capital Resources
General Discussion
The Company uses the following consolidated ratios to measure liquidity and
ability to meet future funding needs and debt service requirements.
<TABLE>
<CAPTION>
1998 1997 1996
-------- -------- --------
<S> <C> <C> <C>
Cash flow from operating activities to capital expenditures and debt
service requirements................................................... 174.3% 193.2% 133.4%
Total debt to total capitalization..................................... 36.0% 37.8% 35.5%
Times interest earned (before tax and extraordinary item).............. 6.0 6.1 7.5
</TABLE>
The changes in the cash flow from operating activities to capital
expenditures and debt service requirements ratio is due mainly to lower capital
expenditures in 1997 as compared to 1998 and 1996. The decrease in the 1998
total debt to total capitalization ratio when compared to 1997 is due to
increased retained earnings resulting from 1998 earnings. The 1997 increase in
total debt to total capitalization over 1996 is due to the issuance of
additional debt. The decrease in the times interest earned ratio for 1997 can be
attributed to increased interest expense resulting from the additional debt.
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 1996 through 1998 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 $146.4 million in 1998,
$136.5 million in 1997 and $127.6 million in 1996. The increases in 1998 and
1997 from the prior years can be attributed primarily to decreases for working
capital requirements.
The Company has adopted a capital expenditure budget of approximately $87.4
million for 1999, an increase from the capital additions of $84.0 million in
1998. The anticipated increase in 1999 is the result of a $13.3 million increase
for natural gas projects partially offset by a $9.9 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, 1998, the Company and
certain affiliates could incur an aggregate of approximately $3 billion of
additional indebtedness.
F-1
<PAGE>
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, 1998, the Company had advanced
$243 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, pursuing innovative marketing strategies and applying strict
cost-cutting measures.
The FASB has issued FAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities" ("FAS 133"), to be effective for all fiscal quarters of
fiscal years beginning after June 15, 1999. FAS 133 requires that an entity
recognize all derivatives as either assets or liabilities in the statement of
financial position and measure those instruments at fair value. The accounting
for changes in the fair value of a derivative will depend on the intended use of
the derivative and the resulting designation. The Company is currently
evaluating the impact of FAS 133.
The Accounting Standards Executive Committee of the AICPA has issued
Statement of Position 98-5, "Reporting of Costs of Start-Up Activities" ("SOP
98-5"), to be effective for periods beginning after December 15, 1998. SOP 98-5
provides guidance on accounting for costs incurred to open new facilities,
conduct business in new territories or otherwise commence some new operation.
The application of SOP 98-5 is not expected to have a material effect on the
Company's consolidated financial statements.
The FASB Emerging Issues Task Force Issue No. 98-10, "Accounting for
Contracts in Energy Trading and Risk Management Activities," to be effective for
years beginning after December 15, 1998, states that energy trading contracts
(as defined) should be marked to market with the gains and losses included in
earnings and separately disclosed in the financial statements or footnotes
thereto. The Company does not believe the application of Issue No. 98-10 will
have a material effect on its consolidated financial statements.
Market Risk Management
The Company has issued fixed rate debt to partially finance expenditures
and debt retirements. These agreements expose the Company to market risk related
to changes in interest rates.
The following table presents hypothetical changes in fair values in the
Company's debt obligations at December 31, 1998. The modeling technique used
measures the change in fair values arising from selected changes in interest
rates. Market changes reflect immediate hypothetical changes in interest rates
at December 31, 1998. Fair values are calculated as the net present value of the
expected cash flows of the financial instrument (millions of dollars).
<TABLE>
<CAPTION>
No Change 10% Increase 10% Decrease
--------- ------------------------ ---------------------------
Impact of changes in market Fair Fair Increase Fair Increase
rates of interest on: Value Value (Decrease) Value (Decrease)
- -------------------------------------- ----------- ----------- ------------ ----------- -----------
<S> <C> <C> <C> <C> <C>
Long-term debt subject to fixed
interest rates:.................... $ 321.2 $ 312.3 $ (8.9) $ 328.8 $ 7.6
</TABLE>
The Company has notes receivable from related parties with a carrying value
of $243 million and a note payable to a related party with a carrying value of
$2.8 million. These notes earn interest at a variable rate tied to market rates
of interest and therefore, the carrying amount is a reasonable estimate of its
fair value. A 10% change in interest rates from December 31, 1998 levels would
not have a material impact on earnings.
The Company's management of market risks is consistent with the prior year.
Year 2000
The Company, like most other companies, is addressing the Year 2000 issue.
This issue is the result of computer programs written with two digits rather
than four to define the applicable year. Computer programs that have
F-2
<PAGE>
date-sensitive software using two digits to define the applicable year 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 of
operations, including, among other things, a temporary inability to process
transactions, send invoices, or engage in similar normal business activities.
The Company's Year 2000 compliance project relates to both information
technology and embedded systems throughout the Company and focuses on all
technology hardware and software, external interfaces with customers and
suppliers, operations process control, automation and instrumentation systems.
Systems are being reviewed in an order of priority that includes an assessment
of the potential adverse effects of noncompliance as well as an assessment of
the complexity of the system. Assessment has been substantially completed for
all systems. It will be necessary to modify or replace certain noncompliant
software and hardware so that they will properly utilize dates beyond December
31, 1999. The Company believes that with such remediation, the Year 2000 issue
can be mitigated. Necessary remediation and testing activities have begun and
are planned to be completed for all material systems by mid 1999. Remaining
systems modifications, replacement and testing are planned to be completed
before the end of 1999.
The Company is continuing with a formal communications process with outside
entities with which the Company conducts business to determine the extent to
which those companies are addressing their Year 2000 compliance. In connection
with this process, the Company has been sending letters and questionnaires to
these parties and is evaluating the responses as received and is following up
with those parties that have not responded. The Company does not expect any
single noncompliant third party to have a material effect on the Company as it
does not rely to a material extent on any single customer or supplier, including
telecommunications providers, utilities and banks. However, the Company does not
control these parties and there can be no assurance that third-party systems
will be timely converted, or that any failure to convert would not have an
adverse effect on the Company's systems. The Company will continue to cooperate
and communicate with these parties to mitigate potential adverse effects.
The Company is currently preparing and will periodically update a Year 2000
contingency plan. The primary goals of the plan are to maintain continuity of
operations, timely resume any operations that have been interrupted, preserve
Company assets and protect the environment. The Company's geographical
distribution and customer base diversity are expected to naturally reduce the
risk of major disruptions to operations due to any Year 2000-related occurrence.
Similarly, the Company's distributed information systems and wide scope of
relationships with financial institutions, suppliers and vendors will most
likely aid in limiting and localizing any individual Year 2000 failure to
specific operations or facilities. Also, in recent years, the Company has
replaced or updated a significant portion of its computer hardware and software.
The plan will include possible manual intervention to operate noncompliant
facilities or systems until they can be modified or replaced. Notwithstanding
the foregoing, due to the nature of contingency planning, there can be no
assurance that such plans will acceptably mitigate the risk of material impact
to the Company's operations due to any Year 2000-related incident.
The Company has been using both external and internal resources to
reprogram or replace its software and embedded systems for the Year 2000 issue.
While the Company has included the Year 2000 project in its overall information
systems planning process since 1996, certain systems were identified for
replacement prior to the organization of the Year 2000 project. These amounts
are not included in the Year 2000 project cost estimates, except where the
replacement date has been accelerated in order to address Year 2000 issues. To
date, the amounts incurred and expensed for developing and carrying out the plan
total approximately $2 million. The total remaining cost for addressing the Year
2000 issue, which will be funded through operating cash flows, is currently
estimated by management to be approximately $1 million.
It should be noted that the ultimate amount of Year 2000 costs is difficult
to estimate due to possible disruptions in business arising from Year 2000
noncompliance of vendors, suppliers, customers and other third parties over whom
the Company has no control. Notwithstanding the Company's efforts, disruptions
could occur in its business due to Year 2000 problems and such disruptions could
have an adverse effect.
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
F-3
<PAGE>
maintenance of its pipeline and production facilities. Compliance with such laws
and regulations can be costly. Additionally, governmental authorities may
enforce the laws and regulations with a variety of civil and criminal
enforcement measures, including monetary penalties and remediation requirements.
The Company spent approximately $1 million in 1998 on environmental capital
projects and anticipates capital expenditures of $1 to $2 million in 1999 in
order to comply with such laws and regulations.
Future information and developments, including legislative and enforcement
developments, will require the Company to continually reassess the expected
impact of these environmental matters. However, the Company has evaluated its
total environmental exposure based on currently available data, including its
potential joint and several liability, and believes that compliance with all
applicable laws and regulations will not have a material adverse impact on the
Company's consolidated financial position or results of operations.
Results of Operations
Operating Revenues. The operating revenues by segment were as follows
(thousands of dollars):
<TABLE>
<CAPTION>
Twelve Months Ended December 31,
-----------------------------------------
1998 1997 1996
----------- ----------- -----------
<S> <C> <C> <C>
Natural gas................................................. $ 368,056 $ 437,445 $ 400,423
Exploration and production.................................. 19,325 26,280 20,273
Eliminations................................................ (7,016) (14,649) (8,219)
----------- ----------- -----------
$ 380,365 $ 449,076 $ 412,477
=========== =========== ===========
</TABLE>
Earnings Before Interest, Income Taxes and Extraordinary Item. The earnings
before interest, income taxes and extraordinary item by segment were as follows
(thousands of dollars):
<TABLE>
<CAPTION>
Twelve Months Ended December 31,
-----------------------------------------
1998 1997 1996
----------- ----------- -----------
<S> <C> <C> <C>
Natural gas................................................. $ 140,482 $ 138,576 $ 138,840
Exploration and production.................................. 1,976 7,479 3,384
----------- ----------- -----------
$ 142,458 $ 146,055 $ 142,224
=========== =========== ===========
</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 discontinued 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 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.
F-4
<PAGE>
Operating Revenues
1998 Versus 1997. Revenues from natural gas operations decreased in 1998
due to a $41 million decrease related to gas sales volumes caused primarily by
the assignment of the Company's Merchant Division activity to an affiliate as
discussed in Note 11 of the Notes to Consolidated Financial Statements, a $22
million decrease in average gas sales prices, a decrease of $8 million in
non-recurring miscellaneous income, a $12 million decrease in extracted products
revenue, and other net decreases of $2 million partially offset by a $16 million
decrease in reservations.
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 rates, a $16 million
increase resulting from increased gas transportation volumes and a $11 million
increase related to average gas sales prices partially offset by a $30 million
change in reservations and other net decreases of $7 million.
Other Income-Net
1998 Versus 1997. The increase of $3 million in 1998 primarily reflects
changes in interest income resulting from loans to affiliated companies.
1997 Versus 1996. The decrease of $1 million in 1997 primarily reflects
changes in interest income resulting from loans to affiliated companies.
Cost of Gas Sold
1998 Versus 1997. The decrease is due primarily to a $59 million reduction
related to gas purchase volumes caused primarily by the assignment of the
Company's Merchant Division activity to an affiliate, a decrease of $9 million
related to lower average gas purchase rates and other net decreases of $3
million partially offset by a $22 million reduction in net system balancing
requirements.
1997 Versus 1996. The increase is due primarily to higher average gas
purchase rates of $32 million and increased purchase volumes of $17 million
partially offset by $19 million in net system balancing requirements.
Operation and Maintenance
1998 Versus 1997. Operation and maintenance expense decreased in 1998 due
primarily to a $8 million decrease in gas used in operations, a $3 million
decrease in materials and supplies expenses, a $3 million decrease in salaries
and benefits and other net decreases of $1 million.
1997 Versus 1996. Operation and maintenance expense increased in 1997 due
primarily to a $10 million increase in gas used in operations offset by net
decreases of $1 million.
Depreciation, Depletion and Amortization
1998 Versus 1997. The 1998 decrease of $4 million is primarily due to
decreased depreciation rates on certain regulated assets.
1997 Versus 1996. The $3 million decrease in 1997 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.
Exploration and Production
Operating Revenues
1998 Versus 1997. Revenues from exploration and production decreased in
1998 as a result of a $4 million decrease related to sales volumes and a $3
million decrease related to average sales prices.
F-5
<PAGE>
1997 Versus 1996. Revenues from exploration and production increased in
1997 as a result of higher natural gas prices.
Operation and Maintenance
1998 Versus 1997. Operation and maintenance expenses increased by $1
million as a result of increased well count and the installation of additional
compression facilities.
1997 Versus 1996. Operation and maintenance expenses increased by $2
million as a result of increased well count and the installation of additional
compression facilities.
Depreciation, Depletion and Amortization
1998 Versus 1997. Depreciation, depletion and amortization decreased by $2
million due to lower production volumes and a lower depreciation rate.
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, 6.85% senior debentures in June 1997.
Taxes on Income
Income taxes fluctuated primarily as a result of changing levels of income
before taxes and changes in effective income tax rates. The effective federal
income tax rate for the Company was 31% in 1998, 33% in 1997 and 32% in 1996.
F-6
<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, 1998 and 1997, 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, 1998. 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, 1998 and 1997, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1998 in conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Denver, Colorado
February 4, 1999
F-7
<PAGE>
COLORADO INTERSTATE GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
<TABLE>
<CAPTION>
December 31,
---------------------------
ASSETS 1998 1997
------------ ------------
<S> <C> <C>
Current Assets:
Cash........................................................................... $ 109 $ 3,508
Notes receivable from affiliates............................................... 243,049 219,655
Accounts receivable............................................................ 41,309 63,319
Accounts receivable from affiliates............................................ 43,057 39,057
Materials and supplies......................................................... 8,666 8,841
Prepaid expenses............................................................... 820 93
Current portion of deferred income taxes....................................... 34,653 38,626
------------ ------------
371,663 373,099
------------ ------------
Plant, Property and Equipment, at cost:
Gas pipeline................................................................... 1,227,928 1,162,907
Gas and oil properties, at full-cost........................................... 136,334 130,500
------------ ------------
1,364,262 1,293,407
Accumulated depreciation, depletion and amortization........................... 711,957 689,690
------------ ------------
652,305 603,717
------------ ------------
Other Assets:
Investments in related parties................................................. 48,742 44,217
Other deferred charges......................................................... 43,557 42,397
------------ ------------
92,299 86,614
------------ ------------
$ 1,116,267 $ 1,063,430
============ ============
</TABLE>
See Notes to Consolidated Financial Statements.
F-8
<PAGE>
COLORADO INTERSTATE GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
<TABLE>
<CAPTION>
December 31,
---------------------------
LIABILITIES AND STOCKHOLDER'S EQUITY 1998 1997
------------ ------------
<S> <C> <C>
Current Liabilities:
Note payable to affiliate...................................................... $ 2,784 $ -
Accounts payable and accrued expenses.......................................... 123,070 138,708
Accounts payable to affiliates................................................. 41,147 26,460
Taxes on income................................................................ 21,565 5,429
------------ ------------
188,566 170,597
------------ ------------
Debt:
Long-term debt................................................................. 279,520 279,447
------------ ------------
Deferred Credits:
Deferred income taxes.......................................................... 111,679 112,063
Other.......................................................................... 40,031 41,947
------------ ------------
151,710 154,010
------------ ------------
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.............................................................. 449,873 412,778
------------ ------------
496,471 459,376
------------ ------------
$ 1,116,267 $ 1,063,430
============ ============
</TABLE>
See Notes to Consolidated Financial Statements.
F-9
<PAGE>
COLORADO INTERSTATE GAS COMPANY AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED EARNINGS
(Thousands of Dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------------
1998 1997 1996
---------- ---------- ---------
<S> <C> <C> <C>
Revenues:
Operating revenues:
Nonaffiliates....................................................... $ 293,653 $ 326,694 $ 338,824
Affiliates.......................................................... 86,712 122,382 73,653
---------- ---------- ---------
380,365 449,076 412,477
Other income-net....................................................... 15,641 12,547 12,987
---------- ---------- ---------
396,006 461,623 425,464
---------- ---------- ---------
Costs and Expenses:
Cost of gas sold:
Nonaffiliates....................................................... 55,303 91,657 75,129
Affiliates.......................................................... 7,346 12,623 5,102
---------- ---------- ---------
62,649 104,280 80,231
Operation and maintenance.............................................. 157,486 171,961 160,708
Depreciation, depletion and amortization............................... 33,413 39,327 42,301
Interest expense....................................................... 23,880 23,816 18,861
Taxes on income........................................................ 40,783 42,015 41,305
---------- ---------- ---------
318,211 381,399 343,406
---------- ---------- ---------
Earnings before Extraordinary Item........................................ 77,795 80,224 82,058
Extraordinary Item - Loss from Discontinuance of FAS 71,
Net of Income Taxes.................................................... - - (6,301)
---------- ---------- ---------
Net Earnings.............................................................. $ 77,795 $ 80,224 $ 75,757
========== ========== =========
</TABLE>
STATEMENT OF CONSOLIDATED RETAINED EARNINGS AND
ADDITIONAL PAID-IN CAPITAL
(Thousands of Dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------------
1998 1997 1996
---------- ---------- ---------
<S> <C> <C> <C>
Retained Earnings:
Beginning balance......................................................... $ 412,778 $ 370,054 $ 413,212
Net earnings........................................................... 77,795 80,224 75,757
Less dividends:
Preferred stock:
5.50% Series..................................................... - - 15
Common stock........................................................ 40,700 37,500 118,900
---------- ---------- ---------
40,700 37,500 118,915
---------- ---------- ---------
Ending balance............................................................ $ 449,873 $ 412,778 $ 370,054
========== ========== =========
Additional Paid-In Capital:
Beginning balance......................................................... $ 19,037 $ 19,037 $ 19,035
Gain on redemption of preferred stock.................................. - - 2
---------- ---------- ---------
Ending balance............................................................ $ 19,037 $ 19,037 $ 19,037
========== ========== =========
</TABLE>
See Notes to Consolidated Financial Statements.
F-10
<PAGE>
COLORADO INTERSTATE GAS COMPANY AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CASH FLOWS
(Thousands of Dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------------
1998 1997 1996
---------- ---------- ---------
<S> <C> <C> <C>
Net Cash Flow From Operating Activities:
Earnings before extraordinary item..................................... $ 77,795 $ 80,224 $ 82,058
Add items not requiring cash:
Depreciation, depletion and amortization............................ 33,413 39,327 42,301
Deferred income taxes............................................... 3,396 13,177 216
Producer contract reformation cost recoveries....................... - 14 135
Other............................................................... (813) 2,524 6,716
Working capital and other changes, excluding changes relating to cash and
non-operating activities:
Receivables......................................................... 22,010 (11,358) (7,443)
Receivables from affiliates......................................... (4,000) 11,999 (38,721)
Materials and supplies.............................................. 175 830 (177)
Prepaid expenses.................................................... (727) 324 (137)
Accounts payable and accrued expenses............................... (15,638) 6,067 17,042
Accounts payable to affiliates...................................... 14,687 1,104 14,004
Taxes on income..................................................... 16,136 (7,733) 11,568
---------- ---------- ---------
146,434 136,499 127,562
---------- ---------- ---------
Cash Flow from Investing Activities:
Purchases of plant, property and equipment............................. (84,022) (70,661) (95,597)
Proceeds from sale of plant, property and equipment.................... 24 8,374 7,934
Investments in related parties......................................... (4,525) (3,161) (40,942)
Net (increase) decrease in notes receivable from affiliates............ (23,394) (80,265) 70,059
Recovery of gas supply prepayments..................................... - 79 109
---------- ---------- ---------
(111,917) (145,634) (58,437)
---------- ---------- ---------
Cash Flow from Financing Activities:
Net increase in note payable to affiliate.............................. 2,784 - -
Redemption of preferred stock.......................................... - - (556)
Gain on redemption of preferred stock.................................. - - 2
Issuance of senior debentures.......................................... - 99,604 -
Preferred dividends paid............................................... - - (15)
Common dividends paid.................................................. (40,700) (37,500) (118,900)
Term loan.............................................................. - (50,000) 50,000
---------- ---------- ---------
(37,916) 12,104 (69,469)
---------- ---------- ---------
Net Increase (Decrease) in Cash........................................... (3,399) 2,969 (344)
Cash at Beginning of Year................................................. 3,508 539 883
---------- ---------- ---------
Cash at End of Year....................................................... $ 109 $ 3,508 $ 539
========== ========== =========
</TABLE>
See Notes to Consolidated Financial Statements.
F-11
<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
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, which had the effect of increasing net earnings by approximately $3.6
million in 1998 and $1 million in 1997.
- - Principles of Consolidation
The Consolidated Financial Statements include the accounts of the Company
and its subsidiaries after eliminating all significant intercompany
transactions. The equity method of accounting is used for an investment in which
the Company has a 50% voting interest and exercises significant influence.
- - 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 $24.6 million, $24.9 million and $18.6 million in
1998, 1997 and 1996, respectively. Cash payments for income taxes amounted to
$21.3 million, $32.9 million and $29.1 million in 1998, 1997 and 1996,
respectively.
- - Nature of Operations and Concentrations of Credit Risk
The Company is involved in the production, purchase, gathering, processing,
transportation, storage and sale of natural gas primarily in the Texas Panhandle
and Rocky Mountain regions of the United States. The Company operates under
arrangements with other companies including distributors, intrastate and
interstate pipelines, producers, brokers, marketers and end-users. As a result,
the Company has a concentration of receivables due from these customers. This
may affect the Company's overall credit risk in that the customers may be
similarly affected by changes in economic, regulatory and other factors. Trade
receivables are generally not collateralized; however, the Company analyzes
customers' credit positions prior to extending credit.
- - Materials and Supplies
Materials and supplies are carried principally at average cost.
F-12
<PAGE>
- - 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 $.5 million, $.2 million and $1.2 million in 1998, 1997 and
1996, 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.
The Company provides for depreciation of gas system facilities on a
straight-line basis with rates that vary by type of property (2% to 27% during
1998). 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. Estimated proved reserves for 1998 were prepared by
Huddleston for the Natural Gas System while the Exploration and Production
portions were prepared by Coastal's engineers and reviewed by Huddleston.
Estimated proved reserves for 1997 were prepared by Huddleston. The average
amortization rate per equivalent unit of a thousand cubic feet of gas production
for oil and gas operations was $.89 for the year 1998, $.91 for the year 1997
and $.88 for the year 1996. 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. 130,
"Reporting Comprehensive Income" in 1998. The application of the new standard
did not have a material effect on the Company's consolidated financial
statements as the Company currently does not have any material items of other
comprehensive income.
The Company adopted Statement of Financial Accounting Standards No. 131,
"Disclosures about Segments of an Enterprise and Related Information " ("FAS
131"), in 1998 and the disclosures for prior years have been revised in
accordance with this statement. See Note 11 for additional information on FAS
131.
The Company adopted Statement of Financial Accounting Standards No. 132,
"Employers' Disclosures about Pensions and Other Postretirement Benefits" ("FAS
132"), in 1998 and the disclosures for prior years have been revised in
accordance with this statement. See Note 7 for additional information on FAS
132.
The FASB has issued Statement of Financial Accounting Standards No. 133,
"Accounting for Derivative Instruments and Hedging Activities" ("FAS 133"), to
be effective for all fiscal quarters of fiscal years beginning after June 15,
1999. FAS 133 requires that an entity recognize all derivatives as either assets
or liabilities in the statement of financial position and measure those
instruments at fair value. The accounting for changes in the fair value of a
derivative will depend on the intended use of the derivative and the resulting
designation. The Company is currently evaluating the impact of FAS 133.
F-13
<PAGE>
The Accounting Standards Executive Committee of the AICPA issued Statement
of Position 98-1, "Accounting for the Costs of Computer Software Developed or
Obtained for Internal Use" ("SOP 98-1") which was adopted by the Company in
1998. The application of the new statement did not have a material effect on the
Company's consolidated results of operations, financial position or cash flows.
The Accounting Standards Executive Committee of the AICPA has issued
Statement of Position 98-5, "Reporting on the Costs of Start-Up Activities"
("SOP 98-5"), to be effective for periods beginning after December 15, 1998. SOP
98-5 provides guidance on accounting for costs incurred to open new facilities,
conduct business in new territories or otherwise commence some new operation.
The application of SOP 98-5 is not expected to have a material effect on the
Company's consolidated financial statements.
The FASB Emerging Issues Task Force Issue No. 98-10, "Accounting for
Contracts in Energy Trading and Risk Management Activities," to be effective for
years beginning after December 15, 1998, states that energy trading contracts
(as defined) should be marked to market with the gains and losses included in
earnings and separately disclosed in the financial statements or footnotes
thereto. The Company does not believe the application of Issue No. 98-10 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.
2. Long-Term Debt
Balances at December 31 were as follows (thousands of dollars):
<TABLE>
<CAPTION>
1998 1997
--------- ---------
<S> <C> <C>
6.85% Senior Debentures, due 2037................................................. $ 100,000 $ 100,000
10% Senior Debentures, due 2005................................................... 179,520 179,447
--------- ---------
$ 279,520 $ 279,447
========= =========
</TABLE>
The 10% Senior Debentures, due 2005, are not redeemable prior to maturity
and have no sinking fund provisions.
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.
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, 1998, the Company and certain affiliates could incur an aggregate
of approximately $3 billion of additional indebtedness.
F-14
<PAGE>
3. Common Stock and Other Stockholders' Equity
All of the Company's common stock is owned by Coastal Natural Gas.
At December 31, 1998, 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, 1998 December 31, 1997
--------------------------- ---------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
---------- ----------- ----------- ----------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Financial assets:
Cash....................................... $ 109 $ 109 $ 3,508 $ 3,508
Notes receivable from affiliates........... 243,049 243,049 219,655 219,655
Financial liabilities:
Long-term debt............................. 279,520 321,186 279,447 321,866
Note payable to affiliate.................. 2,784 2,784 - -
</TABLE>
The carrying values of cash, notes receivable from affiliates and note
payable to affiliate 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, 1998 and 1997, respectively, for new issues with similar remaining
maturities.
6. Taxes On Income
Provisions for income taxes before extraordinary item are composed of the
following (thousands of dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------
1998 1997 1996
-------- -------- --------
<S> <C> <C> <C>
Current Income Taxes:
Federal............................................................. $ 34,721 $ 25,697 $ 39,127
State............................................................... 2,666 3,141 1,962
-------- -------- --------
37,387 28,838 41,089
-------- -------- --------
Deferred Income Taxes:
Federal............................................................. 2,124 13,059 87
State............................................................... 1,272 118 129
-------- -------- --------
3,396 13,177 216
-------- -------- --------
Taxes on Income........................................................ $ 40,783 $ 42,015 $ 41,305
======== ======== ========
</TABLE>
F-15
<PAGE>
Coastal and the Internal Revenue Service ("IRS") Appeals Office have
concluded a final settlement of certain adjustments originally proposed to
federal income tax returns filed for the years 1985 through 1987. The IRS has
proposed additional adjustments to those returns, and Coastal is contesting
certain of 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,
--------------------------------
1998 1997 1996
-------- -------- --------
<S> <C> <C> <C>
Tax expense computed by applying the U.S. federal income
tax rate of 35%..................................................... $ 41,502 $ 42,784 $ 43,177
Increases (reductions) in taxes resulting from:
State income tax cost............................................... 2,560 2,118 1,359
Tight sands gas credit.............................................. (2,756) (2,309) (2,586)
Other............................................................... (523) (578) (645)
-------- -------- --------
Taxes on Income........................................................ $ 40,783 $ 42,015 $ 41,305
======== ======== ========
</TABLE>
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,
---------------------
1998 1997
--------- ---------
<S> <C> <C>
Excess of book basis over tax basis of plant, property and equipment.............. $ 110,459 $ 111,387
Other............................................................................. 1,220 676
--------- ---------
Deferred tax liabilities....................................................... 111,679 112,063
--------- ---------
Provisions for rate refunds and contested claims.................................. (26,219) (30,000)
Accrued expenses.................................................................. (7,852) (5,999)
Other............................................................................. (582) (2,627)
--------- ---------
Deferred tax assets............................................................ (34,653) (38,626)
--------- ---------
Deferred income taxes.......................................................... $ 77,026 $ 73,437
========= =========
</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, 1998, 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 1998, 1997 or 1996. 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 1998 and 1997, respectively and $2.5
million for 1996.
F-16
<PAGE>
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 through October 31, 1996. Effective November
1, 1996, such costs are no longer being deferred as a result of the Company's
discontinued application of FAS 71.
The following tables provide a reconciliation of the changes in the
postretirement benefit obligation, the fair value of plan assets over each of
the years ended December 31, 1998 and 1997, and a statement of the funded status
as of December 31, 1998 and 1997 (millions of dollars):
<TABLE>
<CAPTION>
Year Ended
December 31,
--------------------
1998 1997
-------- --------
<S> <C> <C>
Change in Postretirement Benefit Obligation
Accumulated postretirement benefit obligation at beginning of year................. $ 14.3 $ 15.1
Service cost....................................................................... .3 .2
Interest cost...................................................................... .9 .9
Participant contributions.......................................................... .5 .6
Plan amendments.................................................................... - (.7)
Benefit payments................................................................... (1.7) (1.7)
Actuarial gain..................................................................... - (.1)
-------- --------
Accumulated postretirement benefit obligation at end of year....................... $ 14.3 $ 14.3
======== ========
Change in Plan Assets
Fair value of plan assets at beginning of year..................................... $ 9.0 $ 7.9
Actual return on plan assets....................................................... (.2) .5
Employer contributions............................................................. 1.4 1.3
Benefit payments................................................................... (1.1) (.7)
-------- --------
Fair value of plan assets at end of year........................................... $ 9.1 $ 9.0
======== ========
</TABLE>
<TABLE>
<CAPTION>
December 31,
--------------------
1998 1997
-------- --------
<S> <C> <C>
Funded Status
Funded status at year end.......................................................... $ (5.2) $ (5.3)
Unrecognized gain.................................................................. (5.4) (6.2)
Unrecognized transition obligation................................................. 11.6 12.4
-------- --------
Prepaid postretirement benefit asset............................................... $ 1.0 $ .9
======== ========
</TABLE>
The following table provides the components of net periodic postretirement
benefit cost for 1998, 1997 and 1996 (millions of dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------
1998 1997 1996
-------- -------- --------
<S> <C> <C> <C>
Service cost........................................................... $ .3 $ .2 $ .2
Interest cost.......................................................... .9 .9 1.0
Amortization of transition obligation.................................. .8 .8 .9
Expected return on assets.............................................. (.2) (.2) (.2)
Amortization of net gain............................................... (.4) (.3) (.2)
Deferred regulatory amount............................................. - - .6
-------- -------- --------
Net periodic postretirement benefit cost............................... $ 1.4 $ 1.4 $ 2.3
======== ======== ========
</TABLE>
F-17
<PAGE>
The assumed health care cost trend rate used in measuring the accumulated
postretirement benefit obligation was 9.0% in 1998, 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 9.7% in 1997 and 10.4% in
1996. 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, 1998 by approximately 3.67% and the net postretirement health
care cost by approximately 3.61%. A one percentage point decrease in the assumed
health care cost trend rate for each year would decrease the accumulated
postretirement benefit obligation as of December 31, 1998 by approximately 4.02%
and the net postretirement health care cost by approximately 4.13%. The assumed
discount rate used in determining the accumulated postretirement benefit
obligation was 7.0% in 1998, 7.25% in 1997 and 7.5% in 1996 and the expected
long-term rate of return on assets was 4.3% in 1998, 1997 and 1996.
8. Lease Commitments
The Company had rental expense of approximately $5.1 million, $5.2 million
and $4.7 million in 1998, 1997 and 1996, respectively (excluding leases covering
natural resources). The aggregate minimum lease payments under existing
noncapitalized long-term leases are estimated to be $4.1 million, $3.8 million,
$3.7 million, $2.4 million and $2.3 million for the years 1999-2003,
respectively, and $3.0 million thereafter.
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 of royalties, breach of fiduciary duty,
fraud and negligent misrepresentation. Management believes that Colorado has
numerous defenses to the lessors' claims, including (i) that the royalties were
properly paid, (ii) that the majority of the claims were released by written
agreement and (iii) that the majority of the claims are barred by the statute of
limitations. In March of 1995, the trial court granted a partial summary
judgment in favor of Colorado, holding that the four-year statute of limitations
had not been tolled, that the releases are valid, and dismissing all tort claims
and claims for breach of any duty of disclosure. The remaining claim for
underpayment of royalties was tried to a jury which, in May 1995, made findings
favorable to Colorado. On June 7, 1995, the trial court entered a judgment that
the lessors recover no monetary damages from Colorado and permanently estopping
the lessors from asserting any claim based on an interpretation of the contract
different than that asserted by Colorado in the litigation. The lessors' motion
for a new trial was denied on July 18, 1997, and both parties 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 suit pending the outcome of the
first lawsuit. Oral arguments were heard before the Fifth Circuit Court of
Appeals on December 4, 1998 and the parties are awaiting the Court's decision.
In 1996, Jack Grynberg filed a claim under the False Claims Act on behalf
of the U.S. government in the U.S. District Court, District of Columbia, against
70 defendants, including Colorado and another subsidiary of Coastal. The suit
sought damages for the alleged underpayment of royalties due to the purported
improper measurement of gas. The 1996 suit was dismissed without prejudice in
March 1997 and the dismissal was affirmed by the D.C. Court of Appeals in
October 1998. In September 1997, Mr. Grynberg filed 77 separate, similar False
Claims Act suits against natural gas transmission companies and producers,
gatherers, and processors of natural gas, seeking unspecified damages. Colorado,
Coastal and several other Coastal subsidiaries have been included in two of the
September 1997 suits. The suits were filed in both the U.S. District Court,
District of Colorado and the U.S. District Court, Eastern District of Michigan.
The United States Department of Justice has notified the Company that it is
reviewing these lawsuits to determine whether or not the United States will
intervene.
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
F-18
<PAGE>
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 and production facilities. Compliance with such
laws and regulations can be costly. Additionally, governmental authorities may
enforce the laws and regulations with a variety of civil and criminal
enforcement measures, including monetary penalties and remediation requirements.
The Company spent approximately $1 million in 1998 on environmental capital
projects and anticipates capital expenditures of $1 to $2 million in 1999 in
order to comply with such laws and regulations.
Future information and developments, including legislative and enforcement
developments, will require the Company to continually reassess the expected
impact of these environmental matters. However, the Company has evaluated its
total environmental exposure based on currently available data, including its
potential joint and several liability, and believes that compliance with all
applicable laws and regulations will not 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"). Under this Policy, (i) a pipeline and a customer are
allowed to negotiate a contract which provides for rates and charges that exceed
the pipeline's posted maximum tariff rates, provided that the customer 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"), and (ii) 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. To implement this Policy, a pipeline must
make an initial tariff filing with the FERC to indicate that it intends to
contract for services under this Policy. Colorado has received FERC authority to
enter into negotiated rate transactions. Separately, the FERC has determined
that pipelines who seek to include negotiated rate transactions in the discount
adjustment used to calculate their rates must file tariff sheets demonstrating
that existing customers who purchase service under the pipeline's
cost-of-service rates will not be harmed by negotiated rate discounts.
On July 29, 1998, the FERC issued a "Notice of Proposed Rulemaking," in
which the FERC has proposed a number of further significant changes to the
industry, including, among other things, removal of price caps in the short-term
market (less than one year), capacity auctions, changed reporting obligations,
the ability to negotiate terms and conditions of all services, elimination of
the requirement of a matching term cap on the renewal of existing contracts, and
a review of its policies for approving capacity construction. On the same day,
the FERC also issued a "Notice of Inquiry" soliciting industry input on various
matters affecting the pricing of long-term service and certificate pricing in
light of changing market conditions. The due date for comments on both of these
matters has been rescheduled twice and is currently scheduled for April 22,
1999. The FERC has indicated that it may consider both proposals together
inasmuch as they raise several common issues.
Certain regulatory issues remain unresolved among the Company, its
customers, its suppliers and the FERC. The Company has made provisions which
represent management's assessment of the ultimate resolution of these issues. 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 discontinued application of FAS 71.
The Company believes this accounting change results in financial reporting which
better reflects the results
F-19
<PAGE>
of operations in the economic environment in which the Company now operates. The
impact of this change 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. Segment Information
Natural gas system operations and gas and oil exploration and production
are the two segments of the Company's operations. Separate management of each
segment is required because each line is subject to different production,
marketing and technology strategies.
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.
The Company's operating revenues from external customers and intersegment
revenues; earnings before interest, income taxes and extraordinary item;
depreciation, depletion and amortization; equity income (loss) from investments;
and capital expenditures for the years ended December 31, 1998, 1997 and 1996
are shown as follows (thousands of dollars):
<TABLE>
<CAPTION>
1998 1997 1996
---------- --------- ---------
<S> <C> <C> <C>
Operating Revenues
Natural gas......................................................... $ 368,056 $ 437,445 $ 400,423
Exploration and production.......................................... 19,325 26,280 20,273
Exploration and production intersegment revenue eliminations........ (7,016) (14,649) (8,219)
---------- --------- ---------
Consolidated Totals............................................... $ 380,365 $ 449,076 $ 412,477
========== ========= =========
Earnings Before Interest, Income Taxes and Extraordinary Item
Natural gas......................................................... $ 140,482 $ 138,576 $ 138,840
Exploration and production.......................................... 1,976 7,479 3,384
---------- --------- ---------
Consolidated Totals............................................... $ 142,458 $ 146,055 $ 142,224
========== ========= =========
Depreciation, Depletion and Amortization
Natural gas......................................................... $ 23,305 $ 27,419 $ 30,851
Exploration and production.......................................... 10,108 11,908 11,450
---------- --------- ---------
Consolidated Totals............................................... $ 33,413 $ 39,327 $ 42,301
========== ========= =========
Equity Income (Loss) From Investments
Natural gas......................................................... $ 6,765 $ 5,211 $ (72)
Exploration and production.......................................... - - -
---------- --------- ---------
Consolidated Totals............................................... $ 6,765 $ 5,211 $ (72)
========== ========= =========
Capital Expenditures
Natural gas......................................................... $ 69,364 $ 52,090 $ 90,392
Exploration and production.......................................... 14,658 18,571 5,205
---------- --------- ---------
Consolidated Totals............................................... $ 84,022 $ 70,661 $ 95,597
========== ========= =========
</TABLE>
Effective July 1, 1998, those gas purchases and sales formerly conducted by
the Company's unincorporated Merchant Division were assigned to an affiliate.
Therefore, revenues and cost of gas sold associated with such activities
subsequent to June 30, 1998 are not included in the Company's consolidated
financial statements.
F-20
<PAGE>
Intersegment revenues are accounted for on the basis of contract, current
market or internally established transfer prices. The equity income (loss) from
investments is included in Operating revenues.
The Company's assets and amount of investment in equity method investees by
segment as of December 31, 1998, 1997 and 1996 are as follows (thousands of
dollars):
<TABLE>
<CAPTION>
1998 1997 1996
----------- ----------- -----------
<S> <C> <C> <C>
Assets
Natural gas................................................... $ 1,085,483 $ 1,036,629 $ 880,807
Exploration and production.................................... 30,784 26,801 28,115
----------- ----------- -----------
Consolidated Totals....................................... $ 1,116,267 $ 1,063,430 $ 908,922
=========== =========== ===========
Equity Method Investments (included in Investments
in related parties)
Natural gas................................................... $ 12,034 $ 5,268 $ 42
Exploration and production.................................... - - -
----------- ----------- -----------
Consolidated Totals....................................... $ 12,034 $ 5,268 $ 42
=========== =========== ===========
</TABLE>
Revenues from sales, storage and transportation of natural gas to
individual customers amounting to 10% or more of the Company's consolidated
revenues were as indicated below (thousands of dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------------
1998 1997 1996
---------- --------- ---------
<S> <C> <C> <C>
PSCo
Amount.............................................................. $ 112,468 $ 165,793 $ 167,222
========== ========= =========
Percent............................................................. 28% 36% 39%
========== ========= =========
Pioneer
Amount.............................................................. $ 39,805 * *
========== ========= =========
Percent............................................................. 10% * *
========== ========= =========
<FN>
*Less than 10% of consolidated revenues.
</FN>
</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, 1998, 1997
and 1996. The Company does not have any foreign operations.
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. As noted above, prior to
July 1, 1998, gas sales were made primarily to public utilities and natural gas
marketers which resold the gas to residential, commercial and industrial
customers and to end-users in Colorado and southeastern Wyoming. The Company
extends credit for sales, storage and transportation services provided to
certain qualifying companies.
F-21
<PAGE>
12. Transactions with Related Parties
The Statement of Consolidated Earnings includes the following major
transactions with related parties (thousands of dollars):
<TABLE>
<CAPTION>
1998 1997 1996
------------------ ------------------ -----------------
Percent Percent Percent
Amount of Total Amount of Total Amount of Total
------ -------- ------ -------- ------ --------
<S> <C> <C> <C> <C> <C> <C>
Revenues
Gathering and Transportation -
Engage Energy US, L.P.<F1>................. $ 12,268 6.1% $ * * $ * *
CIG Merchant Company....................... 13,760 6.8 * * - -
Gas Sales -
CIG Resources Company...................... $ 6,319 5.0% $ 35,981 18.9% $ 9,429 5.9%
CIG Merchant Company....................... 25,751 20.4 32,481 17.1 - -
Extracted Products and Gas Processing -
Coastal Refining & Marketing, Inc.......... $ * * % $ 6,415 27.6% $ 24,791 92.5%
Coastal Field Services Company............. 11,535 81.9 11,295 48.6 1,461 5.4
Incidental Gasoline, Oil and Condensate
Sales -
Coastal Refining & Marketing, Inc.......... $ 1,156 31.6% $ 2,403 37.0% $ 1,473 29.1%
Coastal States Trading, Inc................ 973 26.6 1,560 24.0 1,294 25.5
Natural Gas Production -
Engage Energy US, L.P.<F1>................. $ - -% $ 3,161 13.3% $ 6,878 33.9%
CIG Merchant Company....................... 5,855 47.4 - - - -
Miscellaneous -
Coastal Refining & Marketing, Inc.......... $ * * $ * * $ 210 10.6%
Costs and Expenses
Gas Purchases -
Coastal Oil & Gas Corporation.............. $ 7,234 10.0% $ 11,482 12.2% $ 6,077 5.8%
Gathering, Transportation and Compression -
WIC........................................ $ 8,500 92.0% $ 5,969 72.5% $ 4,778 67.3%
ANR Pipeline............................... - - - - 766 10.8
* Less than 5% of total
<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>
Services provided by the Company at cost for affiliated companies were $7.7
million for 1998, $6.3 million for 1997 and $7.0 million for 1996. Services
provided by affiliated companies for the Company at cost were $7.7 million for
1998, $7.5 million for 1997 and $8.2 million for 1996. 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.
F-22
<PAGE>
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 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, 1998, the Company had advanced
$243 million to associated companies at a market rate of interest. Such amount
is repayable on demand.
At December 31, 1998, the Company's investment in an affiliate, Coastal
Medical Services, Inc., was $36.7 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.
13. Quarterly Results of Operations (Unaudited)
The results of operations by quarter for the years ended December 31, 1998
and 1997 were (thousands of dollars):
<TABLE>
<CAPTION>
1998 Quarter Ended
----------------------------------------------
March 31, June 30, Sept. 30, Dec. 31,
--------- -------- --------- --------
<S> <C> <C> <C> <C>
Revenues................................................. $ 133,184 $ 105,307 $ 67,189 $ 90,326
Cost of gas sold......................................... 32,715 28,106 1,898 (70)
--------- ---------- ---------- ---------
Revenues less cost of gas sold........................ 100,469 77,201 65,291 90,396
Other costs and expenses................................. 71,681 61,847 57,028 65,006
--------- ---------- ---------- ---------
Net earnings.......................................... $ 28,788 $ 15,354 $ 8,263 $ 25,390
========= ========== ========== =========
</TABLE>
<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
========= ========== ========== =========
</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.
Effective July 1, 1998, those gas purchases and sales formerly conducted by
the Company's unincorporated Merchant Division were assigned to an affiliate.
Therefore, revenues and cost of gas sold associated with such activities
subsequent to June 30, 1998 are not included in the Company's consolidated
financial statements.
F-23
<PAGE>
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
Reserves, capitalized costs, costs incurred in oil and gas acquisition,
exploration and development activities, results of operations and the
standardized measure of discounted future net cash flows are presented for the
exploration and production segment. Natural gas system reserves and the related
standardized measure of discounted future net cash flows are presented
separately for natural gas operations. All reserves are located in the United
States. The reserve information for 1998 for the Natural Gas System shown below
were prepared by Huddleston, Colorado's independent engineers, while the
Exploration and Production portions are as prepared by Coastal's engineers and
reviewed by Huddleston. The reserves as of December 31, 1997 and 1996 are as
prepared by Huddleston.
<TABLE>
<CAPTION>
Estimated Quantities of Proved Reserves
Natural Gas Exploration
Company-Owned Reserves System and Production
---------------------- ----------- --------------------------
Developed Developed Undeveloped Total
----------- --------- ----------- -------
<S> <C> <C> <C> <C>
Natural Gas (MMcf):
-------------------
1998............................................. 211,761 91,302 21,739 324,802
1997............................................. 248,248 75,200 38,883 362,331
1996............................................. 267,927 74,963 39,803 382,693
Oil, Condensate and Natural Gas Liquids (000 barrels):
------------------------------------------------------
1998............................................. 237 383 167 787
1997............................................. 349 543 363 1,255
1996............................................. 391 427 282 1,100
</TABLE>
Changes in proved reserves since the end of 1995 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 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
-------- -------- -------- --------
Production during 1998.......................... (39,058) ( 10,949) (44) (64)
Extensions and discoveries...................... 404 338 - -
Sales of reserves in-place...................... - (13,619) - (192)
Acquisitions.................................... - - - -
Revisions of previous quantity estimates and
other........................................ 2,167 23,188 (68) (100)
-------- -------- -------- --------
Total, end of 1998.............................. 211,761 113,041 237 550
======== ======== ======== ========
</TABLE>
F-24
<PAGE>
Total proved reserves for the natural gas system exclude storage gas and
liquids volumes. The natural gas system storage gas volumes are 41,213, 40,376
and 38,842 MMcf and storage liquids volumes are approximately 232,000, 209,000
and 192,000 barrels at December 31, 1998, 1997 and 1996, respectively. Volumes
are based on Huddleston's report and include estimates which differ slightly
from actuals.
Capitalized Costs Relating to Exploration and Production Activities
(thousands of dollars)
<TABLE>
<CAPTION>
December 31,
--------------------------
1998 1997
----------- -----------
<S> <C> <C>
Proved and Unproved Properties
- ------------------------------
Proved Properties................................................................... $ 135,812 $ 129,770
Unproved Properties................................................................. 522 730
----------- -----------
136,334 130,500
Accumulated depreciation, depletion and amortization................................ (108,791) (107,489)
----------- -----------
$ 27,543 $ 23,011
=========== ===========
</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, 1998.
The Company regularly evaluates these costs to determine whether impairment has
occurred.
<TABLE>
<CAPTION>
Years Costs Incurred
------------------------------------------------------
Prior
Total 1998 1997 1996 to 1996
----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Property Acquisition...................... $ 1,448 $ 1,448 $ - $ - $ -
Exploration............................... 390 207 174 9 -
Capitalized Interest...................... 25 25 - - -
----------- ----------- ----------- ----------- -----------
$ 1,863 $ 1,680 $ 174 $ 9 $ -
=========== =========== =========== =========== ===========
</TABLE>
Costs Incurred in Oil and Gas Acquisition, Exploration and Development
Activities (thousands of dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------
1998 1997 1996
-------- -------- --------
<S> <C> <C> <C>
Property acquisition costs:
Proved................................................................. $ 1,797 $ 27 $ 51
Unproved............................................................... 1,449 8 2
Exploration costs............................................................ 177 237 107
Development costs............................................................ 11,363 18,178 5,040
</TABLE>
F-25
<PAGE>
Results of Operations for Exploration and Production Activities
(thousands of dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------
1998 1997 1996
-------- -------- --------
<S> <C> <C> <C>
Revenues:
Sales..................................................................... $ 4,605 $ 5,255 $ 1,994
Transfers................................................................. 14,766 20,847 17,256
-------- -------- --------
Total.................................................................. 19,371 26,102 19,250
Production costs............................................................. (6,585) (5,660) (3,656)
Operating expenses........................................................... (2,338) (2,467) (2,165)
Depreciation, depletion and amortization..................................... (10,108) (11,908) (11,450)
-------- -------- --------
340 6,067 1,979
Income tax benefit .......................................................... 2,637 186 1,893
-------- -------- --------
Results of operations for producing activities
(excluding corporate overhead and interest costs)......................... $ 2,977 $ 6,253 $ 3,872
======== ======== ========
</TABLE>
The average amortization rate per equivalent Mcf was $0.89 in 1998, $0.91
in 1997 and $0.88 in 1996.
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 for the year ended December 31, 1998, 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,
---------------------------------------------------------------------------------
1998 1997 1996
------------------------- ------------------------- -------------------------
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.......... $ 256,442 $ 227,546 $ 291,333 $ 239,278 $ 430,290 $ 440,567
Future production and
development costs......... (79,376) (118,847) (87,111) (112,544) (85,619) (139,864)
Future income tax expenses... (57,301) (22,640) (66,657) (28,622) (117,047) (93,337)
----------- ----------- ----------- ----------- ----------- -----------
Future net cash flows........ 119,765 86,059 137,565 98,112 227,624 207,366
10% annual discount for
estimated timing of cash
flows..................... (50,376) (37,479) (57,330) (37,876) (87,979) (88,165)
----------- ----------- ----------- ----------- ----------- -----------
Standardized measure of
discounted future net
cash flows................ $ 69,389 $ 48,580 $ 80,235 $ 60,236 $ 139,645 $ 119,201
=========== =========== =========== =========== =========== ===========
</TABLE>
F-26
<PAGE>
Principal sources of change in the standardized measure of discounted
future net cash flows during each year are as follows (thousands of dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------------------------------------------------
1998 1997 1996
------------------------- ------------------------- -------------------------
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.......... $ (33,732) $ (12,785) $ (34,454) $ (19,411) $ (44,992) $ (14,644)
Net changes in prices and
production costs.......... 2,909 (2,376) (52,962) (80,968) 94,990 73,599
Extensions and discoveries... 392 303 10,343 12,625 3,548 48,073
Acquisitions................. - - - - - 2,169
Sales of reserves in-place... - (9,926) - (19,840) - (1,668)
Development costs incurred
during the period that
reduced estimated future
development costs......... - 7,958 - - - 167
Revisions of previous quantity
estimates, timing and other 5,539 (7,611) (34,149) (4,187) 38,935 22,054
Accretion of discount........ 8,435 5,948 17,924 15,171 6,680 2,142
Net change in income taxes... 5,611 6,833 33,888 37,645 (34,556) (46,324)
----------- ----------- ----------- ----------- ----------- -----------
Net change.............. $ (10,846) $ (11,656) $ (59,410) $ (58,965) $ 64,605 $ 85,568
=========== =========== =========== ============ =========== ===========
</TABLE>
None of the amounts include any value for storage gas and liquids volumes,
which were approximately 41 Bcf and 232 thousand barrels, respectively, at the
end of 1998. Volumes are based on Huddleston's report and include estimates
which differ slightly from actuals.
F-27
<PAGE>
EXHIBIT INDEX
Exhibit
Number Document
- -------- -----------------------------------------------------------------
(3.1)+ Certificate of Incorporation of the Company (Exhibit to the
Company's Annual Report on Form 10-K for the fiscal year ended
December 31, 1980).
(3.2)+ By-laws of the Company (Filed as Module CIGBY-LAWS on March 29,
1994).
(3.3)+ Certificate of Amendment of Certification of Incorporation of the
Company (Exhibit 3.1 to the Company's Annual Report on Form 10-K
for the fiscal year ended December 31, 1989).
(4) With respect to instruments defining the rights of holders of
long-term debt, the Company will furnish to the Securities and
Exchange Commission any such document on request.
(10)+ Agreement for Consulting Services between Colorado Interstate Gas
Company and Harold Burrow dated January 1, 1996 (Exhibit 10 to the
Company's Annual Report on Form 10-K for the fiscal year ended
December 31, 1995).
(21)* Subsidiaries of the Company.
(23)* Consent of Deloitte & Touche LLP.
(24)* Power of Attorney (included on signature pages herein).
(27)* Financial Data Schedule.
- ----------------------------------
Note:
+ Indicates documents incorporated by reference from prior filing
indicated.
* Indicates documents filed herewith.
EXHIBIT 21
SUBSIDIARIES OF COLORADO INTERSTATE GAS COMPANY
State of
Incorporation
-------------
CIG Exploration, Inc.......................................... Delaware
CIG Field Services Company.................................... Delaware
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 4, 1999, appearing in this Annual Report on Form 10-K of Colorado
Interstate Gas Company for the year ended December 31, 1998.
DELOITTE & TOUCHE LLP
Houston, Texas
March 24, 1999
<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, 1998 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-31-1998
<PERIOD-END> DEC-31-1998
<CASH> 109
<SECURITIES> 0
<RECEIVABLES> 327,415
<ALLOWANCES> 0
<INVENTORY> 8,666
<CURRENT-ASSETS> 371,663
<PP&E> 1,364,262
<DEPRECIATION> 711,957
<TOTAL-ASSETS> 1,116,267
<CURRENT-LIABILITIES> 188,566
<BONDS> 279,520
0
0
<COMMON> 27,561
<OTHER-SE> 468,910
<TOTAL-LIABILITY-AND-EQUITY> 1,116,267
<SALES> 380,365
<TOTAL-REVENUES> 396,006
<CGS> 62,649
<TOTAL-COSTS> 253,548
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 23,880
<INCOME-PRETAX> 118,578
<INCOME-TAX> 40,873
<INCOME-CONTINUING> 77,795
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 77,795
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
</TABLE>
