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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, 1999 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 February 1, 2000, 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
Recent Development........................................ 1
Natural Gas System........................................ 1
Operations............................................ 1
General........................................... 1
Gas Sales, Storage and Transportation............. 2
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
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........................................... 7
6. Selected Financial Data....................................... 7
7. Management's Discussion and Analysis of Financial Condition
and Results of Operations..................................... 7
7A. Quantitative and Qualitative Disclosures About Market Risk.... 7
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............ 8
11. Executive Compensation........................................ 8
12. Security Ownership of Certain Beneficial Owners and
Management.................................................... 8
13. Certain Relationships and Related Transactions................ 8
PART IV
14. Exhibits, Financial Statement Schedules, and Reports on
Form 8-K...................................................... 9
(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
"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 and changing
legislation and regulations. 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, 1999, the Company had 842 employees.
Selected financial information of the Company by industry segment is set
forth in Note 9 of Notes to Consolidated Financial Statements included herein.
RECENT DEVELOPMENT
Coastal and El Paso Energy Corporation ("El Paso Energy") announced on
January 18, 2000 the execution of definitive agreements for the merger of
Coastal and El Paso Energy. Each share of Coastal common stock and Class A
common stock will be converted on a tax-free basis (except for cash paid in lieu
of fractional shares) into 1.23 shares of El Paso Energy common stock. The
outstanding convertible preferred stock of Coastal will be exchanged tax free
(except for cash paid in lieu of fractional shares) for El Paso Energy common
stock on the same basis as if the preferred stock had been converted into
Coastal common stock immediately prior to the merger. It is expected that the
merger will be completed during the fourth quarter of 2000 and be accounted for
as a pooling of interests. The merger is subject to various conditions,
particularly federal regulatory approval.
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 years
1999 and 1998. PSCo was the only customer that accounted for more than 10% of
the Company's consolidated revenues in 1997.
The Company's principal transmission and storage pipeline facilities,
including certain facilities in the Panhandle Field of Texas ("Panhandle
Field"), at December 31, 1999 consisted of 4,405 miles of pipeline and 58
compressor stations with approximately 296,000 installed horsepower. The Company
is directly or indirectly connected to every major supply basin in the Rocky
Mountain region, and at December 31, 1999, 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.
1
<PAGE>
Colorado's gathering facilities, excluding certain FERC regulated
facilities in the Panhandle Field, consist of 2,400 miles of gathering lines and
approximately 52,000 horsepower of compression. Colorado owned and operated four
gas processing plants in 1999. These plants, with a total operating capacity of
approximately 477 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 in the Company's consolidated
financial statements. Additionally, Colorado engages in "open access" storage
and transportation of gas owned by third parties.
Colorado's deliveries for the years 1999, 1998 and 1997 were as follows:
Total System Daily Average
Year Deliveries System Deliveries
---- ----------------- -------------------
(Bcf) (MMcf)
1999 454 1,245
1998 480 1,315
1997 486 1,333
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 38 million gallons of
liquid hydrocarbons in 1999 compared to 46 million gallons in 1998 and 55
million gallons in 1997. Additionally, Colorado processed approximately 24
million gallons of liquid hydrocarbons owned by others in 1999 compared to 25
million gallons in 1998 and 24 million gallons in 1997.
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, the weather, 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 issued orders designed to increase competition in
the natural gas industry. These orders have resulted in: (1) pipelines offering
more service options and pricing flexibility in order to maintain and increase
business volumes, and (2) pipelines competing with their customers, who are now
allowed to resell, i.e., release, their unused firm capacity. In addition, firm
contracts traditionally had terms of five to ten years; however, due to
increased competition, new firm contracts are of a shorter average duration.
2
<PAGE>
GAS SYSTEM RESERVES
Reserves
The table below represents estimates of the Company's owned or controlled
reserves as of December 31, 1999, 1998 and 1997, as prepared by Huddleston,
Colorado's independent engineers.
<TABLE>
<CAPTION>
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
Owned or controlled by Colorado (Bcf).................................... 228 243 284
</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, 1999, Colorado maintained under its own account 3.6 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, 1999, and vary slightly from the
Huddleston report which includes estimates for November and December 1999.
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 from this Field may be taken for
customers other than Pioneer.
REGULATIONS AFFECTING GAS SYSTEM
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 U.S. Department of Transportation.
Additionally, the Company is subject to similar safety requirements from the
U.S. Department of Labor's Occupational Safety and Health Administration related
to its processing plants. Operations on United States government land are
regulated by the U.S. Department of the Interior. The Company is also subject to
laws and regulations associated with environmental matters as discussed on Page
6.
For further discussion of Colorado's regulatory matters, see Note 8 of
Notes to Consolidated Financial Statements, which is incorporated herein by
reference.
3
<PAGE>
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.
In 1999, the Company conveyed certain oil and gas properties to affiliated
companies in exchange for common stock, resulting in a reduction of the
Company's proved reserves of approximately 76 Bcf of natural gas equivalents.
The Company's investments in the affiliated companies are being accounted for
using the cost method.
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, 1999:
<TABLE>
<CAPTION>
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
Exploration and Production
Gas (MMcf)...................................................... 5,495 10,949 12,365
Oil, Condensate and Natural Gas Liquids (000 barrels)........... 80 64 129
Natural Gas System
Gas (MMcf)...................................................... 35,634 39,058 38,135
Oil, Condensate and Natural Gas Liquids (000 barrels)........... 24 44 57
</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, 1999:
<TABLE>
<CAPTION>
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
Average sales price:
Gas - per Mcf................................................... $ 1.93 $ 1.69 $ 1.96
Oil, Condensate and Natural Gas Liquids - per barrel............ 15.30 13.36 14.84
Average production cost per unit (equivalent Mcf).................... $ 0.59 $ 0.58 $ 0.43
</TABLE>
Acreage held under gas and oil mineral leases as of December 31, 1999 is
summarized as follows:
<TABLE>
<CAPTION>
Undeveloped Developed
------------------------ -------------------------
Area Gross Net Gross Net
-------------------------------------------------------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Exploration and Production.............................. 10,044 9,561 10,749 6,040
Natural Gas System...................................... - - 262,474 259,276
----------- ----------- ----------- -----------
10,044 9,561 273,223 265,316
=========== =========== =========== ===========
</TABLE>
The net developed acreage is concentrated principally in Texas (92%) and
Oklahoma (7%). The net undeveloped acreage is principally in Utah (98%).
4
<PAGE>
Information on wells drilled in the three years ended December 31, 1999, is
summarized as follows:
<TABLE>
<CAPTION>
1999 1998 1997
------------------------ ------------------------ -------------------------
Gross Net Gross Net Gross Net
----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Exploration and Production
--------------------------
Development Wells
-----------------
Oil........................ - - - - - -
Gas........................ 11 6.90 20 17.66 29 20.82
Dry Holes.................. - - - - - -
----------- ----------- ----------- ----------- ----------- -----------
11 6.90 20 17.66 29 20.82
----------- ----------- ----------- ----------- ----------- -----------
Natural Gas System
------------------
Development Wells
-----------------
Oil........................ - - - - - -
Gas........................ 22 13.10 6 6.00 3 3.00
Dry Holes.................. - - - - - -
----------- ----------- ----------- ----------- ----------- -----------
22 13.10 6 6.00 3 3.00
----------- ----------- ----------- ----------- ----------- -----------
Total.................. 33 20.00 26 23.66 32 23.82
=========== =========== =========== =========== =========== ===========
</TABLE>
Productive wells as of December 31, 1999 are as follows:
<TABLE>
<CAPTION>
Type of Well Gross Net
---------------------------------------------------------------------------------- ----------- -----------
<S> <C> <C>
Exploration and Production
Oil.......................................................................... - -
Gas.......................................................................... 31 15.20
----------- -----------
Total Exploration and Production...................................... 31 15.20
----------- -----------
Natural Gas System
Oil.......................................................................... 9 8.24
Gas.......................................................................... 805 792.44
----------- -----------
Total Natural Gas System.............................................. 814 800.68
----------- -----------
Total..................................................... 845 815.88
=========== ===========
</TABLE>
Information on Company-owned reserves of oil and gas is included herein
under "Supplemental Information on Oil and Gas Producing Activities (Unaudited)"
in Item 14(a)1 included herein.
The Company competes with major integrated oil companies and independent
oil and gas companies for suitable prospects for oil and gas drilling
operations. The availability of a ready market for gas discovered and produced
depends on numerous factors frequently beyond the Company's control. These
factors include the extent of gas discovery and production by other producers,
crude oil imports, the marketing of competitive fuels, and the proximity,
availability and capacity of gas pipelines and other facilities for the
transportation and marketing of gas. The production and sale of oil and gas is
subject to a variety of federal and state regulations, including regulation of
production levels.
5
<PAGE>
ENVIRONMENTAL
Colorado's environmental matters are discussed in Note 8 of Notes to
Consolidated Financial Statements, which is incorporated herein by reference.
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, 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 and the releases are valid and dismissing all tort claims
and claims for breach of any duty of disclosure. The remaining claim for
underpayment of royalties was tried to a jury which, in May 1995, made findings
favorable to Colorado. On June 7, 1995, the trial court entered a judgment that
the lessors recover no monetary damages from Colorado and permanently estopping
the lessors from asserting any claim based on an interpretation of the contract
different than that asserted by Colorado in the litigation. The lessors' motion
for new trial was denied on July 18, 1997, and both parties filed appeals. On
June 7, 1996, the same plaintiffs sued Colorado in state court in Amarillo,
Texas, for underpayment of royalties. Colorado removed the second lawsuit to
federal court which granted a stay of the second lawsuit pending the outcome of
the first lawsuit. Oral arguments were heard before the Fifth Circuit Court of
Appeals on December 4, 1998, and the parties are awaiting the Court's decision.
Two legal proceedings, one in federal court and the other in state court,
have been instituted against a number of gas pipeline companies and their
affiliates, including Colorado, Coastal and several of Coastal's other
subsidiaries. The plaintiffs in each suit seek damages for the alleged
undermeasurement of the heating value and the volume of natural gas. In the
federal proceeding, Jack Grynberg filed 77 separate False Claim Act suits in
September 1997 against natural gas transmission companies and producers,
gatherers, and processors of natural gas, seeking unspecified damages which
could include treble damages for the maximum period permitted by law
(potentially as much as ten years) and penalties of up to $10,000 per false
claim. In addition to the measurement claims, these suits also allege that the
defendants undervalued the gas in paying royalties. The Coastal defendants were
sued in the U.S. District Courts of Colorado and the Eastern District of
Michigan. In April 1999, the U.S. Department of Justice notified the Company
that the United States will not intervene in these cases at this time. The
MultiDistrict Litigation Panel has consolidated the Grynberg suits with several
other Grynberg cases for pre-trial proceedings in Wyoming. The defendants have
filed a motion to dismiss which will be argued in March of 2000.
In the state proceedings, the Quinque Operating Company, on behalf of
itself and subclasses of gas producers, royalty owners, overriding royalty
owners, and state taxing authorities, in May 1999 instituted a legal proceeding
in State Court in Stevens County, Kansas against over 200 gas companies,
including Colorado and several other Coastal subsidiaries. The Quinque suit
seeks unspecified actual, punitive and treble damages for the alleged
undermeasurement of all natural gas measured in the United States from
non-federal and non-Indian lands since 1974. The plaintiffs are seeking
certification of a national class of all similarly situated gas producers,
royalty owners, overriding royalty owners,
6
<PAGE>
and state taxing authorities. The suit has been removed to the U.S. District
Court for the District of Kansas. The plaintiffs have filed a motion to remand
the case back to the state court, and several defendants have filed a motion
under the MultiDistrict Litigation rules to have the suit transferred to Wyoming
and consolidated with the Grynberg proceedings for pre-trial proceedings.
Other lawsuits and other proceedings which have arisen in the ordinary
course of business are pending or threatened against the Company or its
subsidiaries.
Although no assurances can be given and no determination can be made at
this time as to the outcome of any particular lawsuit or proceeding, the Company
believes there are meritorious defenses to substantially all of the above claims
and that any liability which may finally be determined should not have a
material adverse effect on the Company's consolidated financial position or
results of operations.
Item 4. Submission of Matters to a Vote of Security Holders.
The information called for by this item is omitted pursuant to General
Instruction (I) of Form 10-K.
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, 1999, 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.
This information called for by this item is omitted pursuant to General
Instruction (I) of Form 10-K.
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.
Management's Discussion and Analysis of Financial Condition and Results of
Operations is presented on pages F-1 and F-2 herein.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
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, 1999 and 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. Fair values are calculated as the net present
value of the expected cash flows of the financial instrument.
<TABLE>
<CAPTION>
Millions of Dollars 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
1999......................... $ 288.8 $ 280.2 $ (8.6) $ 298.1 $ 9.3
1998......................... 321.2 312.3 (8.9) 328.8 7.6
</TABLE>
7
<PAGE>
The Company has notes receivable from related parties with a carrying value
of $297.2 million and $243.0 million and a note payable to a related party with
a carrying value of $2.5 million and $2.8 million at December 31, 1999 and 1998,
respectively. 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 the December 31 levels would not
have a material impact on earnings.
The Company's management of market risks is consistent with the prior year.
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.
PART III
Item 10. Directors and Executive Officers of the Registrant.
The information called for by this item is omitted pursuant to General
Instruction (I) of Form 10-K.
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.
8
<PAGE>
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a) The following documents are filed as part of this Annual Report or
incorporated herein by reference:
1. Financial Statements and Supplemental Information.
The following Consolidated Financial Statements of Colorado and
Subsidiaries and Supplemental Information are included in response to
Item 8 hereof on the attached pages as indicated:
<TABLE>
<CAPTION>
Page
<S> <C>
Independent Auditors' Report.................................................................... F-3
Consolidated Balance Sheet at December 31, 1999 and 1998........................................ F-4
Statement of Consolidated Earnings for the Years Ended December 31, 1999, 1998 and 1997......... F-6
Statement of Consolidated Retained Earnings and Additional Paid-In Capital for the Years
Ended December 31, 1999, 1998 and 1997....................................................... F-6
Statement of Consolidated Cash Flows for the Years Ended December 31, 1999, 1998 and 1997....... F-7
Notes to Consolidated Financial Statements...................................................... F-8
Supplemental Information on Oil and Gas Producing Activities (Unaudited)........................ F-20
</TABLE>
2. Financial Statement Schedules.
Schedules are omitted as not applicable or not required, or the
required information is shown in the Consolidated Financial
Statements or Notes thereto.
3. Exhibits.
(3.1)+ Certificate of Incorporation of the Company (Exhibit to the
Company's Annual Report on Form 10-K for the fiscal year ended
December 31, 1980).
(3.2)+ By-laws of the Company (Filed as Module CIGBY-LAWS on March 29,
1994).
(3.3)+ Certificate of Amendment of Certification of Incorporation of
the Company (Exhibit 3.1 to the Company's Annual Report on Form
10-K for the fiscal year ended December 31, 1989).
(4) With respect to instruments defining the rights of holders of
long-term debt, the Company will furnish to the Securities and
Exchange Commission any such document on request.
(10)+ Agreement for Consulting Services between Colorado Interstate
Gas Company and Harold Burrow dated January 1, 1996 (Exhibit 10
to the Company's Annual Report on Form 10-K for the fiscal year
ended December 31, 1995).
(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,
1999.
9
<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
February 25, 2000
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 Director
February 25, 2000 February 25, 2000
By: HAROLD BURROW By: DAN A. HOMEC
---------------------------- -----------------------------
Harold Burrow Dan A. Homec
Director Principal Accounting Officer
February 25, 2000 February 25, 2000
By: JON R. WHITNEY By: C. SCOTT HOBBS
--------------------------- -----------------------------
Jon R. Whitney C. Scott Hobbs
Director Director
February 25, 2000 February 25, 2000
By: DONALD H. GULQUIST
----------------------------
Donald H. Gulquist
Senior Vice President and
Principal Financial Officer
February 25, 2000
10
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The Notes to Consolidated Financial Statements contain information that is
pertinent to the following analysis.
The information required by this Item is presented in a reduced disclosure
format pursuant to General Instruction (I) of Form 10-K.
Results of Operations
Operating Revenues. The operating revenues by segment were as follows
(thousands of dollars):
<TABLE>
<CAPTION>
Year Ended
December 31,
--------------------------
1999 1998
----------- -----------
<S> <C> <C>
Natural gas................................................................. $ 299,276 $ 368,056
Exploration and production.................................................. 11,776 19,325
Eliminations................................................................ (41) (7,016)
----------- -----------
$ 311,011 $ 380,365
=========== ===========
</TABLE>
Earnings Before Interest and Income Taxes. The earnings before interest and
income taxes by segment were as follows (thousands of dollars):
<TABLE>
<CAPTION>
Year Ended
December 31,
--------------------------
1999 1998
----------- -----------
<S> <C> <C>
Natural gas................................................................. $ 159,303 $ 140,482
Exploration and production.................................................. 2,844 1,976
----------- -----------
$ 162,147 $ 142,458
=========== ===========
</TABLE>
Natural Gas
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.
Operating Revenues
Operating revenues from natural gas operations decreased $69 million in
1999 as compared to 1998 due to a $57 million decrease related to gas sales
volumes and a $14 million decrease related to average gas sales prices, net of
reservations, caused primarily by the assignment of the Company's Merchant
Division activity to an affiliate effective July 1, 1998, and a $3 million
decrease related to extracted products revenue partially offset by increased
gathering revenues of $5 million.
Cost of Gas Sold.
Cost of gas sold decreased $75 million before intercompany eliminations in
1999 as compared to 1998 due to the decrease in gas purchase volumes caused by
the assignment of the Company's Merchant Division activity to an affiliate
effective July 1, 1998.
F-1
<PAGE>
Operation and Maintenance
Operation and maintenance expense decreased $13 million in 1999 as compared
to 1998 due primarily to a $6 million increase in administrative expense
transfers, a $5 million decrease in gas transportation expenses and a $2 million
decrease in materials and supplies expense.
Exploration and Production
Operating Revenues
Operating revenues from exploration and production decreased $7 million in
1999 as compared to 1998 due to a $9 million decrease related to gas sales
volumes partially offset by an increase of $1 million related to average natural
gas sales prices and other net increases of $1 million.
Operation and Maintenance
Operation and maintenance expense decreased by $3 million in 1999 as
compared to 1998 primarily due to certain properties sold to affiliates,
decreased operating rents and lower management service fees.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization decreased by $5 million in 1999 as
compared to 1998 primarily due to lower production volumes.
Taxes on Income
Taxes on income increased by $10 million in 1999 as compared to 1998
primarily as a result of an increase in income before taxes and changes in
effective income tax rates. The effective federal income tax rate for the
Company was 35% in 1999 and 32% in 1998.
F-2
<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, 1999 and 1998, 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, 1999. 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, 1999 and 1998, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1999 in conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Denver, Colorado
February 8, 2000
F-3
<PAGE>
COLORADO INTERSTATE GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
<TABLE>
<CAPTION>
December 31,
---------------------------
ASSETS 1999 1998
------------ ------------
<S> <C> <C>
Current Assets:
Cash........................................................................... $ 731 $ 109
Notes receivable from affiliates............................................... 297,201 243,049
Accounts receivable............................................................ 48,808 41,309
Accounts receivable from affiliates............................................ 40,031 43,057
Materials and supplies......................................................... 8,303 8,666
Prepaid expenses............................................................... 419 820
Current portion of deferred income taxes....................................... 39,505 34,653
------------ ------------
434,998 371,663
------------ ------------
Plant, Property and Equipment, at cost:
Gas pipeline................................................................... 1,248,949 1,227,928
Gas and oil properties, at full-cost........................................... 96,650 136,334
------------ ------------
1,345,599 1,364,262
Accumulated depreciation, depletion and amortization........................... 704,790 711,957
------------ ------------
640,809 652,305
------------ ------------
Other Assets:
Investments in related parties................................................. 64,336 48,742
Other deferred charges......................................................... 45,504 43,557
------------ ------------
109,840 92,299
------------ ------------
$ 1,185,647 $ 1,116,267
============ ============
</TABLE>
See Notes to Consolidated Financial Statements.
F-4
<PAGE>
COLORADO INTERSTATE GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
<TABLE>
<CAPTION>
December 31,
---------------------------
LIABILITIES AND STOCKHOLDER'S EQUITY 1999 1998
------------ ------------
<S> <C> <C>
Current Liabilities:
Note payable to affiliate...................................................... $ 2,452 $ 2,784
Accounts payable and accrued expenses.......................................... 119,215 123,070
Accounts payable to affiliates................................................. 20,278 41,147
Taxes on income................................................................ 21,526 21,565
------------ ------------
163,471 188,566
------------ ------------
Debt:
Long-term debt................................................................. 279,594 279,520
------------ ------------
Deferred Credits:
Deferred income taxes.......................................................... 118,168 111,679
Other.......................................................................... 40,888 40,031
------------ ------------
159,056 151,710
------------ ------------
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.............................................................. 536,928 449,873
------------ ------------
583,526 496,471
------------ ------------
$ 1,185,647 $ 1,116,267
============ ============
</TABLE>
See Notes to Consolidated Financial Statements.
F-5
<PAGE>
COLORADO INTERSTATE GAS COMPANY AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED EARNINGS
(Thousands of Dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------
1999 1998 1997
---------- ---------- ----------
<S> <C> <C> <C>
Revenues:
Operating revenues:
Nonaffiliates....................................................... $ 225,477 $ 293,653 $ 326,694
Affiliates.......................................................... 85,534 86,712 122,382
---------- ---------- ---------
311,011 380,365 449,076
Other income - net..................................................... 15,425 15,641 12,547
---------- ---------- ---------
326,436 396,006 461,623
---------- ---------- ---------
Costs and Expenses:
Cost of gas sold:
Nonaffiliates....................................................... - 60,869 117,166
Affiliates.......................................................... - 7,346 12,623
---------- ---------- ---------
- 68,215 129,789
Operation and maintenance.............................................. 135,440 151,920 146,452
Depreciation, depletion and amortization............................... 28,849 33,413 39,327
Interest expense....................................................... 24,761 23,880 23,816
Taxes on income........................................................ 50,331 40,783 42,015
---------- ---------- ---------
239,381 318,211 381,399
---------- ---------- ---------
Net Earnings.............................................................. $ 87,055 $ 77,795 $ 80,224
========== ========== =========
</TABLE>
STATEMENT OF CONSOLIDATED RETAINED EARNINGS AND
ADDITIONAL PAID-IN CAPITAL
(Thousands of Dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------
1999 1998 1997
---------- ---------- ----------
<S> <C> <C> <C>
Retained Earnings:
Beginning balance......................................................... $ 449,873 $ 412,778 $ 370,054
Net earnings........................................................... 87,055 77,795 80,224
Less dividends on common stock......................................... - 40,700 37,500
---------- ---------- ---------
Ending balance............................................................ $ 536,928 $ 449,873 $ 412,778
========== ========== =========
Additional Paid-In Capital:
Beginning and ending balance.............................................. $ 19,037 $ 19,037 $ 19,037
========== ========== =========
</TABLE>
See Notes to Consolidated Financial Statements.
F-6
<PAGE>
COLORADO INTERSTATE GAS COMPANY AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CASH FLOWS
(Thousands of Dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------
1999 1998 1997
---------- ---------- ----------
<S> <C> <C> <C>
Net Cash Flow From Operating Activities:
Net earnings........................................................... $ 87,055 $ 77,795 $ 80,224
Add items not requiring cash:
Depreciation, depletion and amortization............................ 28,849 33,413 39,327
Deferred income taxes............................................... 6,576 3,396 13,177
Other............................................................... 218 (813) 2,538
Working capital and other changes, excluding changes relating to cash and
non-operating activities:
Accounts receivable................................................. (7,499) 22,010 (11,358)
Accounts receivable from affiliates................................. 3,026 (4,000) 11,999
Materials and supplies.............................................. 363 175 830
Prepaid expenses.................................................... 401 (727) 324
Accounts payable and accrued expenses............................... (3,855) (15,638) 6,067
Accounts payable to affiliates...................................... (20,869) 14,687 1,104
Taxes on income..................................................... (39) 16,136 (7,733)
---------- ---------- ---------
94,226 146,434 136,499
---------- ---------- ---------
Cash Flow from Investing Activities:
Purchases of plant, property and equipment............................. (45,562) (84,022) (70,661)
Proceeds from sale of plant, property and equipment.................... 10,417 24 8,374
Investments in related parties......................................... (3,975) (4,525) (3,161)
Net increase in notes receivable from affiliates....................... (54,152) (23,394) (80,265)
Recovery of gas supply prepayments..................................... - - 79
---------- ---------- ---------
(93,272) (111,917) (145,634)
---------- ---------- ---------
Cash Flow from Financing Activities:
Net (decrease) increase in note payable to affiliate................... (332) 2,784 -
Issuance of senior debentures.......................................... - - 99,604
Common dividends paid.................................................. - (40,700) (37,500)
Term loan.............................................................. - - (50,000)
---------- ---------- ---------
(332) (37,916) 12,104
---------- ---------- ---------
Net Increase (Decrease) in Cash........................................... 622 (3,399) 2,969
Cash at Beginning of Year................................................. 109 3,508 539
---------- ---------- ---------
Cash at End of Year....................................................... $ 731 $ 109 $ 3,508
========== ========== =========
</TABLE>
See Notes to Consolidated Financial Statements.
F-7
<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.
- - 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 was used for an investment in
which the Company had a 50% voting interest and exercised significant influence.
Other investments in which the Company has less than a 20% voting interest are
accounted for by the cost method.
- - 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 $24.8 million, $24.6 million and $24.9 million in
1999, 1998 and 1997, respectively. Cash payments for income taxes amounted to
$43.8 million, $21.3 million and $32.9 million in 1999, 1998 and 1997,
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.
- - 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 $.3 million, $.5 million and $.2 million in 1999, 1998 and
1997, respectively. All costs incurred in the acquisition, exploration and
development of gas and oil properties, including unproductive wells, are
capitalized under the full-cost method of accounting. Such costs include the
costs of all
F-8
<PAGE>
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
1997-1999). 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 1999 and 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 exploration and production segment amortization rate per equivalent unit
of a thousand cubic feet of gas production for oil and gas operations was $.87
for the year 1999, $.89 for the year 1998 and $.91 for the year 1997.
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.
In 1997, the Company re-examined the useful lives of its assets and 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.
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 FASB has issued Statement of Financial Accounting Standards No. 133,
"Accounting for Derivative Instruments and Hedging Activities" ("FAS 133"), as
amended by Statement of Financial Accounting Standards No. 137, to be effective
for all fiscal quarters of fiscal years beginning after June 15, 2000. 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, if any, of FAS 133.
The Company adopted AICPA Statement of Position 98-5, "Reporting on the
Costs of Start-Up Activities" ("SOP 98-5") in 1999. The application of SOP 98-5
did not have a material effect on the Company's consolidated financial
statements.
The Company adopted the FASB Emerging Issues Task Force Issue No. 98-10,
"Accounting for Contracts in Energy Trading and Risk Management Activities" in
1999. The application of Issue No. 98-10 did not have a material effect on the
Company's consolidated financial statements.
- - 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.
F-9
<PAGE>
- - 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>
1999 1998
--------- ---------
<S> <C> <C>
6.85% Senior Debentures, due 2037................................................. $ 100,000 $ 100,000
10% Senior Debentures, due 2005................................................... 179,594 179,520
--------- ---------
$ 279,594 $ 279,520
========= =========
</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, 1999, the Company and certain affiliates could incur an aggregate
of approximately $3 billion of additional indebtedness.
3. Common Stock and Other Stockholder's Equity
All of the Company's common stock is owned by Coastal Natural Gas.
At December 31, 1999, there were no restrictions on retained earnings as to
the Company's ability to declare dividends on common stock.
4. 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, 1999 December 31, 1998
--------------------------- ---------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
----------- ----------- ----------- ----------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Financial assets:
Cash....................................... $ 731 $ 731 $ 109 $ 109
Notes receivable from affiliates........... 297,201 297,201 243,049 243,049
Financial liabilities:
Long-term debt............................. 279,594 288,793 279,520 321,186
Note payable to affiliate.................. 2,452 2,452 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, 1999 and 1998, respectively, for new issues with similar remaining
maturities.
F-10
<PAGE>
5. Taxes On Income
Provisions for income taxes are composed of the following (thousands of
dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------
1999 1998 1997
-------- -------- --------
<S> <C> <C> <C>
Current Income Taxes:
Federal............................................................. $ 40,331 $ 34,721 $ 25,697
State............................................................... 3,424 2,666 3,141
-------- -------- --------
43,755 37,387 28,838
-------- -------- --------
Deferred Income Taxes:
Federal............................................................. 5,764 2,124 13,059
State............................................................... 812 1,272 118
-------- -------- --------
6,576 3,396 13,177
-------- -------- --------
Taxes on Income........................................................ $ 50,331 $ 40,783 $ 42,015
======== ======== ========
</TABLE>
Coastal and the Internal Revenue Service ("IRS") Appeals Office have
concluded a final settlement of adjustments originally proposed to federal
income tax returns filed for the years 1985 through 1987 and have concluded a
tentative settlement of the additional adjustments proposed by the IRS to those
returns. Coastal and the IRS Appeals Office have also concluded a tentative
settlement of the adjustments proposed to Coastal's federal income tax returns
filed for the years 1988 through 1990. Coastal has received notice of proposed
adjustments to Coastal's federal income tax returns filed for the years 1991
through 1994, and Coastal is currently contesting certain of these adjustments
before the IRS Appeals Office. Examination of Coastal's federal income tax
returns filed for the years 1995, 1996 and 1997 began in 1999. It is the opinion
of management that adequate provisions for federal income taxes have been
reflected in the 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,
--------------------------------
1999 1998 1997
-------- -------- --------
<S> <C> <C> <C>
Tax expense computed by applying the U.S. federal income
tax rate of 35%..................................................... $ 48,085 $ 41,502 $ 42,784
Increases (reductions) in taxes resulting from:
State income tax cost............................................... 2,753 2,560 2,118
Tight sands gas credit.............................................. (1,419) (2,756) (2,309)
Other............................................................... 912 (523) (578)
-------- -------- --------
Taxes on Income........................................................ $ 50,331 $ 40,783 $ 42,015
======== ======== ========
</TABLE>
F-11
<PAGE>
Deferred tax liabilities (assets) which are recognized for the estimated
future tax effects attributable to temporary differences are (thousands of
dollars):
<TABLE>
<CAPTION>
December 31,
---------------------
1999 1998
--------- ---------
<S> <C> <C>
Excess of book basis over tax basis of plant, property and equipment.............. $ 116,446 $ 110,459
Other............................................................................. 1,722 1,220
--------- ---------
Deferred tax liabilities....................................................... 118,168 111,679
--------- ---------
Provisions for rate refunds and contested claims.................................. (25,447) (26,219)
Accrued expenses.................................................................. (10,804) (7,852)
Other............................................................................. (3,254) (582)
--------- ---------
Deferred tax assets............................................................ (39,505) (34,653)
--------- ---------
Deferred income taxes.......................................................... $ 78,663 $ 77,026
========= =========
</TABLE>
6. 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, 1999, 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 1999, 1998 or 1997. 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 $2.6 million for 1999 and $2.3 million for 1998 and
1997, respectively.
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.
F-12
<PAGE>
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, 1999 and 1998, and a statement of the funded status
as of December 31, 1999 and 1998 (millions of dollars):
<TABLE>
<CAPTION>
Year Ended
December 31,
--------------------
1999 1998
-------- --------
<S> <C> <C>
Change in Postretirement Benefit Obligation
Accumulated postretirement benefit obligation at beginning of year................. $ 14.3 $ 14.3
Service cost....................................................................... .3 .3
Interest cost...................................................................... .9 .9
Participant contributions.......................................................... .5 .5
Benefit payments................................................................... (1.4) (1.7)
-------- --------
Accumulated postretirement benefit obligation at end of year....................... $ 14.6 $ 14.3
======== ========
Change in Plan Assets
Fair value of plan assets at beginning of year..................................... $ 9.1 $ 9.0
Actual return on plan assets....................................................... .5 (.2)
Employer contributions............................................................. 1.4 1.4
Administrative expenses............................................................ (.7) -
Benefit payments................................................................... (.8) (1.1)
-------- --------
Fair value of plan assets at end of year........................................... $ 9.5 $ 9.1
======== ========
</TABLE>
<TABLE>
<CAPTION>
December 31,
--------------------
1999 1998
-------- --------
<S> <C> <C>
Funded Status
Funded status at year end.......................................................... $ (5.1) $ (5.2)
Unrecognized gain.................................................................. (4.7) (5.4)
Unrecognized transition obligation................................................. 10.8 11.6
-------- --------
Prepaid postretirement benefit asset............................................... $ 1.0 $ 1.0
======== ========
</TABLE>
The following table provides the components of net periodic postretirement
benefit cost for 1999, 1998 and 1997 (millions of dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------
1999 1998 1997
-------- -------- --------
<S> <C> <C> <C>
Service cost........................................................... $ .3 $ .3 $ .2
Interest cost.......................................................... .9 .9 .9
Amortization of transition obligation.................................. .8 .8 .8
Expected return on assets.............................................. (.2) (.2) (.2)
Amortization of net gain............................................... (.3) (.4) (.3)
-------- -------- --------
Net periodic postretirement benefit cost............................... $ 1.5 $ 1.4 $ 1.4
======== ======== ========
</TABLE>
The assumed health care cost trend rate used in measuring the accumulated
postretirement benefit obligation was 8.4% in 1999, 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 9.0% in 1998 and 9.7% in 1997.
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, 1999 by approximately 3.83% and the net postretirement health care
cost by approximately 3.45%. 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, 1999 by approximately 4.13%
and the net postretirement health care cost by approximately 3.98%. The assumed
discount rate used in determining the accumulated postretirement benefit
obligation was 8.0% in 1999, 7.0% in 1998 and 7.25% in 1997 and the expected
long-term rate of return on assets was 4.3% in 1999, 1998 and 1997.
F-13
<PAGE>
7. Commitments
The Company had rental expense of approximately $5.3 million, $5.1 million
and $5.2 million in 1999, 1998 and 1997, respectively (excluding leases covering
natural resources). The aggregate minimum lease payments under existing
noncapitalized long-term leases are estimated to be $4.1 million, $3.9 million,
$2.6 million, $2.4 million and $2.4 million for the years 2000-2004,
respectively, and $.7 million thereafter.
The Company has executed a service agreement with WIC, an affiliate,
providing for the availability of pipeline transportation capacity through
December 31, 2007. Under the service agreement, the Company is required to make
minimum payments on a monthly basis with minimum annual payments of $9.9 million
per year for 2000-2004 and $11.5 million for later years. In 1999, the Company
expensed approximately $5.2 million related to this agreement.
8. 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, 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 and the releases are valid and dismissing all tort claims
and claims for breach of any duty of disclosure. The remaining claim for
underpayment of royalties was tried to a jury which, in May 1995, made findings
favorable to Colorado. On June 7, 1995, the trial court entered a judgment that
the lessors recover no monetary damages from Colorado and permanently estopping
the lessors from asserting any claim based on an interpretation of the contract
different than that asserted by Colorado in the litigation. The lessors' motion
for new trial was denied on July 18, 1997, and both parties filed appeals. On
June 7, 1996, the same plaintiffs sued Colorado in state court in Amarillo,
Texas, for underpayment of royalties. Colorado removed the second lawsuit to
federal court which granted a stay of the second lawsuit pending the outcome of
the first lawsuit. Oral arguments were heard before the Fifth Circuit Court of
Appeals on December 4, 1998, and the parties are awaiting the Court's decision.
Two legal proceedings, one in federal court and the other in state court,
have been instituted against a number of gas pipeline companies and their
affiliates, including Colorado, Coastal and several of Coastal's other
subsidiaries. The plaintiffs in each suit seek damages for the alleged
undermeasurement of the heating value and the volume of natural gas. In the
federal proceeding, Jack Grynberg filed 77 separate False Claim Act suits in
September 1997 against natural gas transmission companies and producers,
gatherers, and processors of natural gas, seeking unspecified damages which
could include treble damages for the maximum period permitted by law
(potentially as much as ten years) and penalties of up to $10,000 per false
claim. In addition to the measurement claims, these suits also allege that the
defendants undervalued the gas in paying royalties. The Coastal defendants were
sued in the U.S. District Courts of Colorado and the Eastern District of
Michigan. In April 1999, the U.S. Department of Justice notified the Company
that the United States will not intervene in these cases at this time. The
MultiDistrict Litigation Panel has consolidated the Grynberg suits with several
other Grynberg cases for pre-trial proceedings in Wyoming. The defendants have
filed a motion to dismiss which will be argued in March of 2000.
In the state proceedings, the Quinque Operating Company, on behalf of
itself and subclasses of gas producers, royalty owners, overriding royalty
owners, and state taxing authorities, in May 1999 instituted a legal proceeding
in State Court in Stevens County, Kansas against over 200 gas companies,
including Colorado and several other Coastal subsidiaries. The Quinque suit
seeks unspecified actual, punitive and treble damages for the alleged
undermeasurement of all natural gas measured in the United States from
non-federal and non-Indian lands since 1974. The plaintiffs are seeking
certification of a national class of all similarly situated gas producers,
royalty owners, overriding royalty owners, and state taxing authorities. The
suit has been removed to the U.S. District Court for the District of Kansas. The
plaintiffs have filed a motion to remand the case back to the state court, and
several defendants have filed a motion under the MultiDistrict Litigation rules
to have the suit transferred to Wyoming and consolidated with the Grynberg
proceedings for pre-trial proceedings.
F-14
<PAGE>
Other lawsuits and other proceedings which have arisen in the ordinary
course of business are pending or threatened against the Company or its
subsidiaries.
Although no assurances can be given and no determination can be made at
this time as to the outcome of any particular lawsuit or proceeding, the Company
believes there are meritorious defenses to substantially all of the above claims
and that any liability which may finally be determined should not have a
material adverse effect on the Company's consolidated financial position or
results of operations.
- - Environmental Matters
The Company's operations are subject to extensive and evolving federal,
state and local environmental laws and regulations which may affect such
operations and costs as a result of their effect on the construction, operation,
and maintenance of its pipeline 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 $.4 million in 1999 on environmental
capital projects and anticipates capital expenditures of approximately $1
million per year over the next several years 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 July 29, 1998, the FERC issued a "Notice of Proposed Rulemaking," in
which the FERC has proposed a number of 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. On February 9, 2000, the FERC issued a
final rule implementing certain of the changes that were discussed in these two
proposals. Among other things, the final rule: (a) removes the price ceilings
for short-term secondary market capacity releases for a trial period through
September 30, 2002; (b) permits pipelines to propose seasonally and
term-differentiated rates; (c) revises requirements relating to pipeline
scheduling procedures, capacity segmentation and penalties; (d) narrows the
right-of-first-refusal granted to long term shippers to retain their capacity;
and (e) expands pipeline reporting requirements. Colorado and its affiliates
will seek clarification of certain aspects of the final rule.
On September 15, 1999, the FERC issued a Policy Statement addressing the
certification and pricing of new pipeline construction projects. Under the
Policy Statement, applicants must first satisfy a threshold pricing requirement
of demonstrating that their projects can be constructed without subsidies from
existing customers. Second, the applicants must show that any adverse impacts of
the project on identified interests (existing customers of the applicant, other
existing pipelines and their captive customers, landowners and the surrounding
communities) are outweighed by its benefits. On October 19, 1999, Colorado and
its affiliates sought clarification and/or rehearing of the Policy Statement
insofar as it does not apply directly to those projects filed for approval under
the FERC's "optional certificate" regulations. Other parties also sought
rehearing of this and other aspects of the Policy Statement. On February 9,
2000, the FERC issued an order which, among other things, held that the Policy
Statement balancing criteria would apply to new optional certificate
applications while it receives comments on its companion notice proposing to
eliminate its optional certificate regulations.
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
F-15
<PAGE>
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.
9. 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 and income taxes; depreciation, depletion and
amortization; equity income (loss) from investments; and capital expenditures
for the years ended December 31, 1999, 1998 and 1997 are shown as follows
(thousands of dollars):
<TABLE>
<CAPTION>
1999 1998 1997
---------- --------- ----------
<S> <C> <C> <C>
Operating Revenues
Natural gas......................................................... $ 299,276 $ 368,056 $ 437,445
Exploration and production.......................................... 11,776 19,325 26,280
Exploration and production intersegment revenue eliminations........ (41) (7,016) (14,649)
---------- --------- ---------
Consolidated Totals............................................... $ 311,011 $ 380,365 $ 449,076
========== ========= =========
Earnings Before Interest and Income Taxes
Natural gas......................................................... $ 159,303 $ 140,482 $ 138,576
Exploration and production.......................................... 2,844 1,976 7,479
---------- --------- ---------
Consolidated Totals............................................... $ 162,147 $ 142,458 $ 146,055
========== ========= =========
Depreciation, Depletion and Amortization
Natural gas......................................................... $ 23,677 $ 23,305 $ 27,419
Exploration and production.......................................... 5,172 10,108 11,908
---------- --------- ---------
Consolidated Totals............................................... $ 28,849 $ 33,413 $ 39,327
========== ========= =========
Equity Income (Loss) From Investments
Natural gas......................................................... $ (444) $ 6,765 $ 5,211
Exploration and production.......................................... - - -
---------- --------- ---------
Consolidated Totals............................................... $ (444) $ 6,765 $ 5,211
========== ========= =========
Capital Expenditures
Natural gas......................................................... $ 39,461 $ 69,364 $ 52,090
Exploration and production.......................................... 6,101 14,658 18,571
---------- --------- ---------
Consolidated Totals............................................... $ 45,562 $ 84,022 $ 70,661
========== ========= =========
</TABLE>
Effective July 1, 1998, those gas purchases and sales of the natural gas
segment 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.
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.
F-16
<PAGE>
The Company's assets and amount of investment in equity method investees by
segment as of December 31, 1999 and 1998 are as follows (thousands of dollars):
<TABLE>
<CAPTION>
1999 1998
----------- -----------
<S> <C> <C>
Assets
Natural gas.............................................................. $ 1,141,860 $ 1,085,483
Exploration and production............................................... 43,787 30,784
----------- -----------
Consolidated Totals.................................................. $ 1,185,647 $ 1,116,267
=========== ===========
Equity Method Investments (included in Investments
in related parties)
Natural gas.............................................................. $ - $ 12,034
Exploration and production............................................... - -
----------- -----------
Consolidated Totals.................................................. $ - $ 12,034
=========== ===========
</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,
-----------------------------------
1999 1998 1997
---------- --------- ----------
<S> <C> <C> <C>
PSCo
Amount.............................................................. $ 87,141 $ 112,468 $ 165,793
========== ========= =========
Percent............................................................. 27% 28% 36%
========== ========= =========
Pioneer
Amount.............................................................. $ 36,453 $ 39,805 $ *
========== ========= =========
Percent............................................................. 11% 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, 1999, 1998
and 1997. 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-17
<PAGE>
10. Transactions with Related Parties
The Statement of Consolidated Earnings includes the following major
transactions with related parties (thousands of dollars):
<TABLE>
<CAPTION>
1999 1998 1997
------------------ ------------------ -----------------
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.(1).................. $ * * % $ 12,268 6.1% $ * * %
CIG Merchant Company....................... 20,353 9.4 13,760 6.8 * *
Gas Sales -
CIG Resources Company...................... $ * * % $ 6,319 5.0% $ 35,981 18.9%
CIG Merchant Company....................... 24,184 41.6 25,751 20.4 32,481 17.1
Extracted Products and Gas Processing -
Coastal Refining & Marketing, Inc.......... $ - - % $ * * % $ 6,415 27.6%
Coastal Field Services Company............. 12,226 77.9 11,535 81.9 11,295 48.6
Incidental Gasoline, Oil and Condensate
Sales -
Coastal Refining & Marketing, Inc.......... $ 1,114 26.3% $ 1,156 31.6% $ 2,403 37.0%
Coastal States Trading, Inc................ 903 21.3 973 26.6 1,560 24.0
Natural Gas Production -
Engage Energy US, L.P.(1).................. $ - -% $ - -% $ 3,161 13.3%
CIG Merchant Company....................... 9,650 81.5 5,855 47.4 - -
Costs and Expenses
- ------------------
Gas Purchases -
Coastal Oil & Gas Corporation.............. $ - -% $ 7,234 10.0% $ 11,482 12.2%
Gathering, Transportation and Compression -
WIC........................................ $ 5,230 68.5% $ 8,500 92.0% $ 5,969 72.5%
<FN>
* Less than 5% of total
------------------
1 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 $9.6
million for 1999, $7.7 million for 1998 and $6.3 million for 1997. Services
provided by affiliated companies for the Company at cost were $8.0 million for
1999, $7.7 million for 1998 and $7.5 million for 1997. 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.
The Company participates in a program which matches short-term cash
excesses and requirements of participating affiliates, thus minimizing total
borrowings from outside sources. The Company had advanced $279.9 million and
$243.0 million to associated companies at a market rate of interest at December
31, 1999 and 1998, respectively. Such amount is repayable on demand.
Additionally, at December 31, 1999, the Company had advanced $17.3 million to an
affiliate on a long-term basis at a market rate of interest.
F-18
<PAGE>
The Company's investment in an affiliate, Coastal Medical Services, Inc.,
was $35.1 million and $36.7 million on December 31, 1999 and 1998, respectively.
The affiliate has assumed the responsibility for facilitating the management of
a portion of the medical obligations of the Company and other Coastal
subsidiaries.
In 1999, the Company conveyed certain oil and gas properties to affiliated
companies in exchange for common stock, resulting in a reduction of the
Company's proved reserves of approximately 76 Bcf of natural gas equivalents.
The Company's investments in the affiliated companies are being accounted for
using the cost method.
11. Quarterly Results of Operations (Unaudited)
The results of operations by quarter for the years ended December 31, 1999
and 1998 were (thousands of dollars):
<TABLE>
<CAPTION>
1999 Quarter Ended
----------------------------------------------
March 31, June 30, Sept. 30, Dec. 31,
--------- -------- --------- --------
<S> <C> <C> <C> <C>
Revenues................................................. $ 90,388 $ 73,824 $ 73,783 $ 88,441
Other costs and expenses................................. 59,694 59,698 61,281 58,708
--------- ---------- ---------- ---------
Net earnings.......................................... $ 30,694 $ 14,126 $ 12,502 $ 29,733
========= ========== ========== =========
</TABLE>
<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......................................... 38,205 30,297 - (287)
--------- ---------- ---------- ---------
Revenues less cost of gas sold........................ 94,979 75,010 67,189 90,613
Other costs and expenses................................. 66,191 59,656 58,926 65,223
--------- ---------- ---------- ---------
Net earnings.......................................... $ 28,788 $ 15,354 $ 8,263 $ 25,390
========= ========== ========== =========
</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.
12. Merger
Coastal and El Paso Energy Corporation ("El Paso Energy") announced on
January 18, 2000 the execution of definitive agreements for the merger of
Coastal and El Paso Energy. Each share of Coastal common stock and Class A
common stock will be converted on a tax-free basis (except for cash paid in lieu
of fractional shares) into 1.23 shares of El Paso Energy common stock. The
outstanding convertible preferred stock of Coastal will be exchanged tax free
(except for cash paid in lieu of fractional shares) for El Paso Energy common
stock on the same basis as if the preferred stock had been converted into
Coastal common stock immediately prior to the merger. It is expected that the
merger will be completed during the fourth quarter of 2000 and be accounted for
as a pooling of interests. The merger is subject to various conditions,
particularly federal regulatory approval.
F-19
<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 1999 and 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 are as prepared
by Huddleston. In 1999, the Company conveyed certain oil and gas properties to
affiliated companies in exchange for common stock, resulting in a reduction of
the Company's proved reserves of approximately 76 Bcf of natural gas
equivalents. The Company's investments in the affiliated companies are being
accounted for using the cost method.
Estimated Quantities of Proved Reserves
<TABLE>
<CAPTION>
Natural Gas Exploration
Company-Owned Reserves System and Production
---------------------- ----------- -------------------------
Developed Developed Undeveloped Total
----------- --------- ----------- -------
<S> <C> <C> <C> <C>
Natural Gas (MMcf):
------------------
1999............................................. 197,649 6,877 1,144 205,670
1998............................................. 211,761 91,302 21,739 324,802
1997............................................. 248,248 75,200 38,883 362,331
Oil, Condensate and Natural Gas Liquids (000 barrels):
-----------------------------------------------------
1999............................................. 249 140 19 408
1998............................................. 237 383 167 787
1997............................................. 349 543 363 1,255
</TABLE>
F-20
<PAGE>
Changes in proved reserves since the end of 1996 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 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
-------- -------- -------- --------
Production during 1999.......................... (35,634) (5,495) (24) (80)
Extensions and discoveries...................... - 930 - 19
Sales of reserves in-place...................... - - - -
Acquisitions.................................... - - - -
Revisions of previous quantity estimates and
other........................................ 21,522 (100,455) 36 (330)
-------- -------- -------- --------
Total, end of 1999.............................. 197,649 8,021 249 159
======== ======== ======== ========
</TABLE>
Total proved reserves for the natural gas system exclude storage gas and
liquids volumes. The natural gas system storage gas volumes are 41,472, 41,213
and 40,376 MMcf and storage liquids volumes are approximately 301,000, 232,000
and 209,000 barrels at December 31, 1999, 1998 and 1997, 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,
--------------------------
1999 1998
----------- -----------
<S> <C> <C>
Proved and Unproved Properties
Proved Properties................................................................... $ 95,535 $ 135,812
Unproved Properties................................................................. 1,115 522
----------- -----------
96,650 136,334
Accumulated depreciation, depletion and amortization................................ (93,639) (108,791)
----------- -----------
$ 3,011 $ 27,543
=========== ===========
</TABLE>
The Company follows the full-cost method of accounting for oil and gas
properties.
F-21
<PAGE>
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, 1999.
The Company regularly evaluates these costs to determine whether impairment has
occurred.
<TABLE>
<CAPTION>
Years Costs Incurred
------------------------------------------------------
Prior
Total 1999 1998 1997 to 1997
----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Property Acquisition...................... $ 977 $ - $ 977 $ - $ -
Exploration............................... 48 48 - - -
Capitalized Interest...................... 90 90 - - -
----------- ----------- ----------- ----------- -----------
$ 1,115 $ 138 $ 977 $ - $ -
=========== =========== =========== =========== ===========
</TABLE>
Costs Incurred in Oil and Gas Acquisition, Exploration and Development
Activities (thousands of dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------
1999 1998 1997
-------- -------- --------
<S> <C> <C> <C>
Property acquisition costs:
Proved................................................................. $ 67 $ 1,797 $ 27
Unproved............................................................... 31 1,449 8
Exploration costs............................................................ 138 177 237
Development costs............................................................ 5,852 11,363 18,178
</TABLE>
Results of Operations for Exploration and Production Activities
(thousands of dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------
1999 1998 1997
-------- -------- --------
<S> <C> <C> <C>
Revenues:
Sales..................................................................... $ 3,282 $ 4,605 $ 5,255
Transfers................................................................. 8,552 14,766 20,847
-------- -------- --------
Total.................................................................. 11,834 19,371 26,102
Production costs............................................................. (3,506) (6,585) (5,660)
Operating expenses........................................................... (1,445) (2,338) (2,467)
Depreciation, depletion and amortization..................................... (5,172) (10,108) (11,908)
-------- -------- --------
1,711 340 6,067
Income tax benefit .......................................................... 820 2,637 186
-------- -------- --------
Results of operations for producing activities
(excluding corporate overhead and interest costs)......................... $ 2,531 $ 2,977 $ 6,253
======== ======== ========
</TABLE>
The average exploration and production segment amortization rate per
equivalent Mcf was $.87 in 1999, $0.89 in 1998 and $0.91 in 1997.
F-22
<PAGE>
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved
Oil and Gas Reserve Quantities
Future cash inflows from the sale of proved reserves and estimated
production and development costs for the year ended December 31, 1999, 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 changes in
both natural gas and crude oil prices, may be subject to material future
revisions (thousands of dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------------------------------------------------------------
1999 1998 1997
------------------------- ------------------------- --------------------------
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.......... $ 228,888 $ 20,406 $ 256,442 $ 227,546 $ 291,333 $ 239,278
Future production and
development costs......... (73,652) (7,201) (79,376) (118,847) (87,111) (112,544)
Future income tax (expenses)
benefits................. (48,879) 2,781 (57,301) (22,640) (66,657) (28,622)
----------- ----------- ----------- ----------- ----------- -----------
Future net cash flows........ 106,357 15,986 119,765 86,059 137,565 98,112
10% annual discount for
estimated timing of cash
flows..................... (40,972) (2,415) (50,376) (37,479) (57,330) (37,876)
----------- ----------- ----------- ----------- ----------- -----------
Standardized measure of
discounted future net
cash flows................ $ 65,385 $ 13,571 $ 69,389 $ 48,580 $ 80,235 $ 60,236
=========== =========== =========== =========== =========== ===========
</TABLE>
Principal sources of change in the standardized measure of discounted
future net cash flows during each year are as follows (thousands of dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------------------------------------------------------
1999 1998 1997
------------------------- ------------------------- ---------------------------
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.......... $ (36,176) $ (8,328) $ (33,732) $ (12,785) $ (34,454) $ (19,411)
Net changes in prices and
production costs.......... (5,580) 13,203 2,909 (2,376) (52,962) (80,968)
Extensions and discoveries... - 1,468 392 303 10,343 12,625
Acquisitions................. - - - - - -
Sales of reserves in-place... - - - (9,926) - (19,840)
Development costs incurred
during the period that
reduced estimated future
development costs......... - 2,190 - 7,958 - -
Revisions of previous quantity
estimates, timing and other 27,897 (55,872) 5,539 (7,611) (34,149) (4,187)
Accretion of discount........ 6,497 4,509 8,435 5,948 17,924 15,171
Net change in income taxes... 3,358 7,821 5,611 6,833 33,888 37,645
----------- ----------- ----------- ----------- ----------- -----------
Net change.............. $ (4,004) $ (35,009) $ (10,846) $ (11,656) $ (59,410) $ (58,965)
=========== =========== =========== =========== =========== ============
</TABLE>
None of the amounts include any value for storage gas and liquids volumes,
which were approximately 41 Bcf and 301 thousand barrels, respectively, at the
end of 1999. Volumes are based on Huddleston's report and include estimates
which differ slightly from actuals.
F-23
<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).
(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.
<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,
1999 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-31-1999
<PERIOD-END> DEC-31-1999
<CASH> 731
<SECURITIES> 0
<RECEIVABLES> 386,040
<ALLOWANCES> 0
<INVENTORY> 8,303
<CURRENT-ASSETS> 434,998
<PP&E> 1,345,599
<DEPRECIATION> 704,790
<TOTAL-ASSETS> 1,185,647
<CURRENT-LIABILITIES> 163,471
<BONDS> 279,594
0
0
<COMMON> 27,561
<OTHER-SE> 555,965
<TOTAL-LIABILITY-AND-EQUITY> 1,185,647
<SALES> 311,011
<TOTAL-REVENUES> 326,436
<CGS> 0
<TOTAL-COSTS> 164,289
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 24,761
<INCOME-PRETAX> 137,386
<INCOME-TAX> 50,331
<INCOME-CONTINUING> 87,055
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 87,055
<EPS-BASIC> 0
<EPS-DILUTED> 0
</TABLE>
