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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
▇▇▇▇▇▇▇▇▇▇, ▇▇ ▇▇▇▇▇
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM
TO
COMMISSION FILE NUMBER 1-6446
▇▇▇▇▇▇ ▇▇▇▇▇▇, INC.
(Exact name of registrant as specified in its charter)
KANSAS ▇▇-▇▇▇▇▇▇▇
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
▇▇▇ ▇▇▇▇▇▇, ▇▇▇▇▇ ▇▇▇▇, ▇▇▇▇▇▇▇, ▇▇▇▇▇ ▇▇▇▇▇
(Address of principal executive offices) (Zip Code)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE (▇▇▇) ▇▇▇-▇▇▇▇
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
Common stock, par value $5 per share New York Stock Exchange
Preferred share purchase rights New York Stock Exchange
Exchange feature of ▇▇▇▇▇▇ ▇▇▇▇▇▇ New York Stock Exchange
Management, LLC shares
Purchase obligation of ▇▇▇▇▇▇ ▇▇▇▇▇▇ New York Stock Exchange
Management, LLC shares
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
PREFERRED STOCK, CLASS A $5 CUMULATIVE SERIES
(Title of class)
Indicate by check ▇▇▇▇ 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 (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days: Yes [X] No [ ]
Indicate by check ▇▇▇▇ 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]
The aggregate market value of the voting stock held by non-affiliates of
the registrant was $4,794,480,772 as of January 31, 2002.
The number of shares outstanding of each of the registrant's classes of
common stock, as of the latest practicable date was: Common stock, $5 par value;
authorized 150,000,000 shares; outstanding 123,596,043 shares as of February 1,
2002.
DOCUMENTS INCORPORATED BY REFERENCE
Part III of this report incorporates by reference specific portions of the
Registrant's Proxy Statement relating to the 2002 Annual Meeting of
Stockholders.
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▇▇▇▇▇▇ ▇▇▇▇▇▇, INC. AND SUBSIDIARIES
CONTENTS
PAGE
NUMBER
------
PART I
Items 1 and 2. Business and Properties..................................... 3-13
Overview.................................................... 4
Natural Gas Pipeline Company of America..................... 5
▇▇▇▇▇▇ ▇▇▇▇▇▇ Retail........................................ 7
Power and Other............................................. 8
Regulation.................................................. 9
Environmental Regulation.................................... 11
Risk Factors................................................ 12
Item 3. Legal Proceedings........................................... 13-15
Item 4. Submission of Matters to a Vote of Security Holders......... 16
Executive Officers of the Registrant........................ 16-18
PART II
Item 5. Market for Registrant's Equity and Related Security Holder
Matters................................................... 18
Item 6. Selected Financial Data..................................... 19-20
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. 21-44
General..................................................... 21
Critical Accounting Policies and Estimates.................. 22
Consolidated Financial Results.............................. 24
Results of Operations....................................... 25
Natural Gas Pipeline Company of America..................... 26
▇▇▇▇▇▇ ▇▇▇▇▇▇ Retail........................................ 28
Power and Other............................................. ▇▇
▇▇▇▇▇▇ ▇▇▇▇▇▇ ▇▇▇▇▇ Pipeline................................ 30
▇▇▇▇▇▇ ▇▇▇▇▇▇ Interstate Gas Transmission................... 31
Other Income and (Expenses)................................. 31
Income Taxes -- Continuing Operations....................... 32
Discontinued Operations..................................... 32
Liquidity and Capital Resources............................. 33
Cash Flows.................................................. 35
Litigation and Environmental................................ 39
Regulation.................................................. 39
Risk Management............................................. 39
Recent Accounting Pronouncements............................ 42
Item 7A. Quantitative and Qualitative Disclosures About Market
Risk...................................................... 44
Item 8. Financial Statements and Supplementary Data................. 45-93
Item 9. Changes in and Disagreements With Accountants on Accounting
and Financial Disclosure.................................. 94
1
PAGE
NUMBER
------
PART III
Item 10. Directors and Executive Officers of the Registrant.......... 94
Item 11. Executive Compensation...................................... 94
Item 12. Security Ownership of Certain Beneficial Owners and
Management................................................ 94
Item 13. Certain Relationships and Related Transactions.............. 94
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K....................................................... 94-98
Signatures.................................................................. 99
---------------
Note: Individual financial statements of the parent company are omitted pursuant
to the provisions of Accounting Series Release No. 302.
2
PART I
ITEMS 1. AND 2. BUSINESS AND PROPERTIES.
In this report, unless the context requires otherwise, references to "we,"
"us," "our," or the "Company" are intended to mean ▇▇▇▇▇▇ ▇▇▇▇▇▇, Inc. (a Kansas
corporation, incorporated on May 18, 1927, formerly known as K N Energy, Inc.)
and its consolidated subsidiaries. All volumes of natural gas are stated at a
pressure base of 14.73 pounds per square inch absolute and at 60 degrees
Fahrenheit and, in most instances, are rounded to the nearest major multiple. In
this report, the term "MMcf" means million cubic feet, the term "Bcf" means
billion cubic feet and the term "MMBtus" means million British Thermal Units
("Btus"). Natural gas liquids consist of ethane, propane, butane, iso-butane and
natural gasoline.
(A) GENERAL DEVELOPMENT OF BUSINESS
We are one of the largest energy storage and transportation companies in
the United States, operating, either for ourselves or on behalf of ▇▇▇▇▇▇ ▇▇▇▇▇▇
Energy Partners, L.P., more than 30,000 miles of natural gas and products
pipelines. We own and operate Natural Gas Pipeline Company of America, a major
interstate natural gas pipeline system with approximately 10,000 miles of
pipelines and associated storage facilities. We own and operate a retail natural
gas distribution business serving approximately 233,000 customers in Colorado,
Nebraska and Wyoming. We construct, operate and, in some cases, own natural
gas-fired electric generation facilities. These businesses are discussed in
detail in the next section of this report. Our common stock is traded on the New
York Stock Exchange under the symbol "KMI." Our executive offices are located at
▇▇▇ ▇▇▇▇▇▇, ▇▇▇▇▇ ▇▇▇▇, ▇▇▇▇▇▇▇ ▇▇▇▇▇ ▇▇▇▇▇ and our telephone number is (713)
369-9000.
In addition to the businesses described above, we own the general partner
of, and a significant limited partner interest in, ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy
Partners, the largest publicly traded limited partnership in the pipeline
industry in terms of market capitalization and the second largest products
pipeline system in the United States in terms of volumes delivered. ▇▇▇▇▇▇
▇▇▇▇▇▇ Energy Partners also owns and/or operates a diverse group of assets used
in the transportation, storage and processing of energy products, including
refined petroleum products pipeline systems with more than 10,000 miles of
pipeline and over 32 associated terminals. ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners owns
10,000 miles of natural gas transportation pipelines and natural gas gathering
and storage facilities. ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners also owns or operates 33
dry bulk terminal facilities that transfer approximately 55 million tons of
coal, petroleum coke and other products annually and owns 11 liquids terminals
with storage capacity for up to 35 million barrels of refined petroleum products
and chemicals. In addition, ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners owns 51% of, and
operates, Plantation Pipeline Company and owns 100% of ▇▇▇▇▇▇ ▇▇▇▇▇▇ CO(2)
Company, L.P., formerly Shell CO(2) Company, Ltd. On December 17, 2001, ▇▇▇▇▇▇
▇▇▇▇▇▇ Energy Partners announced that it had entered into a definitive agreement
to acquire Tejas Gas, LLC for approximately $750 million in cash. Tejas Gas owns
and operates a 3,400-mile intrastate natural gas pipeline system in the Texas
Gulf Coast area. Additional information concerning the business of ▇▇▇▇▇▇ ▇▇▇▇▇▇
Energy Partners is contained in ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners' 2001
Annual
Report on Form 10-K.
In May 2001, ▇▇▇▇▇▇ ▇▇▇▇▇▇ Management, LLC, one of our indirect
subsidiaries, issued and sold shares in an underwritten initial public offering.
The net proceeds from the offering were used by ▇▇▇▇▇▇ ▇▇▇▇▇▇ Management to buy
i-units from ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners for $991.9 million. Upon purchase of
the i-units, ▇▇▇▇▇▇ ▇▇▇▇▇▇ Management became a partner in ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy
Partners and was delegated by ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners' general partner the
responsibility to manage and control ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners' business and
affairs. The i-units are a class of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners' limited
partner interests and have been, and will be, issued only to ▇▇▇▇▇▇ ▇▇▇▇▇▇
Management.
In the initial public offering, 10 percent of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Management's
shares were purchased by us, with the balance purchased by the public. The
equity interest in ▇▇▇▇▇▇ ▇▇▇▇▇▇ Management (which
3
is consolidated in our financial statements) purchased by the public created an
additional minority interest on our balance sheet of $892.7 million at the time
of the transaction. The earnings recorded by ▇▇▇▇▇▇ ▇▇▇▇▇▇ Management that are
attributable to its shares held by the public are reported as "minority
interest" in our consolidated statements of operations. We have certain rights
and obligations with respect to these securities, including an obligation to
purchase the ▇▇▇▇▇▇ ▇▇▇▇▇▇ Management shares or exchange them for ▇▇▇▇▇▇ ▇▇▇▇▇▇
Energy Partners, L.P.'s common units that we own or for cash. Additional
information concerning the business of, and our obligations to, ▇▇▇▇▇▇ ▇▇▇▇▇▇
Management is contained in ▇▇▇▇▇▇ ▇▇▇▇▇▇ Management's 2001
Annual Report on Form
10-K.
As of December 31, 2001, we owned, directly, and indirectly in the form of
i-units corresponding to the number of shares of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Management, LLC,
we own, approximately 31.1 million limited partner units of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy
Partners, representing approximately 18.7% of its total outstanding units. We
receive quarterly distributions on the i-units in additional i-units and
distributions on our other units in cash. We reflect our investment in ▇▇▇▇▇▇
▇▇▇▇▇▇ Energy Partners under the equity method of accounting and, accordingly,
report our share of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners' earnings as "Equity in
Earnings" in our Consolidated Statement of Operations in the period in which
such earnings are reported by ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners.
In addition to distributions received on our limited partner interests as
discussed above, we also receive an incentive distribution from ▇▇▇▇▇▇ ▇▇▇▇▇▇
Energy Partners as a result of our ownership of the general partner interest in
▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners. This incentive distribution is calculated in
increments based on the amount by which quarterly distributions to unit holders
exceed specified target levels as set forth in ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners'
partnership agreement, reaching a maximum of 50% of distributions allocated to
the general partner for distributions above $0.23375 per limited partner unit.
Including both our general and limited partner interests in ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy
Partners, at the current level of distributions, we currently are entitled to
receive approximately 50% of all quarterly distributions from ▇▇▇▇▇▇ ▇▇▇▇▇▇
Energy Partners, of which approximately 38% is attributable to our general
partner interest and 12% is attributable to our limited partner interest. The
actual level of distributions we will receive in the future will vary with the
level of distributable cash determined in accordance with ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy
Partners' partnership agreement.
On October 7, 1999, we completed the acquisition of ▇▇▇▇▇▇ ▇▇▇▇▇▇
(Delaware), Inc., a Delaware corporation and the sole stockholder of the general
partner of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners. To effect that acquisition, we issued
approximately 41.5 million shares of our common stock in exchange for all of the
outstanding shares of ▇▇▇▇▇▇ ▇▇▇▇▇▇ (Delaware). Upon closing of the transaction,
▇▇▇▇▇▇▇ ▇. ▇▇▇▇▇▇, Chairman and Chief Executive Officer of ▇▇▇▇▇▇ ▇▇▇▇▇▇
(Delaware), was named Chairman and Chief Executive Officer, and we were renamed
▇▇▇▇▇▇ ▇▇▇▇▇▇, Inc.
(B) FINANCIAL INFORMATION ABOUT SEGMENTS
Note 21 of the accompanying Notes to Consolidated Financial Statements
contains financial information about our business segments.
(C) NARRATIVE DESCRIPTION OF BUSINESS
OVERVIEW
We are an energy and related services provider. Our principal business
segments are: (1) Natural Gas Pipeline Company of America (NGPL) and affiliated
companies, a major interstate natural gas pipeline and storage system, (2)
▇▇▇▇▇▇ ▇▇▇▇▇▇ Retail, the regulated sale of natural gas to residential,
commercial and industrial customers and non-utility sales of natural gas to
certain utility customers under the Choice Gas Program, a program that allows
utility customers to choose their natural gas provider, and (3) Power and Other,
the construction and operation of natural gas-fired electric generation
facilities, together with various other activities not constituting separately
managed or reportable business segments. Natural gas transportation, sales and
storage accounted for approximately 90%, 96% and 95% of our consolidated
revenues in 2001, 2000 and 1999, respectively. The operations of ▇▇▇▇▇▇ ▇▇▇▇▇▇
Energy Partners, a
4
significant master limited partnership equity-method investee in which we hold
the general partner interest, include (i) liquids and refined products
pipelines, (ii) transportation and storage of natural gas, (iii) carbon dioxide
production and transportation and (iv) bulk and liquids terminals. Our equity in
the earnings of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners, net of the associated
amortization, constituted approximately 40%, 21% and 2% of our income from
continuing operations before interest and income taxes in 2001, 2000 and 1999,
respectively. As described in "Management's Discussion and Analysis of Financial
Condition and Results of Operations", at December 31, 1999 and 2000, we
transferred certain assets to ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners. In 1999, we
discontinued our wholesale natural gas marketing, non-energy retail marketing
services and natural gas gathering and processing businesses. Notes 6 and 21 of
the accompanying Notes to Consolidated Financial Statements contain additional
information on asset sales and our business segments. As discussed following,
certain of our operations are regulated by various federal and state entities.
NATURAL GAS PIPELINE COMPANY OF AMERICA
During 2001, Natural Gas Pipeline Company of America's segment earnings of
$346.6 million represented approximately 56% of ▇▇▇▇▇▇ ▇▇▇▇▇▇, Inc.'s income
before interest and income taxes. Through Natural Gas Pipeline Company of
America we own and operate approximately 10,000 miles of interstate natural gas
pipelines, field system lines and related facilities, consisting primarily of
two major interconnected transmission pipelines terminating in the Chicago
metropolitan area. The system is powered by 62 compressor stations in mainline
and storage service having an aggregate of approximately 1.0 million horsepower.
Natural Gas Pipeline Company of America's system has over 1,700 points of
interconnection with 32 interstate pipelines, 19 intrastate pipelines, a number
of gathering systems, and over 60 local distribution companies and other end
users, thereby providing significant flexibility in the receipt and delivery of
natural gas. Natural Gas Pipeline Company of America's Amarillo Line originates
in the West Texas and New Mexico producing areas and is comprised of
approximately 3,900 miles of mainline and various small-diameter pipelines. The
other major pipeline, the Gulf Coast Line, originates in the Gulf Coast areas of
Texas and Louisiana and consists of approximately 4,400 miles of mainline and
various small-diameter pipelines. These two main pipelines are connected at
points in Texas and Oklahoma by Natural Gas Pipeline Company of America's
700-mile Amarillo/Gulf Coast pipeline.
Natural Gas Pipeline Company of America provides transportation and storage
services to third-party natural gas distribution utilities, marketers,
producers, industrial end users and other shippers. Pursuant to transportation
agreements and Federal Energy Regulatory Commission tariff provisions, Natural
Gas Pipeline Company of America offers its customers firm and interruptible
transportation, storage, park-and-loan and no-notice services. Under Natural Gas
Pipeline Company of America's tariffs, firm transportation customers pay
reservation charges each month plus a commodity charge based on actual volumes
transported. Interruptible transportation customers pay a commodity charge based
upon actual volumes transported. Reservation and commodity charges are both
based upon geographical location and time of year. Under no-notice service,
customers pay a reservation charge for the right to have up to a specified
volume of natural gas delivered but, unlike with firm transportation service,
are able to meet their peaking requirements without making specific nominations.
Natural Gas Pipeline Company of America has the authority to negotiate rates
with customers as long as it has first offered service under its reservation and
commodity charge rate structure. Natural Gas Pipeline Company of America's
revenues have historically been higher in the first and fourth quarters of the
year, reflecting higher system utilization during the colder months. During the
winter months, Natural Gas Pipeline Company of America collects higher
transportation commodity revenue, higher interruptible transportation revenue,
winter-only capacity revenue and higher peak rates on certain contracts.
Natural Gas Pipeline Company of America's principal delivery market area
encompasses the states of Illinois, Indiana and Iowa and secondary markets in
portions of Wisconsin, Nebraska, Kansas, Missouri and Arkansas. Natural Gas
Pipeline Company of America is the largest transporter of natural gas to the
Chicago market and we believe that its cost of service is one of the most
competitive in the region. In 2001, Natural Gas Pipeline Company of America
delivered an average of 1.67 trillion Btus per day of natural gas to this
market. Given its strategic location at the center of the North American
pipeline grid,
5
we believe that Chicago is likely to continue to be a major natural gas trading
hub for the rapidly growing markets in the Midwest and Northeast.
Substantially all of Natural Gas Pipeline Company of America's pipeline
capacity is committed under firm transportation contracts ranging from one to
five years. Approximately 71% of the total transportation volume committed under
Natural Gas Pipeline Company of America's long-term firm transportation
contracts in effect on January 1, 2002 had remaining terms of less than three
years. Natural Gas Pipeline Company of America continues to actively pursue the
renegotiation, extension and/or replacement of expiring contracts. Nicor Gas and
Peoples Energy are Natural Gas Pipeline Company of America's two largest
customers. Contracts representing 28% of Natural Gas Pipeline Company of
America's total long-term contracted firm transport capacity as of January 1,
2002 are scheduled to expire during 2002.
Natural Gas Pipeline Company of America is one of the nation's largest
natural gas storage operators with approximately 600 Bcf of total natural gas
storage capacity, 215 Bcf of working gas capacity and up to 4.0 Bcf per day of
peak deliverability from its storage facilities, which are located near the
markets it serves. Natural Gas Pipeline Company of America owns and operates
eight underground storage fields in four states. These storage assets complement
its pipeline facilities and allow it to optimize pipeline deliveries and meet
peak delivery requirements in its principal markets. Natural Gas Pipeline
Company of America provides firm and interruptible gas storage service pursuant
to storage agreements and tariffs. Firm storage customers pay a monthly demand
charge irrespective of actual volumes stored. Interruptible storage customers
pay a monthly charge based upon actual volumes of gas stored.
Natural Gas Pipeline Company of America is a 50% joint venturer in the
Horizon Pipeline Company. Nicor-Horizon, a subsidiary of Nicor Inc. (NYSE: GAS)
is the other joint venturer. The Horizon Pipeline Company will lease 46 miles of
existing pipeline from Natural Gas Pipeline Company of America that it will
combine with 27 miles of 36-inch pipeline that it is currently constructing at
an estimated cost of $79 million. These combined facilities will allow Horizon
Pipeline Company to transport 380 MMcf of natural gas per day from near Joliet
into ▇▇▇▇▇▇▇ County in Illinois, connecting the emerging supply hub at Joliet
with the northern part of the Nicor Gas distribution system and an existing
Natural Gas Pipeline Company of America pipeline. Horizon Pipeline Company's
pipeline system, expected to be completed in the summer of 2002, will be
operated by Natural Gas Pipeline Company of America.
Natural Gas Pipeline Company of America is currently constructing a lateral
extension of its pipeline system from Centralia, Illinois into the metropolitan
east area of St. Louis. This lateral will consist of approximately 50 miles of
24-inch pipeline with an initial capacity of approximately 300,000 MMBtus per
day. We expect to place these facilities into service early in the third quarter
of 2002 at an estimated cost of $36.4 million.
Competition: Natural Gas Pipeline Company of America competes with other
transporters of natural gas in virtually all of the markets it serves and, in
particular, in the Chicago area, which is the northern terminus of Natural Gas
Pipeline Company of America's two major pipeline segments and its largest
market. These competitors include both interstate and intrastate natural gas
pipelines and, historically, most of the competition has been from such
pipelines with supplies originating in the United States. In recent periods,
Natural Gas Pipeline Company of America has also faced competition from
additional pipelines carrying Canadian produced natural gas into the Chicago
market. The most recent example is the Alliance Pipeline, which began service
during the 2000-2001 heating season. The additional pipeline capacity into the
Chicago market has increased competition for transportation into the area while,
at the same time, new pipelines, such as Vector Pipeline, have been or are
expected to be constructed for the specific purpose of transporting gas from the
Chicago area to other markets, generally further north and further east. The
overall impact of the increased pipeline capacity into the Chicago area combined
with additional take-away capacity and the increased demand in the area has
created a situation that remains dynamic with respect to the ultimate impact on
individual transporters such as Natural Gas Pipeline Company of America.
Natural Gas Pipeline Company of America also faces competition with respect
to the natural gas storage services it provides. Natural Gas Pipeline Company of
America has storage facilities in both
6
market and supply areas, allowing it to offer varied storage services to
customers. It faces competition from independent storage providers as well as
storage services offered by other natural gas pipelines and local natural gas
distribution companies.
The competition faced by Natural Gas Pipeline Company of America with
respect to its natural gas transportation and storage services is generally
price-based, although there is also a significant component related to the
variety, flexibility and the perceived reliability of services offered. Natural
Gas Pipeline Company of America's extensive pipeline system, with access to
diverse supply basins and significant storage assets in both the supply and
market areas, gives it a competitive advantage in some situations but,
typically, customers still have alternative sources for their requirements. In
addition, due to the price-based nature of much of the competition faced by
Natural Gas Pipeline Company of America, its proven ability to be a low-cost
provider is an important factor in its success in acquiring and retaining
customers. Additional competition for storage services could result from the
utilization of currently underutilized storage facilities or from conversion of
existing storage facilities from one use to another. In addition, competitive
existing storage facilities could, in some instances, be expanded.
▇▇▇▇▇▇ ▇▇▇▇▇▇ RETAIL
During 2001, ▇▇▇▇▇▇ ▇▇▇▇▇▇ Retail's segment earnings of $56.4 million
represented approximately 9% of ▇▇▇▇▇▇ ▇▇▇▇▇▇, Inc.'s income before interest and
income taxes. As of December 31, 2001, through ▇▇▇▇▇▇ ▇▇▇▇▇▇ Retail, our retail
natural gas distribution business served approximately 233,000 customers in
Colorado, Nebraska and Wyoming through approximately 8,600 miles of distribution
pipelines. Our intrastate pipelines, distribution facilities and retail natural
gas sales in Colorado and Wyoming are subject to the regulatory authority of
each state's utility commission. In Nebraska, retail natural gas sales rates for
residential and small commercial customers are regulated by each municipality
served.
▇▇▇▇▇▇ ▇▇▇▇▇▇ Retail's operations in Nebraska, Wyoming and northeastern
Colorado serve areas that are primarily rural and agricultural where natural gas
is used primarily for space heating, crop irrigation, grain drying and
processing of agricultural products. In much of Nebraska, the winter heating
load is balanced by irrigation requirements in the summer and grain drying
requirements in the fall. ▇▇▇▇▇▇ ▇▇▇▇▇▇ Retail's operations in western Colorado
serve fast-growing resort and associated service areas, and rural communities.
These areas are characterized primarily by natural gas use for space heating,
with historical annual growth rates of 6-8%. ▇▇▇▇▇▇ ▇▇▇▇▇▇ Retail operations
include non-jurisdictional products and services including the sale of commodity
natural gas in ▇▇▇▇▇▇ ▇▇▇▇▇▇ Retail's Choice Gas programs and natural
gas-related equipment and services.
To support ▇▇▇▇▇▇ ▇▇▇▇▇▇ Retail's business, underground storage facilities
are used to provide natural gas for load balancing and peak system demand.
Storage services for ▇▇▇▇▇▇ ▇▇▇▇▇▇ Retail's natural gas distribution services
are provided by three facilities in Wyoming and one facility in Colorado, all of
which are owned by wholly owned subsidiaries of ▇▇▇▇▇▇ ▇▇▇▇▇▇, Inc., and one
facility located in Nebraska and owned by ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners. The
peak natural gas withdrawal capacity available for ▇▇▇▇▇▇ ▇▇▇▇▇▇ Retail's
business is approximately 82 MMcf per day.
▇▇▇▇▇▇ ▇▇▇▇▇▇ Retail's natural gas distribution business relies on both the
intrastate pipelines it operates and third-party pipelines for transportation
and storage services required to serve its markets. The natural gas supply
requirements for ▇▇▇▇▇▇ ▇▇▇▇▇▇ Retail's natural gas distribution business are
met through contract purchases from third-party suppliers.
Through Rocky Mountain Natural Gas Company in Colorado and Northern Gas
Company in Wyoming, ▇▇▇▇▇▇ ▇▇▇▇▇▇ Retail provides transportation services to
affiliated local distribution companies as well as natural gas producers,
shippers and industrial customers. These two intrastate pipeline systems include
approximately 1,500 miles of transmission lines, field system lines and related
facilities. Through Northern Gas Company, ▇▇▇▇▇▇ ▇▇▇▇▇▇ Retail provides storage
services in Wyoming to its customers from its three storage fields, Oil Springs,
Bunker Hill and ▇▇▇▇ Ranch, which combined have 29.7 Bcf of total storage
capacity, 11.7 Bcf of working gas capacity, and up to 37 MMcf per day of peak
withdrawal capacity. Rocky Mountain Natural Gas Company operates the Wolf Creek
storage facility, which has
7
10.1 Bcf of total storage capacity, 2.7 Bcf of working gas capacity and provides
15 MMcf per day of withdrawal capacity for peak day use by its sales customers
in Colorado.
Effective November 30, 2001, we purchased natural gas distribution assets
from Citizens Communications Company (NYSE: CZN) for approximately $11 million.
The natural gas distribution assets serve approximately 13,400 residential,
commercial and agricultural customers in Bent, Crowley, Otero, Archuleta, La
Plata and Mineral Counties in Colorado. This transaction was approved by the
Colorado Public Utilities Commission on October 31, 2001.
Competition: The ▇▇▇▇▇▇ ▇▇▇▇▇▇ Retail natural gas distribution business
segment operates in areas with varying service area rules, including state
utility commission exclusively certificated service areas, non-exclusive
municipal franchises and competitive areas. Limited competitive natural gas
distribution pipelines exist within these service areas. The primary competition
for ▇▇▇▇▇▇ ▇▇▇▇▇▇ Retail's products is from alternative fuels such as electric
power and propane for heating use, and electric power, propane and diesel fuel
for agriculture use. ▇▇▇▇▇▇ ▇▇▇▇▇▇ Retail provides natural gas utility delivery
services based upon cost-of-service regulation in most of its service areas.
▇▇▇▇▇▇ ▇▇▇▇▇▇ Retail currently has unbundled the regulated commodity
natural gas supply in Nebraska and eastern Wyoming under Choice Gas Programs,
and on April 20, 2001, filed an application with the Wyoming Public Service
Commission to expand Choice Gas to cover all of its Wyoming customers. A
Stipulation and Agreement calling for approval of the application to expand
Choice Gas has been presented to the Wyoming Public Service Commission for its
consideration. The Choice Gas Program allows competitive commodity natural gas
providers to sell natural gas to approximately half of its total customers at
present, which will increase to approximately two thirds of its customers if its
pending application to expand the program in Wyoming is approved. In the
unbundled areas, ▇▇▇▇▇▇ ▇▇▇▇▇▇ Retail competes as one of five natural gas
marketing companies to provide the customer with natural gas commodity
offerings. ▇▇▇▇▇▇ ▇▇▇▇▇▇ Retail currently provides the commodity product for 66%
of the end use customers in the unbundled areas.
POWER AND OTHER
During 2001, Power and Other's segment earnings of $63.3 million
represented approximately 10% of ▇▇▇▇▇▇ ▇▇▇▇▇▇, Inc.'s income before interest
and income taxes. ▇▇▇▇▇▇ ▇▇▇▇▇▇ Power designs, develops and constructs power
projects and operates electric generation facilities as an independent power
producer. ▇▇▇▇▇▇ ▇▇▇▇▇▇ Power is, primarily, a fee-for-service business that
seeks to develop power projects for the benefit of long-term, off-take
customers. These customers take the commodity benefits and risks in the
marketplace and pay ▇▇▇▇▇▇ ▇▇▇▇▇▇ Power a fee for developing and constructing
and, in some cases, operating these facilities. ▇▇▇▇▇▇ ▇▇▇▇▇▇ Power takes
limited commodity price risk, as described below. ▇▇▇▇▇▇ ▇▇▇▇▇▇ Power's
customers include power marketers, power generation companies and utilities.
In 1998, ▇▇▇▇▇▇ ▇▇▇▇▇▇ Power acquired interests in the Thermo Companies,
which provided us with our first electric generation assets as well as knowledge
and expertise with General Electric Company jet engines (LMs) configured in a
combined cycle mode. Through the Thermo Companies, ▇▇▇▇▇▇ ▇▇▇▇▇▇ Power has
interests in three independent natural gas-fired LM projects in Colorado with an
aggregate of 380 megawatts of electric generation capacity. ▇▇▇▇▇▇ ▇▇▇▇▇▇ Power
used the LM knowledge to develop its proprietary "Orion" technology, which is
now being deployed into various power markets. ▇▇▇▇▇▇ ▇▇▇▇▇▇ Power has natural
gas price risk at the Colorado power facilities, which it manages through a
combination of fixed-price supply contracts, ▇▇▇▇▇▇, and short-term or floating
price contracts.
In May 2000, ▇▇▇▇▇▇ ▇▇▇▇▇▇ Power and Mirant Corporation (formerly Southern
Energy Inc.) announced plans to build a 550 megawatt natural gas-fired electric
power plant southeast of Little Rock, Arkansas, utilizing ▇▇▇▇▇▇ ▇▇▇▇▇▇ Power's
Orion technology. Mirant will operate the plant, manage the natural gas supply
and power sales for the project company that owns the power plant, in which
project company ▇▇▇▇▇▇ ▇▇▇▇▇▇ Power has a preferred investment. Natural gas
transportation service for the plant will be provided by Natural Gas Pipeline
Company of America. Construction is in process on the
8
facility, for which ▇▇▇▇▇▇ ▇▇▇▇▇▇ Power is the general contractor. Completion of
construction is expected by June 2002.
On February 20, 2001, ▇▇▇▇▇▇ ▇▇▇▇▇▇ Power announced an agreement under
which ▇▇▇▇▇▇▇▇ Energy Marketing and Trading agreed to supply natural gas to and
market capacity for 16 years for up to six 550 megawatt natural gas-fired Orion
technology electric power plants. The first of the planned six facilities is
currently under construction in Jackson, Michigan. ▇▇▇▇▇▇▇▇ will supply all
natural gas to and purchase all power from the power plant under a 16-year
tolling agreement with a project company in which ▇▇▇▇▇▇ ▇▇▇▇▇▇ Power will have
a preferred investment. ▇▇▇▇▇▇ ▇▇▇▇▇▇ Power is the general contractor for the
▇▇▇▇▇▇▇ power plant and will operate the plant, which is expected to begin
commercial operation in July 2002. Sites for the remainder of the six plants
must be mutually agreed upon between ▇▇▇▇▇▇ ▇▇▇▇▇▇ Power and ▇▇▇▇▇▇▇▇. One
additional site has been agreed upon, but commencement of construction is
subject to permits that have not yet been obtained. No assurance can be given
that ▇▇▇▇▇▇ ▇▇▇▇▇▇ Power and ▇▇▇▇▇▇▇▇ will agree on additional sites or that
necessary permits will be obtained for additional power plants beyond the
initial plant already under construction in Jackson, Michigan.
Competition: ▇▇▇▇▇▇ ▇▇▇▇▇▇ Power's competitors are other companies that
develop power projects. This competition takes the form of competing for a
limited number of potential projects and sites and can be based on pricing,
length of construction period or other terms and conditions. With respect to the
power facilities ▇▇▇▇▇▇ ▇▇▇▇▇▇ Power owns, the output is currently sold under
"qualifying facilities" arrangements with the local utilities. For the power
plants we develop for others, we are not responsible for purchasing the fuel or
marketing the power being generated. Utilities and power marketers are the
customers of power developers. ▇▇▇▇▇▇ ▇▇▇▇▇▇ Power has developed a proprietary
"Orion" design that is targeted for a niche application in the intermediate
electric power market. Currently, other technologies are used for the majority
of the natural gas-fired power plants being developed.
REGULATION
INTERSTATE TRANSPORTATION AND STORAGE SERVICES
Under the Natural Gas Act and, to a lesser extent, the Natural Gas Policy
Act, the Federal Energy Regulatory Commission regulates both the performance of
interstate transportation and storage services by interstate natural gas
pipeline companies, and the rates charged for such services. As used in this
report, FERC refers to the Federal Energy Regulatory Commission.
With the adoption of FERC Order No. 636, the FERC required interstate
natural gas pipelines that perform open access transportation under blanket
certificates to "unbundle" or separate their traditional merchant sales services
from their transportation and storage services and to provide comparable
transportation and storage services with respect to all natural gas supplies,
whether such natural gas is purchased from the pipeline or from other merchants
such as marketers or producers. Each interstate natural gas pipeline must now
separately state the applicable rates for each unbundled service. Order 636 has
been affirmed in all material respects upon judicial review and Natural Gas
Pipeline Company of America's own FERC orders approving its unbundling plans are
final and not subject to any pending judicial review.
Natural Gas Pipeline Company of America had a number of gas purchase
contracts that required Natural Gas Pipeline Company of America to purchase
natural gas at prices in excess of the prevailing market price. As a result of
Order 636 prohibiting interstate natural gas pipelines from using their natural
gas transportation and storage facilities to market natural gas to sales
customers, Natural Gas Pipeline Company of America lost its sales market for the
gas it was required to purchase under these contracts. Order 636 went into
effect on Natural Gas Pipeline Company of America's system on December 1, 1993.
Natural Gas Pipeline Company of America agreed to pay substantial transition
costs to reform these contracts with the natural gas suppliers. Under settlement
agreements between Natural Gas Pipeline Company of America and its former sales
customers, Natural Gas Pipeline Company of America recovered from these
customers a significant amount of the natural gas supply realignment costs over
a four-year period beginning December 1, 1993. These settlement agreements were
approved by the FERC.
9
The FERC also permitted Natural Gas Pipeline Company of America to implement a
tariff mechanism to recover additional portions of its natural gas supply
realignment costs in rates charged to transportation customers that were not
party to the settlements. On December 1, 1997, the FERC allowed recovery of
natural gas supply realignment costs initially allocated to interruptible
transportation but not recovered. Effective December 1, 1998, the FERC allowed
Natural Gas Pipeline Company of America to recover its remaining natural gas
supply realignment costs over the period from December 1, 1998 through November
30, 2001. On October 22, 2001, in Docket No. RP02-22, Natural Gas Pipeline
Company of America filed revised tariff sheets eliminating the surcharges for
natural gas supply realignment costs applicable to its services. On November 28,
2001, the FERC accepted the revised tariff sheets effective December 1, 2001, as
proposed.
We are also subject to the requirements of FERC Order Nos. 497, et seq.,
and 566, et. seq., the Marketing Affiliate Rules, which prohibit preferential
treatment by an interstate natural gas pipeline of its marketing affiliates and
govern, in particular, the provision of information by an interstate natural gas
pipeline to its marketing affiliates. On September 27, 2001 the FERC issued a
Notice of Proposed Rulemaking in Docket No. RM01-10 in which it proposed new
rules governing the interaction between an interstate gas pipeline and its
affiliates. If adopted as proposed, the Notice of Proposed Rulemaking could be
read to limit communication between Natural Gas Pipeline Company of America and
its affiliates. The Notice could also be read to require separate staffing of
Natural Gas Pipeline Company of America and its affiliates, which, if applied,
could significantly increase costs for these functions. On December 20, 2001,
Natural Gas Pipeline Company of America and ▇▇▇▇▇▇ ▇▇▇▇▇▇ Interstate Gas
Transmission LLC, as well as numerous other parties, jointly submitted their
comments on the Notice of Proposed Rulemaking. The FERC to date has not acted on
the proposal.
INTRASTATE TRANSPORTATION AND SALES
The operations of our intrastate pipelines are affected by FERC rules and
regulations issued pursuant to the Natural Gas Act and the Natural Gas Policy
Act. Of particular importance are regulations that allow increased access to
interstate transportation services, without the necessity of obtaining prior
FERC authorization for each transaction. A key element of the program is
nondiscriminatory access, under which a regulated pipeline must agree, under
certain conditions, to transport natural gas for any party requesting such
service.
Our intrastate pipeline in Colorado, Rocky Mountain Natural Gas Company, is
regulated by the Colorado Public Utilities Commission as a public utility in
regard to its natural gas transportation and sales services within the state.
Rocky Mountain also performs certain natural gas transportation services in
interstate commerce pursuant to Section 311 of the Natural Gas Policy Act of
1978. The Colorado Public Utilities Commission regulates the rates, terms, and
conditions of natural gas sales and transportation services performed by public
utilities in the state of Colorado.
Our intrastate pipeline in Wyoming, Northern Gas Company, is regulated by
the Wyoming Public Service Commission as a public utility in regard to its
natural gas transportation and sales services within the state. Northern Gas
also performs certain natural gas transportation services in interstate commerce
pursuant to Section 311 of the Natural Gas Policy Act of 1978. The Wyoming
Public Service Commission regulates the rates, terms, and conditions of natural
gas sales and transportation services performed by public utilities in the state
of Wyoming. On April 20, 2001, we filed an application with the Wyoming Public
Service Commission to reorganize our Wyoming natural gas utility operations by
merging Northern Gas Company into ▇▇▇▇▇▇ ▇▇▇▇▇▇, Inc. Northern Gas Company
presently serves ▇▇▇▇▇▇ ▇▇▇▇▇▇, Inc.'s natural gas distribution system in
central Wyoming, and if the application is approved, Northern Gas Company's
pipelines will be conveyed to ▇▇▇▇▇▇ ▇▇▇▇▇▇, Inc. and thereafter be operated as
part of our natural gas distribution system in Wyoming in order to streamline
operation of the two systems and facilitate expansion of the Choice Gas Program.
10
RETAIL NATURAL GAS DISTRIBUTION SERVICES
Our intrastate pipelines, storage, distribution and/or retail sales in
Colorado and Wyoming are under the regulatory authority of those state's utility
commission. In Nebraska, retail natural gas sales rates for residential and
small commercial customers are regulated by the municipality served.
In certain of the incorporated communities in which we provide retail
natural gas services, we operate under franchises granted by the applicable
municipal authorities. The duration of these franchises varies. In
unincorporated areas, our natural gas utility services are not subject to
municipal franchise. We have been issued various certificates of public
convenience and necessity by the regulatory commissions in Colorado and Wyoming
authorizing us to provide natural gas utility services within certain
incorporated and unincorporated areas of those states.
We emerged as a leader in providing for customer choice in early 1996, when
the Wyoming Public Service Commission issued an order allowing us to bring
competition to 10,500 residential and commercial customers. In November 1997, we
announced a similar plan to give residential and small commercial customers in
Nebraska a choice of natural gas suppliers. This program, the Nebraska Choice
Gas program, became effective June 1, 1998. As of December 31, 2001, the plan
had been adopted by 178 of 181 communities, representing approximately 91,000
customers served by us in Nebraska. On April 20, 2001, we filed an application
with the Wyoming Public Service Commission to expand Choice Gas to cover all of
our Wyoming customers. A Stipulation and Agreement calling for approval of
expansion of the Choice Gas Program has been presented to the Wyoming Public
Service Commission for its consideration. The programs have succeeded in
providing a choice of suppliers, competitive prices, and new products and
services, while maintaining reliability and security of supply. ▇▇▇▇▇▇ ▇▇▇▇▇▇
Retail continues to provide all services other than the commodity supply in
these programs, and competes with other suppliers in offering nonregulated
natural gas supplies to retail customers.
ENVIRONMENTAL REGULATION
Our operations and properties are subject to extensive and evolving
federal, state and local laws and regulations governing the release or discharge
of regulated materials into the environment or otherwise relating to
environmental protection or human health and safety. Numerous governmental
departments issue rules and regulations to implement and enforce such laws,
which are often costly to comply with and onerous, and which carry substantial
administrative, civil and criminal penalties for failure to comply. These laws
and regulations can also impose liability for remedial costs on the owner or
operator of properties or the generators of waste materials, regardless of
fault. Moreover, the recent trends toward stricter standards in environmental
legislation and regulation are likely to continue.
We had an established environmental reserve at December 31, 2001 of
approximately $18 million, excluding any cost of remediation described below, to
address remediation issues associated with approximately 35 projects. After
consideration of reserves established, we believe that costs for environmental
remediation and ongoing compliance with these regulations will not have a
material adverse effect on our cash flows, financial position or results of
operations or diminish our ability to operate our businesses. However, there can
be no assurances that future events, such as changes in existing laws, the
promulgation of new laws, or the development of new facts or conditions will not
cause us to incur significant unanticipated costs.
11
RISK FACTORS
- For 2001, approximately 40% of our income before interest and income
taxes was attributable to our general and limited partner interests in
▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners. A significant decline in ▇▇▇▇▇▇ ▇▇▇▇▇▇
Energy Partners' earnings and/or cash distributions would have a
corresponding negative impact on us. For more information on the earnings
and cash distributions, please see ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners' 2001
Annual Report on Form 10-K.
- For 2001, approximately 56% of our income before interest and income
taxes was attributable to the results of operations of Natural Gas
Pipeline Company of America, an interstate pipeline that is a major
supplier to the Chicago, Illinois area. In recent periods, interstate
pipeline competitors of Natural Gas Pipeline Company of America have
constructed or expanded pipeline capacity into the Chicago area, although
additional take-away capacity has also been constructed. To the extent
that an excess of supply into this market area is created and persists,
Natural Gas Pipeline Company of America's ability to recontract for
expiring transportation capacity at favorable rates could be impaired.
- At December 31, 2001, we had approximately $1.6 billion of debt subject
to floating interest rates. Should interest rates increase significantly,
our earnings would be adversely affected.
- While there are currently no material proceedings challenging the rates
on any of our pipeline systems, shippers on these pipelines do have
rights to challenge the rates we charge under certain circumstances
prescribed by applicable regulations. We can provide no assurance that we
will not face challenges to the rates we receive on our pipeline systems
in the future.
- Weather-related factors such as temperature and rainfall at certain times
of the year affect our earnings in our natural gas transportation and
retail natural gas distribution businesses. While we mitigate this impact
through hedging programs and our interstate pipelines collect the
majority of their transportation revenues through charges that are
collected regardless of actual volumes transported, sustained periods of
temperatures and rainfall that differ from normal can create volatility
in our earnings.
- Our short term liquidity could be impaired in the event the number of
shares of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Management surrendered for exchange exceeds by a
significant amount the number of common units of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy
Partners owned by us. ▇▇▇▇▇▇ ▇▇▇▇▇▇ Management shareholders have the
option to exchange ▇▇▇▇▇▇ ▇▇▇▇▇▇ Management shares for common units of
▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners owned by us, or at our election, cash. If
the volume of exchanges exceeds the number of units we own, to the extent
of the excess we will need to pay cash for the surrendered shares or buy
common units on the open market to exchange for the shares. This need to
raise cash could impact our liquidity on a short term basis. For more
information on this exchange feature, please see Note 2 to our Financial
Statements.
- On September 27, 2001, FERC issued a Notice of Proposed Rulemaking in
Docket No. RM01-10. The proposed rule would expand FERC's current
standards of conduct to include a regulated transmission provider and all
of its energy affiliates. It is not known whether FERC will issue a final
rule in this docket and, if it does, whether the company could as a
result incur increased costs and increased difficulty in its operations.
- Environmental regulation could result in increased operating and capital
costs for us. Our business operations are subject to federal, state and
local laws and regulations relating to environmental protection. If an
accidental leak or spill occurs from our pipelines or at our storage or
other facilities, we may have to pay a significant amount to clean up the
leak or spill. The resulting costs and liabilities could negatively
affect our level of earnings and cash flow. In addition, emission
controls required under federal and state environmental laws could
require significant capital expenditures at our facilities. The impact of
Environmental Protection Agency standards or future environmental
measures on us could increase our costs significantly if environmental
laws and
12
regulations become stricter. Since the costs of environmental regulation
are already significant, additional regulation could negatively affect
our business.
OTHER
Amounts we spent during 2001, 2000, and 1999 on research and development
activities were not material. We employed 4,937 people at December 31, 2001,
including employees of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Services, LLC who are dedicated to the
operations of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners.
We are of the opinion that we generally have satisfactory title to the
properties owned and used in our businesses, subject to the liens for current
taxes, liens incidental to minor encumbrances, and easements and restrictions
which do not materially detract from the value of such property or the interests
therein or the use of the properties in our businesses. We generally do not own
the land on which our pipelines are constructed. Instead, we obtain the right to
construct and operate the pipelines on other people's land for a period of time.
(D) FINANCIAL INFORMATION ABOUT GEOGRAPHIC AREAS
All but an insignificant amount of our assets and operations are located in
the continental United States of America.
ITEM 3. LEGAL PROCEEDINGS.
K N TransColorado, Inc. v. TransColorado Gas Transmission Company, et. al,
Case ▇▇. ▇▇-▇▇-▇▇▇, ▇▇▇▇▇▇▇▇ ▇▇▇▇▇, ▇▇▇▇▇▇ ▇▇ ▇▇▇▇▇▇▇▇, ▇▇▇▇▇ of Colorado. On
June 15, 2000, K N TransColorado filed suit against Questar TransColorado, its
parent Questar Pipeline Company, and other affiliated Questar entities,
asserting claims for breach of fiduciary duties, breach of contract,
constructive trust, rescission of the partnership agreement, breach of good
faith and fair dealing, tortious concealment, misrepresentation, aiding and
abetting a breach of fiduciary duty, dissolution of the TransColorado
partnership, and seeking a declaratory judgment, among other claims. The
TransColorado partnership has been made a defendant for purposes of an
accounting. The lawsuit alleges, among other things, Questar breached its
fiduciary duties as a partner. K N TransColorado seeks to recover damages in
excess of $152 million due to Questar's breaches and, in addition, seeks
punitive damages. In response to the complaint, on July 28, 2000, the Questar
entities filed a counterclaim and third party claims against ▇▇▇▇▇▇ ▇▇▇▇▇▇ and
certain of its affiliates for claims arising out of the construction and
operation of the TransColorado pipeline project. The claims allege, among other
things, that the ▇▇▇▇▇▇ ▇▇▇▇▇▇ entities interfered with and delayed construction
of the pipeline and made misrepresentations about marketing of capacity. The
Questar entities seek to recover damages in excess of $185 million for an
alleged breach of fiduciary duty and other claims. The parties agreed to stay
the exercise of a contractual provision purportedly requiring K N TransColorado
to purchase Questar's interest in the pipeline and to investigate the
appointment of an independent operator for the pipeline during the litigation.
The Court dismissed Questar's counterclaims for breach of duty of good faith and
fair dealing and for indemnity and contribution and dismissed Questar's Third
Party Complaint. On July 19, 2001, the Court granted K N TransColorado's motion
for summary judgment that: a) fiduciary duties existed between the partners; b)
these fiduciary duties were not modified or waived; and c) the affiliates and
directors of Questar Pipeline Company and Questar TransColorado acting in their
dual capacity had fiduciary obligations which required those individuals to
disclose, to the partnership and the partners, information that affected the
fundamental business purpose of the partnership. On August 14, 2001, the Court
granted leave to Questar to file its First Amended Answer and Counterclaim, once
again naming ▇▇▇▇▇▇ ▇▇▇▇▇▇, Inc. as a counterclaim defendant, and making similar
allegations against us as set forth above. Fact discovery and expert discovery
have closed. The case is set for trial on April 1, 2002.
▇▇▇▇ ▇. ▇▇▇▇▇▇▇▇, individually and as general partner for the Greater Green
River Basin Drilling Program: 72-73 v. Rocky Mountain Natural Gas Company and K
N Energy, Inc., Case No. 90-CV-3686. On June 5, 1990, ▇▇▇▇ ▇. ▇▇▇▇▇▇▇▇ filed
suit, which is presently pending in Jefferson County District Court for
Colorado, against Rocky Mountain Natural Gas Company and us alleging breach of
contract
13
and fraud. In essence, Grynberg asserts claims that the named companies failed
to pay Grynberg the proper price, impeded the flow of natural gas, mismeasured
natural gas, delayed his development of natural gas reserves, and other claims
arising out of a contract to purchase natural gas from a field in northwest
Colorado. On February 13, 1997, the trial judge entered partial summary judgment
for Grynberg on his contract claim that he failed to receive the proper price
for his natural gas. This ruling followed an appellate decision that was adverse
to us on the contract interpretation of the price issue, but which did not
address the question of whether Grynberg could legally receive the price he
claimed or whether he had illegally diverted natural gas from a prior purchase.
Grynberg has previously claimed damages in excess of $30 million. On August 29,
1997, the trial judge stayed the summary judgment pending resolution of a
proceeding at the FERC to determine if Grynberg was entitled to administrative
relief from an earlier dedication of the same natural gas to interstate
commerce. On March 15, 1999, an Administrative Law Judge for the FERC ruled,
after an evidentiary hearing, that ▇▇. ▇▇▇▇▇▇▇▇ had illegally diverted the
natural gas when he entered the contract with the named companies and was not
entitled to relief. Grynberg filed exceptions to this ruling. In late March
2000, the FERC issued an order affirming in part and denying in part the motions
for rehearing of its Initial Decision. On November 21, 2000, the FERC upheld the
Administrative Law Judge's factual findings and denial of retroactive
abandonment. On June 14, 2001, Rocky Mountain Natural Gas Company filed a motion
for Summary Judgment and To Vacate the February 13, 1997, Partial Summary
Judgment, as a result of the conclusion of the FERC proceedings. On August 16,
2001, the Court granted Plaintiff's Motion to Continue the Stay of these
proceedings pending the proceedings in federal court. The parties have reached a
settlement in principle of this matter and the federal court matter. The
settlement is conditioned on certain findings by a Special Master.
▇▇▇▇ ▇. ▇▇▇▇▇▇▇▇ v. K N Energy, Inc., Rocky Mountain Natural Gas Company,
and GASCO, Inc., Civil Action No. 92-N-2000. On October 9, 1992, ▇▇▇▇ ▇.
▇▇▇▇▇▇▇▇ filed suit in the United States District Court for the District of
Colorado against us, Rocky Mountain Natural Gas Company and GASCO, Inc. alleging
that these entities, the K N Entities, as well as K N Production Company and K N
Gas Gathering, Inc., have violated federal and state antitrust laws. In essence,
Grynberg asserts that the companies have engaged in an illegal exercise of
monopoly power, have illegally denied him economically feasible access to
essential facilities to store, transport and distribute gas, and illegally have
attempted to monopolize or to enhance or maintain an existing monopoly. Grynberg
also asserts certain state causes of action relating to a gas purchase contract.
In February 1999, the Federal District Court granted summary judgment for the K
N Entities as to some of Grynberg's antitrust and state law claims, while
allowing other claims to proceed to trial. Grynberg has previously claimed
damages in excess of $50 million. In addition to monetary damages, Grynberg has
requested that the K N Entities be ordered to divest all interests in natural
gas exploration, development and production properties, all interests in
distribution and marketing operations, and all interests in natural gas storage
facilities, in order to separate these interests from our natural gas gathering
and transportation system in northwest Colorado. The parties have reached a
settlement in principle of this matter and the state court matter. The court has
ordered that the settlement be finalized by March 15, 2002, or the federal case
will proceed to trial. The settlement is conditioned on certain findings by a
Special Master.
United States of America, ex rel., ▇▇▇▇ ▇. ▇▇▇▇▇▇▇▇ v. K N Energy, Civil
Action No. 97-D-1233, filed in the U.S. District Court, District of Colorado.
This action was filed on June 9, 1997 pursuant to the federal False Claim Act
and involves allegations of mismeasurement of natural gas produced from federal
and Indian lands. The Department of Justice has decided not to intervene in
support of the action. The complaint is part of a larger series of similar
complaints filed by ▇▇. ▇▇▇▇▇▇▇▇ against 77 natural gas pipelines (approximately
330 other defendants). An earlier single action making substantially similar
allegations against the pipeline industry was dismissed by Judge ▇▇▇▇▇ of the
U.S. District Court for the District of Columbia on grounds of improper joinder
and lack of jurisdiction. As a result, ▇▇. ▇▇▇▇▇▇▇▇ filed individual complaints
in various courts throughout the country. These cases were recently consolidated
by the Judicial Panel for Multidistrict Litigation, and transferred to the
District of Wyoming. Motions to Dismiss were filed and an oral argument on the
Motion to Dismiss occurred on March 17, 2000. On July 20, 2000 the United States
of America filed a motion to dismiss those claims by Grynberg that deal
14
with the manner in which defendants valued gas produced from federal leases.
Judge ▇▇▇▇▇▇ denied the defendant's motion to dismiss on May 18, 2001. The
defendants have sought reconsideration of this Order and have requested a status
conference.
Quinque Operating Company, et. al. v. Gas Pipelines, et. al., Cause No.
▇▇-▇▇▇▇-▇▇, ▇▇▇▇▇▇ ▇▇▇▇▇▇ District Court for the District of Kansas. This action
was originally filed on May 28, 1999 in Kansas state court in ▇▇▇▇▇▇▇ County,
Kansas as a class action against approximately 245 pipeline companies and their
affiliates, including certain ▇▇▇▇▇▇ ▇▇▇▇▇▇ entities. The plaintiffs in the case
seek to have the Court certify the case as a class action, a class of natural
gas producers and fee royalty owners who allege that they have been subject to
systematic mismeasurement of natural gas by the defendants for more than 25
years. Among other things, the plaintiffs allege a conspiracy among the pipeline
industry to under-measure gas and have asserted joint and several liability
against the defendants. Subsequently, one of the defendants removed the action
to Kansas Federal District Court. Thereafter, we filed a motion with the
Judicial Panel for Multidistrict Litigation to consolidate this action for
pretrial purposes with the Grynberg False Claim Act cases referred to above,
because of common factual questions. On April 10, 2000, the Judicial Panel for
Multidistrict Litigation ordered that this case be consolidated with the
Grynberg federal False Claims Act cases. On January 12, 2001, the Federal
District Court of Wyoming issued an oral ruling remanding the case back to the
State Court in ▇▇▇▇▇▇▇ County, Kansas. A case management conference occurred in
State Court in ▇▇▇▇▇▇▇ County, and a briefing schedule was established for
preliminary matters. Personal jurisdiction discovery has commenced. Merits
discovery has been stayed. Recently, the defendants filed a motion to dismiss on
grounds other than personal jurisdiction, and a motion to dismiss for lack of
personal jurisdiction for non-resident defendants.
K N Energy, Inc., et al. v. ▇▇▇▇▇ ▇. ▇▇▇▇ and ▇▇▇▇▇▇▇ ▇. ▇▇▇▇▇▇▇▇, Case No.
99CV1239, filed in the District Court, Jefferson County, Division 8, Colorado.
The case was filed on May 21, 1999. Defendants counterclaimed and filed third
party claims against several of our former officers and/or directors. Messrs.
Rode and McDonald are former principal shareholders of Interenergy Corporation.
We acquired Interenergy on December 19, 1997 pursuant to a Merger Agreement
dated August 25, 1997. Rode and McDonald allege that K N Energy committed
securities fraud, common law fraud and negligent misrepresentation as well as
breach in contract. Plaintiffs are seeking an unspecified amount of compensatory
damages, greater than $2 million, plus unspecified exemplary or punitive
damages, attorney's fees and their costs. We filed a motion to dismiss, and on
April 21, 2000, the Jefferson County District Court Judge dismissed the case
against the individuals and us with prejudice. On April 6, 2001, the Colorado
Court of Appeals affirmed the dismissal. Defendants also filed a federal
securities fraud action in the United States District Court for the District of
Colorado on January 27, 2000 titled: ▇▇▇▇▇ ▇. ▇▇▇▇ and ▇▇▇▇▇▇▇ ▇. ▇▇▇▇▇▇▇▇ v. K
N Energy, Inc., et al., Civil Action No. 00-N-190. This case initially raised
the identical state law claims contained in the counterclaim and third party
complaint in state court. Rode and McDonald filed an amended Complaint, which
dropped the state-law claims. On June 20, ▇▇▇▇, ▇▇▇ ▇▇▇▇▇▇▇ ▇▇▇▇▇▇▇▇ ▇▇▇▇▇
dismissed this Complaint with prejudice. Rode and McDonald filed notices of
appeal of the federal court dismissal. Briefing on this appeal is complete. A
third related class action case styled, ▇▇▇▇▇ vs. ▇▇▇▇▇▇ ▇▇▇▇▇▇, Inc., et. al.,
Civil Action No. 00-M-516, in the United States District Court for the District
of Colorado was served on us on April 10, 2000. As of this date no class has
been certified. On February 23, 2001, the federal district court dismissed
several claims raised by the plaintiff, with prejudice, and dismissed the
remaining claims, without prejudice. On April 27, 2001, the ▇▇▇▇▇ plaintiffs
filed their second amended complaint. We have moved to dismiss this complaint
and the briefing on the motion is complete. An oral argument on the motion to
dismiss is set for March 29, 2002.
We believe that we have meritorious defenses to all lawsuits and legal
proceedings in which we are defendants and will vigorously defend against them.
Based on our evaluation of the above matters, and after consideration of
reserves established, we believe that the resolution of such matters will not
have a material adverse effect on our businesses, cash flows, financial position
or results of operations.
15
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None
EXECUTIVE OFFICERS OF THE REGISTRANT
(A) IDENTIFICATION AND BUSINESS EXPERIENCE OF EXECUTIVE OFFICERS
Set forth below is certain information concerning our executive officers.
All officers serve at the discretion of our board of directors.
NAME AGE POSITION
---- --- --------
▇▇▇▇▇▇▇ ▇. ▇▇▇▇▇▇.................... 57 Director, Chairman and Chief Executive Officer
▇▇▇▇▇▇▇ ▇. ▇▇▇▇▇▇.................... 58 Director and Vice Chairman
▇▇▇▇▇▇▇ ▇. ▇▇▇▇▇▇.................... 33 President
▇▇▇▇▇▇▇ ▇. ▇▇▇▇▇▇▇................... 54 President, Natural Gas Pipelines
▇▇▇▇▇ ▇. ▇▇▇▇▇▇▇▇▇, ▇▇. ............. 41 Vice President, Corporate Development
▇▇▇▇▇▇ ▇▇▇▇▇▇▇▇▇▇.................... 33 Vice President, General Counsel and Secretary
C. Park Shaper....................... 33 Vice President, Treasurer and Chief Financial
Officer
▇▇▇▇▇ ▇. Street...................... 45 Vice President, Human Resources and
Administration
▇▇▇▇▇▇▇ ▇. ▇▇▇▇▇▇ is Director, Chairman and Chief Executive Officer of
▇▇▇▇▇▇ ▇▇▇▇▇▇, Inc., ▇▇▇▇▇▇ ▇▇▇▇▇▇ Management, LLC and Kinder ▇▇▇▇▇▇ ▇.▇., Inc.
▇▇. ▇▇▇▇▇▇ has served as Director, Chairman and Chief Executive Officer of
▇▇▇▇▇▇ ▇▇▇▇▇▇ Management, LLC since its formation in February 2001. He was
elected Director, Chairman and Chief Executive Officer of ▇▇▇▇▇▇ ▇▇▇▇▇▇, Inc. in
October 1999. He was elected Director, Chairman and Chief Executive Officer of
Kinder ▇▇▇▇▇▇ ▇.▇., Inc. in February 1997. ▇▇. ▇▇▇▇▇▇ is also a director of
TransOcean Offshore Inc. and ▇▇▇▇▇ ▇▇▇▇▇▇ Incorporated.
▇▇▇▇▇▇▇ ▇. ▇▇▇▇▇▇ is Director and Vice Chairman of ▇▇▇▇▇▇ ▇▇▇▇▇▇, Inc.,
▇▇▇▇▇▇ ▇▇▇▇▇▇ Management, LLC and Kinder ▇▇▇▇▇▇ ▇.▇., Inc. ▇▇. ▇▇▇▇▇▇ served as
the President of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Management, LLC from February 2001 to July 2001.
He served as President of ▇▇▇▇▇▇ ▇▇▇▇▇▇, Inc. from October 1999 to July 2001. He
served as President of Kinder ▇▇▇▇▇▇ ▇.▇., Inc. from February 2001 to July 2001.
▇▇. ▇▇▇▇▇▇ has served as Director and Vice Chairman of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Management,
LLC since its formation in February 2001. ▇▇. ▇▇▇▇▇▇ has served as Director and
Vice Chairman of ▇▇▇▇▇▇ ▇▇▇▇▇▇, Inc. since October 1999. ▇▇. ▇▇▇▇▇▇ was elected
Vice Chairman of Kinder ▇▇▇▇▇▇ ▇.▇., Inc. in February 1997. He served as
President of ▇▇▇▇▇▇ Holdings Corporation, a pipeline investment company, from
October 1992 through March 2000. On January 17, 2002, we announced that ▇▇.
▇▇▇▇▇▇ would transition to a non-executive role in April 2003. At that time, ▇▇.
▇▇▇▇▇▇ will retain his Vice Chairman title and remain an active board member,
but he will be less involved in our day-to-day operations. ▇▇. ▇▇▇▇▇▇ is the
father of ▇▇▇▇▇▇▇ ▇. ▇▇▇▇▇▇, President of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Management, LLC, Kinder
▇▇▇▇▇▇ ▇.▇., Inc., and ▇▇▇▇▇▇ ▇▇▇▇▇▇, Inc.
▇▇▇▇▇▇▇ ▇. ▇▇▇▇▇▇ is President of ▇▇▇▇▇▇ ▇▇▇▇▇▇, Inc., ▇▇▇▇▇▇ ▇▇▇▇▇▇
Management, LLC and Kinder ▇▇▇▇▇▇ ▇.▇., Inc. ▇▇. ▇▇▇▇▇▇ was elected to each of
these positions in July 2001. ▇▇. ▇▇▇▇▇▇ served as Vice President, Strategy and
Investor Relations of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Management, LLC from February 2001 to July
2001. He served as Vice President, Strategy and Investor Relations of ▇▇▇▇▇▇
▇▇▇▇▇▇, Inc. and Kinder ▇▇▇▇▇▇ ▇.▇., Inc. from January 2000 to July 2001. He
served as Vice President, Corporate Development of Kinder ▇▇▇▇▇▇ ▇.▇., Inc. from
February 1997 to January 2000. ▇▇. ▇▇▇▇▇▇ was the Vice President, Corporate
Development of ▇▇▇▇▇▇ ▇▇▇▇▇▇, Inc. from October 1999 to January 2000. From
August 1995 until February 1997, ▇▇. ▇▇▇▇▇▇ was an associate with McKinsey &
Company, an international management consulting firm. In 1995, ▇▇. ▇▇▇▇▇▇
received a Masters in Business Administration from the Harvard Business School.
From March 1991 to June 1993, ▇▇. ▇▇▇▇▇▇ held various positions, including
Assistant to the Chairman, at PSI Energy, Inc., an electric utility. ▇▇. ▇▇▇▇▇▇
received a Bachelor of Arts in Economics and a Masters of Arts in Sociology from
Stanford University in 1990. ▇▇. ▇▇▇▇▇▇ is the son of ▇▇▇▇▇▇▇ ▇. ▇▇▇▇▇▇.
16
▇▇▇▇▇▇▇ ▇. ▇▇▇▇▇▇▇ is President, Natural Gas Pipelines of ▇▇▇▇▇▇ ▇▇▇▇▇▇,
Inc., ▇▇▇▇▇▇ ▇▇▇▇▇▇ Management, LLC and Kinder ▇▇▇▇▇▇ ▇.▇., Inc. ▇▇. ▇▇▇▇▇▇▇ was
elected President, Natural Gas Pipelines of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Management, LLC upon
its formation in February 2001. He was elected President, Natural Gas Pipelines
of Kinder ▇▇▇▇▇▇ ▇.▇., Inc. and ▇▇▇▇▇▇ ▇▇▇▇▇▇, Inc. in September 1999. He was
President, Pipeline Operations of Kinder ▇▇▇▇▇▇ ▇.▇., Inc. from February 1999 to
September 1999. ▇▇. ▇▇▇▇▇▇▇ served as Vice President and General Counsel of
Kinder ▇▇▇▇▇▇ ▇.▇., Inc. from April 1998 to February 1999. From May 1997 to
April 1998, ▇▇. ▇▇▇▇▇▇▇ managed his personal investments. From April 1996
through May 1997, ▇▇. ▇▇▇▇▇▇▇ served as President of Enron Liquid Services
Corporation. On February 8, 2002, we announced that ▇▇. ▇▇▇▇▇▇▇ will retire
effective June 1, 2002.
▇▇▇▇▇ ▇. ▇▇▇▇▇▇▇▇▇, ▇▇. is Vice President, Corporate Development of ▇▇▇▇▇▇
▇▇▇▇▇▇, Inc., ▇▇▇▇▇▇ ▇▇▇▇▇▇ Management, LLC and Kinder ▇▇▇▇▇▇ ▇.▇., Inc. ▇▇.
▇▇▇▇▇▇▇▇▇ was elected Vice President, Corporate Development of ▇▇▇▇▇▇ ▇▇▇▇▇▇
Management, LLC upon its formation in February 2001. ▇▇. ▇▇▇▇▇▇▇▇▇ was elected
Vice President, Corporate Development of Kinder ▇▇▇▇▇▇ ▇.▇., Inc. and ▇▇▇▇▇▇
▇▇▇▇▇▇, Inc. in January 2000. He served as Vice President and Chief Financial
Officer of ▇▇▇▇▇▇ ▇▇▇▇▇▇, Inc. from October 1999 to January 2000. He served as
Vice President and Chief Financial Officer of Kinder ▇▇▇▇▇▇ ▇.▇., Inc. from July
1997 to January 2000 and Treasurer of Kinder ▇▇▇▇▇▇ ▇.▇., Inc. from February
1997 to January 2000. He served as Secretary of Kinder ▇▇▇▇▇▇ ▇.▇., Inc. from
February 1997 to August 1997. ▇▇. ▇▇▇▇▇▇▇▇▇ was previously employed by the
national CPA firms of Ernst & Whinney and ▇▇▇▇▇▇ ▇▇▇▇▇. ▇▇. ▇▇▇▇▇▇▇▇▇ received
his law degree from the University of Missouri-Kansas City and is a member of
the Missouri Bar. He is also a CPA and received his undergraduate Accounting
degree from ▇▇▇▇▇▇▇▇▇ University in Omaha, Nebraska.
▇▇▇▇▇▇ ▇▇▇▇▇▇▇▇▇▇ is Vice President, General Counsel and Secretary of
▇▇▇▇▇▇ ▇▇▇▇▇▇, Inc., ▇▇▇▇▇▇ ▇▇▇▇▇▇ Management, LLC and Kinder ▇▇▇▇▇▇ ▇.▇., Inc.
▇▇. ▇▇▇▇▇▇▇▇▇▇ was elected Vice President, General Counsel and Secretary of
▇▇▇▇▇▇ ▇▇▇▇▇▇ Management, LLC upon its formation in February 2001. He was
elected Vice President and General Counsel of Kinder ▇▇▇▇▇▇ ▇.▇., Inc. and Vice
President, General Counsel and Secretary of ▇▇▇▇▇▇ ▇▇▇▇▇▇, Inc. in October 1999.
▇▇. ▇▇▇▇▇▇▇▇▇▇ was elected Secretary of Kinder ▇▇▇▇▇▇ ▇.▇., Inc. in November
1998 and became an employee of Kinder ▇▇▇▇▇▇ ▇.▇., Inc. in March 1998. From
March 1995 through February 1998, ▇▇. ▇▇▇▇▇▇▇▇▇▇ worked as an attorney for
▇▇▇▇▇▇▇▇, ▇▇▇▇▇▇▇ & ▇▇▇▇▇▇▇, a Professional Corporation. ▇▇. ▇▇▇▇▇▇▇▇▇▇ received
his Masters in Business Administration from Boston University in January 1995,
his Juris Doctor, magna cum laude, from Boston University in May 1994, and his
Bachelor of Arts degree in Economics from Stanford University in June 1990.
C. Park Shaper is Vice President, Treasurer and Chief Financial Officer of
▇▇▇▇▇▇ ▇▇▇▇▇▇, Inc., ▇▇▇▇▇▇ ▇▇▇▇▇▇ Management, LLC and Kinder ▇▇▇▇▇▇ ▇.▇., Inc.
Mr. Shaper was elected Vice President, Treasurer and Chief Financial Officer of
▇▇▇▇▇▇ ▇▇▇▇▇▇ Management, LLC upon its formation in February 2001. He has served
as Treasurer of ▇▇▇▇▇▇ ▇▇▇▇▇▇, Inc. since April 2000 and Vice President and
Chief Financial Officer of ▇▇▇▇▇▇ ▇▇▇▇▇▇, Inc. since January 2000. Mr. Shaper
was elected Vice President, Treasurer and Chief Financial Officer of Kinder
▇▇▇▇▇▇ ▇.▇., Inc. in January 2000. From June 1999 to December 1999, Mr. Shaper
was President and Director of Altair Corporation, an enterprise focused on the
distribution of web-based investment research for the financial services
industry. He served as Vice President and Chief Financial Officer of First Data
Analytics, a wholly-owned subsidiary of First Data Corporation, from 1997 to
June 1999. From 1995 to 1997, he was a consultant with The Boston Consulting
Group. He received a Masters of Business Administration degree from the ▇.▇.
▇▇▇▇▇▇▇ Graduate School of Management at Northwestern University. Mr. Shaper
also has a Bachelor of Science degree in Industrial Engineering and a Bachelor
of Arts degree in Quantitative Economics from Stanford University.
▇▇▇▇▇ ▇. Street is Vice President, Human Resources and Administration of
▇▇▇▇▇▇ ▇▇▇▇▇▇, Inc., ▇▇▇▇▇▇ ▇▇▇▇▇▇ Management, LLC and Kinder ▇▇▇▇▇▇ ▇.▇., Inc.
Mr. Street was elected Vice President, Human Resources and Administration of
▇▇▇▇▇▇ ▇▇▇▇▇▇ Management, LLC upon its formation in February 2001. He was
elected Vice President, Human Resources and Administration of ▇▇▇▇▇▇ ▇▇▇▇▇▇
17
G.P., Inc. and ▇▇▇▇▇▇ ▇▇▇▇▇▇, Inc. in August 1999. From October 1996 to August
▇▇▇▇, ▇▇. ▇▇▇▇▇▇ was Senior Vice President, Human Resources and Administration
for Coral Energy, a subsidiary of Shell Oil Company. Mr. Street received a
Masters of Business Administration degree from the University of Nebraska at
Omaha and a Bachelor of Science degree from the University of Nebraska at
▇▇▇▇▇▇▇.
(B) INVOLVEMENT IN CERTAIN LEGAL PROCEEDINGS
None.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S EQUITY AND RELATED SECURITY HOLDER MATTERS.
Our common stock is listed for trading on the New York Stock Exchange under
the symbol KMI. Dividends paid and the price range of our common stock by
quarter for the last two years are provided below.
MARKET PRICE PER SHARE DATA
----------------------------------------
2001 2000
------------------ ------------------
LOW HIGH LOW HIGH
------- ------- ------- -------
Quarter Ended:
March 31.......................................... $42.875 $60.000 $19.875 $34.500
June 30........................................... $50.250 $59.970 $29.188 $34.938
September 30...................................... $46.220 $57.570 $31.625 $41.688
December 31....................................... $46.950 $57.130 $37.063 $54.250
DIVIDENDS PAID PER SHARE
-----------------------------
Quarter Ended:
March 31.......................................... $ 0.05 $0.05
June 30........................................... $ 0.05 $0.05
September 30...................................... $ 0.05 $0.05
December 31....................................... $ 0.05 $0.05
Stockholders of Record as of February 1, 2002....... 32,000 (approximately)
There were no sales of unregistered equity securities during the period
covered by this report.
18
ITEM 6. SELECTED FINANCIAL DATA.
FIVE-YEAR REVIEW
▇▇▇▇▇▇ ▇▇▇▇▇▇, INC. AND SUBSIDIARIES
YEAR ENDED DECEMBER 31,
------------------------------------------------------------
2001 2000 1999(1) 1998(2) 1997
---------- ---------- ---------- ---------- --------
(IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
Operating Revenues.......................... $1,054,918 $2,679,722 $1,836,368 $1,660,259 $340,685
Gas Purchases and Other Costs of Sales...... 339,353 1,926,068 1,050,250 836,614 134,476
---------- ---------- ---------- ---------- --------
Gross Margin................................ 715,565 753,654 786,118 823,645 206,209
Other Operating Expenses.................... 331,246 358,511 490,416 427,953 128,059
---------- ---------- ---------- ---------- --------
OPERATING INCOME............................ 384,319 395,143 295,702 395,692 78,150
Other Income and (Expenses)(3).............. 22,917 (87,977) (81,151) (172,787) (21,039)
---------- ---------- ---------- ---------- --------
Income From Continuing Operations Before
Income Taxes.............................. 407,236 307,166 214,551 222,905 57,111
Income Taxes................................ 168,601 123,017 79,124 82,710 12,777
---------- ---------- ---------- ---------- --------
INCOME FROM CONTINUING OPERATIONS........... 238,635 184,149 135,427 140,195 44,334
Gain (Loss) From Discontinued Operations,
Net of Tax................................ -- (31,734) (395,319) (77,984) 33,163
---------- ---------- ---------- ---------- --------
Income (Loss) Before Extraordinary Item..... 238,635 152,415 (259,892) 62,211 77,497
Extraordinary Item -- Loss on Early
Extinguishment of Debt, Net of Income
Taxes..................................... (13,565) -- -- -- --
---------- ---------- ---------- ---------- --------
NET INCOME (LOSS)........................... 225,070 152,415 (259,892) 62,211 77,497
Less-Preferred Dividends.................... -- -- 129 350 350
Less-Premium Paid on Preferred Stock
Redemption................................ -- -- 350 -- --
---------- ---------- ---------- ---------- --------
EARNINGS (LOSS) AVAILABLE FOR COMMON
STOCK..................................... $ 225,070 $ 152,415 $ (260,371) $ 61,861 $ 77,147
========== ========== ========== ========== ========
BASIC EARNINGS (LOSS) PER COMMON SHARE:
Continuing Operations....................... $ 2.07 $ 1.62 $ 1.68 $ 2.19 $ 0.95
Discontinued Operations..................... -- (0.28) (4.92) (1.22) 0.71
Extraordinary Item -- Loss on Early
Extinguishment of Debt.................... (0.12) -- -- -- --
---------- ---------- ---------- ---------- --------
Total Basic Earnings (Loss) Per Common
Share..................................... $ 1.95 $ 1.34 $ (3.24) $ 0.97 $ 1.66
========== ========== ========== ========== ========
Number of Shares Used in Computing Basic
Earnings (Loss) Per Common Share.......... 115,243 114,063 80,284 64,021 46,589
========== ========== ========== ========== ========
DILUTED EARNINGS (LOSS) PER COMMON SHARE:
Continuing Operations....................... $ 1.97 $ 1.61 $ 1.68 $ 2.17 $ 0.93
Discontinued Operations..................... -- (0.28) (4.92) (1.21) 0.70
Extraordinary Item -- Loss on Early
Extinguishment of Debt.................... (0.11) -- -- -- --
---------- ---------- ---------- ---------- --------
Total Diluted Earnings (Loss) Per Common
Share..................................... $ 1.86 $ 1.33 $ (3.24) $ 0.96 $ 1.63
========== ========== ========== ========== ========
Number of Shares Used in Computing Diluted
Earnings (Loss) Per Common Share.......... 121,326 115,030 80,358 64,636 47,307
========== ========== ========== ========== ========
DIVIDENDS PER COMMON SHARE.................. $ 0.20 $ 0.20 $ 0.65 $ 0.76 $ 0.73
========== ========== ========== ========== ========
CAPITAL EXPENDITURES(4)..................... $ 124,171 $ 85,654 $ 92,841 $ 120,881 $230,814
========== ========== ========== ========== ========
---------------
(1) Reflects the acquisition of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Delaware on October 7, 1999. See
Note 3 of the accompanying Notes to Consolidated Financial Statements.
(2) Reflects the acquisition of MidCon Corp. on January 30, 1998.
(3) Includes significant impacts from sales of assets. See Note 1 (N) of the
accompanying Notes to Consolidated Financial Statements.
(4) Capital Expenditures shown are for continuing operations only.
19
FIVE-YEAR REVIEW (CONTINUED)
▇▇▇▇▇▇ ▇▇▇▇▇▇, INC. AND SUBSIDIARIES
AS OF DECEMBER 31,
------------------------------------------------------------------------------------------------
2001 2000 1999 1998 1997
---------- ---------- ---------- ---------- ----------
(IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
TOTAL ASSETS........... $9,533,085 $8,386,989 $9,393,834 $9,623,779 $2,305,805
========== ========== ========== ========== ==========
CAPITALIZATION:
Common Equity.......... $2,259,997 39% $1,777,624 39% $1,649,615 32% $1,219,043 25% $ 606,132 46%
Preferred Stock........ -- -- -- -- -- -- 7,000 -- 7,000 --
Preferred Capital Trust
Securities........... 275,000 5% 275,000 6% 275,000 5% 275,000 6% 100,000 8%
Minority Interests..... 817,513 14% 4,910 -- 9,523 -- 63,354 1% 47,303 4%
Long-term Debt......... 2,404,967 42% 2,478,983 55% 3,293,326 63% 3,300,025 68% 553,816 42%
---------- --- ---------- --- ---------- --- ---------- --- ---------- ---
Total Capitalization... $5,757,477 100% $4,536,517 100% $5,227,464 100% $4,864,422 100% $1,314,251 100%
========== === ========== === ========== === ========== === ========== ===
BOOK VALUE PER
COMMON SHARE......... $ 18.24 $ 15.53 $ 14.64 $ 17.77 $ 12.63
========== ========== ========== ========== ==========
20
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
GENERAL
In this report, unless the context requires otherwise, references to "we,"
"us," "our," or the "Company" are intended to mean ▇▇▇▇▇▇ ▇▇▇▇▇▇, Inc. (a Kansas
corporation formerly known as K N Energy, Inc.) and its consolidated
subsidiaries. The following discussion should be read in conjunction with the
accompanying Consolidated Financial Statements and related Notes. Specifically,
as discussed in Notes 3, 6 and 7 of the accompanying Notes to Consolidated
Financial Statements, we have engaged in acquisitions (including the October
1999 acquisition of ▇▇▇▇▇▇ ▇▇▇▇▇▇ (Delaware), Inc., the indirect owner of the
general partner interest in ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners, L.P., a publicly
traded master limited partnership, referred to in this report as "▇▇▇▇▇▇ ▇▇▇▇▇▇
Energy Partners"), and divestitures (including the discontinuance of certain
lines of business and the transfer of certain assets to ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy
Partners) that may affect comparisons of financial position and results of
operations between periods.
BUSINESS STRATEGY
On October 7, 1999, we completed the acquisition of ▇▇▇▇▇▇ ▇▇▇▇▇▇
(Delaware), Inc., a Delaware corporation and the sole stockholder of the general
partner of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners. To effect that acquisition, we issued
approximately 41.5 million shares of our common stock in exchange for all of the
outstanding shares of ▇▇▇▇▇▇ ▇▇▇▇▇▇ (Delaware). Upon closing of the transaction,
▇▇▇▇▇▇▇ ▇. ▇▇▇▇▇▇, Chairman and Chief Executive Officer of ▇▇▇▇▇▇ ▇▇▇▇▇▇
(Delaware), was named Chairman and Chief Executive Officer, and we were renamed
▇▇▇▇▇▇ ▇▇▇▇▇▇, Inc.
In accordance with previously announced plans, we implemented and have
continued to pursue our "Back to Basics" strategy. This strategy includes the
following key aspects: (i) focus on fee-based energy transportation and storage
assets that are core to the energy infrastructure of growing markets, (ii)
increase utilization of existing assets while controlling costs, (iii) leverage
economies of scale from incremental acquisitions, (iv) maximize the benefits of
our unique financial structure and (v) continue to align employee and
shareholder incentives.
During 1999, we implemented plans to dispose of our non-core businesses and
as of December 31, 2000, we effectively completed the disposition of these
assets and operations, all as more fully described in Note 7 of the accompanying
Notes to Consolidated Financial Statements. The cash proceeds from these
dispositions were largely used to retire debt, contributing to the reduction in
outstanding indebtedness during 2000.
In addition to sales of non-core assets to third parties, we made
significant transfers of assets to ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners at the end of
1999 and the end of 2000 that, in total, had over $1 billion of fair market
value. By contributing assets to ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners that are
accretive to its earnings and cash flow, we can receive fair market value in the
contribution transaction, while still maintaining an indirect interest in the
earnings and cash flows of the assets through our limited and general partner
interests in ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners. As of December 31, 2001, we owned,
directly, and indirectly in the form of i-units corresponding to the number of
shares of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Management, LLC we own, approximately 31.1 million
limited partner units of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners, representing
approximately 18.7% of the total units outstanding. As a result of our general
and limited partner interests in ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners, at the current
level of distribution including incentive distributions to the general partner,
we currently are entitled to receive approximately 50% of all distributions from
▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners. The actual level of distributions received by us
in the future will vary with the level of distributable cash determined by
▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners' partnership agreement.
After the dispositions discussed above, our remaining businesses constitute
three business segments. Our largest business segment and our primary source of
operating income is Natural Gas Pipeline Company of America (NGPL), which owns
and operates a major interstate natural gas pipeline system
21
that runs from natural gas producing areas in West Texas and the Gulf of Mexico
to its principal market area of Chicago, Illinois. In accordance with our
strategy to increase operational focus on core assets, we have worked toward
renewing existing agreements and entering into new agreements to fully utilize
the transportation and storage capacity of Natural Gas Pipeline Company of
America's system. As a result, Natural Gas Pipeline Company of America sold
virtually all of its capacity through the 2001-2002 winter season. Natural Gas
Pipeline Company of America continues to pursue opportunities to connect its
system to power generation facilities and, in addition, has announced plans to
extend its system into the metropolitan east area of St. Louis anchored by a
contract with Dynegy Marketing and Trade.
Our other business segments consist of the retail distribution of natural
gas to approximately 233,000 customers in Colorado, Wyoming and Nebraska and the
construction and operation of electric power generation facilities. Our retail
natural gas distribution operations are located, in part, in areas where
significant growth is occurring and we expect to participate in that growth
through increased natural gas demand. Our power segment owns and operates power
generation facilities, is currently constructing two power plants for other
parties and may construct additional natural gas-fired electric generation
facilities to help meet the country's growing electric power needs. These power
projects, in addition to generating income in their own right, are expected to
increase Natural Gas Pipeline Company of America's throughput as described
above.
With respect to financial strategy, it is our intention to maintain a
relatively conservative capital structure that provides flexibility and
stability. During 2001, we utilized our significant free cash flow both from
operations and financing activities (principally the November 2001 maturity of
our premium equity participating securities) to reduce debt and to reacquire
approximately $270 million of our common stock (pursuant to a previously
announced $300 million stock buyback program). In early 2002, we announced the
expansion of our stock buyback program to a total of $400 million. At December
31, 2001, our total debt to total capital was approximately 47%, down from over
70% in late 1999, with approximately 50% of our debt subject to floating
interest rates.
We believe that we will continue to benefit from accretive acquisitions and
business expansions, primarily by ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners. ▇▇▇▇▇▇ ▇▇▇▇▇▇
Energy Partners has a multi-year history of making accretive acquisitions, which
benefit us through our limited and general partner interests. This acquisitive
strategy is expected to continue, with the availability of potential acquisition
candidates being driven by consolidation in the energy industry, as well as
realignment of asset portfolios by major energy companies. In addition, we
expect to, within strict guidelines as to rate of return and risk and timing of
cash flows, expand Natural Gas Pipeline Company of America's pipeline system and
acquire natural gas retail distribution properties that fit well with our
current profile.
It is our intention to carry out the above strategy, modified as necessary
to reflect changing economic and other circumstances. However, as discussed
under "Risk Factors" elsewhere in this report, there are factors that could
affect our ability to carry out our strategy or to affect its level of success
even if carried out.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Our discussion and analysis of financial condition and operations are based
on our consolidated financial statements, prepared in accordance with accounting
principles generally accepted in the United States of America and contained
within this report. Certain amounts included in or affecting our financial
statements and related disclosure must be estimated, requiring us to make
certain assumptions with respect to values or conditions which cannot be known
with certainty at the time the financial statements are prepared. Therefore, the
reported amounts of our assets and liabilities, revenues and expenses and
associated disclosures with respect to contingent assets and obligations are
necessarily affected by these estimates. We evaluate these estimates on an
ongoing basis, utilizing historical experience, consultation with experts and
other methods we consider reasonable in the particular circumstances.
Nevertheless, actual results may differ significantly from our estimates.
22
In preparing our financial statements and related disclosures, we must use
estimates in determining the economic useful lives of our assets, obligations
under our employee benefit plans, provisions for uncollectible accounts
receivable, unbilled revenues for our natural gas distribution deliveries for
which meters have not yet been read, exposures under contractual
indemnifications and to determine various other recorded or disclosed amounts.
However, we believe that certain accounting policies are of more significance in
our financial statement preparation process than others. With respect to revenue
recognition, our power plant development business utilizes the percentage of
completion method to determine what portion of its overall constructor fee has
been earned. We utilize the services of third-party engineering firms to help us
estimate the progress being made on each project, but any such process requires
subjective judgments. Any errors in this estimation process could result in
revenues being reported before or after they were actually earned. Increases or
decreases in revenues resulting from revisions to these estimates are recorded
in the period in which the facts that give rise to the revision become known.
With respect to our environmental exposure, we utilize both internal staff and
external experts to assist us in identifying environmental issues and in
estimating the costs and timing of remediation efforts. Often, as the
remediation evaluation and effort progresses, additional information is
obtained, requiring revisions to estimated costs. These revisions are reflected
in our income in the period in which they are reasonably determinable. We record
a valuation allowance to reduce our deferred tax assets to an amount that is
more likely than not to be realized. While we have considered future taxable
income and prudent and feasible tax planning strategies in determining the
amount of our valuation allowance, any difference in the amount that we expect
to ultimately realize will be included in income in the period in which such a
determination is reached. As discussed under "Risk Management" elsewhere herein,
we enter into derivative contracts (natural gas futures, swaps and options)
solely for the purpose of mitigating risks that accompany our normal business
activities, including interest rates and the price of natural gas and associated
transportation. We account for these derivative transactions as ▇▇▇▇▇▇ in
accordance with the authoritative accounting guidelines, marking the derivatives
to market at each reporting date, with the unrealized gains and losses either
recognized as part of comprehensive income or, in the case of interest rate
swaps, as a valuation adjustment to the underlying debt. Any inefficiency in the
performance of the hedge is recognized in income currently and, ultimately, the
financial results of the hedge are recognized concurrently with the financial
results of the underlying hedged item. All but an insignificant amount of our
natural gas related derivatives are for terms of 18 months or less, allowing us
to utilize widely available, published forward pricing curves in determining the
appropriate market values. Our interest rate swaps are similar in nature to many
other such financial instruments and are valued for us by commercial banks with
expertise in such valuations. Finally, we are subject to litigation as the
result of our business operations and transactions. We utilize both internal and
external counsel in evaluating our potential exposure to adverse outcomes from
judgments or settlements. To the extent that actual outcomes differ from our
estimates, or additional facts and circumstances cause us to revise our
estimates, our earnings will be affected.
23
CONSOLIDATED FINANCIAL RESULTS
YEAR ENDED DECEMBER 31,
---------------------------------------
2001 2000 1999
----------- ----------- -----------
(IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
Operating Revenues....................................... $1,054,918 $2,679,722 $1,836,368
========== ========== ==========
Gross Margin............................................. $ 715,565 $ 753,654 $ 786,118
========== ========== ==========
General and Administrative Expenses...................... $ 70,386 $ 58,087 $ 85,591
========== ========== ==========
Operating Income......................................... $ 384,319 $ 395,143 $ 295,702
Other Income and (Expenses).............................. 22,917 (87,977) (81,151)
Income Taxes............................................. 168,601 123,017 79,124
---------- ---------- ----------
Income from Continuing Operations........................ 238,635 184,149 135,427
Loss from Discontinued Operations........................ -- -- (50,941)
Loss on Disposal of Discontinued Operations.............. -- (31,734) (344,378)
Extraordinary Item -- Loss on Early Extinguishment of
Debt................................................... (13,565) -- --
---------- ---------- ----------
Net Income (Loss)........................................ $ 225,070 $ 152,415 $ (259,892)
========== ========== ==========
Total Diluted Earnings (Loss) Per Common Share........... $ 1.86 $ 1.33 $ (3.24)
Loss from Discontinued Operations...................... -- -- (0.63)
Loss on Disposal of Discontinued Operations............ -- (0.28) (4.29)
Extraordinary Item -- Loss on Early Extinguishment of
Debt................................................ (0.11) -- --
---------- ---------- ----------
Income from Continuing Operations Per Diluted Share...... 1.97 1.61 1.68
Asset Sales(1)......................................... 0.08 0.32 1.23
Litigation Provision................................... (0.05) -- --
Counterparty Nonperformance Exposure................... (0.02) -- --
Merger-related and Severance Costs..................... -- -- (0.29)
---------- ---------- ----------
$ 1.96 $ 1.29 $ 0.74
========== ========== ==========
---------------
(1) Incidental asset sales are included in business segment earnings.
Our results for 2001, in comparison to 2000, reflect a decrease of $1.6
billion in operating revenues, a decrease of $38.1 million in gross margin and a
decrease of $10.8 million in operating income. These declines are attributable
to the fact that consolidated results for 2000 include the results of ▇▇▇▇▇▇
▇▇▇▇▇▇ Texas Pipeline, L.P., referred to in this report as "▇▇▇▇▇▇ ▇▇▇▇▇▇ Texas
Pipeline" (operating revenues, gross margin and operating income before
corporate charges of $1.7 billion, $81.3 million and $29.3 million,
respectively), which was transferred to ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners effective
December 22, 2000. If the results of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Texas Pipeline are excluded
from 2000 results, the comparison of 2001 to 2000 reflects increases of $122.7
million, $43.2 million and $13.9 million in operating revenues, gross margin and
operating income, respectively. These increases represent improved results at
each of our business segments, with ▇▇▇▇▇▇ ▇▇▇▇▇▇ Retail making the largest
contribution to increased revenues and Power and Other making the largest
contribution to the increases in gross margin and operating income. General and
administrative expenses increased by $12.3 million from 2000 to 2001 principally
as a result of (i) increased costs for employee benefits and (ii) a $5.0 million
loss resulting from nonperformance by a derivative counterparty (Enron Corp.) as
more fully discussed in Note 15 of the accompanying Notes to Consolidated
Financial Statements. General and administrative expenses decreased by $27.5
million from 1999 to 2000 principally due to (1) the December 1999 transfer of
▇▇▇▇▇▇ ▇▇▇▇▇▇ Interstate Gas Transmission and certain other assets to ▇▇▇▇▇▇
▇▇▇▇▇▇ Energy Partners and (2) decreased employee benefit costs in 2000 due, in
part, to staffing reductions following the October
24
1999 acquisition of ▇▇▇▇▇▇ ▇▇▇▇▇▇ (Delaware). Individual business segment
results are discussed in detail following.
Below the operating income line, the improved results for 2001, relative to
2000, were principally due to (i) an increase of $138.5 million in equity
earnings in ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners, net of amortization of excess
investment and (ii) a decrease of $27.0 million in net interest expense. The
favorable variance created by these impacts was partially offset by (i) $12.6
million of increased 2001 minority interest (due to the sale of ▇▇▇▇▇▇ ▇▇▇▇▇▇
Management shares) and (ii) a reduction of approximately $39.1 million in net
gains from assets sales in 2001. Additional information on these non-operating
income and expense items is included under "Other Income and (Expenses)"
following.
For 2002, earnings attributable to our investment in ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy
Partners are expected to increase by approximately 60% due to, among other
factors, the improved performance of existing assets and the addition of
earnings attributable to ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners' pending acquisition of
Tejas Gas, LLC. However, there are factors beyond the control of ▇▇▇▇▇▇ ▇▇▇▇▇▇
Energy Partners that may affect its results, including developments in the
regulatory arena and as yet unforeseen competitive developments.
Diluted earnings per common share from continuing operations increased from
$1.61 in 2000 to $1.97 in 2001. In addition to the operating and financing
factors described preceding, this increase reflects an additional 6.3 million
(5.5%) average diluted shares outstanding in 2001, largely due to shares issued
in conjunction with the November 2001 maturity of our premium equity
participating units, partially offset by shares reacquired in our share
repurchase program. As shown in the preceding table of our consolidated
financial results, after adjustment for net gains from asset sales and two loss
provisions recorded in 2001, diluted earnings per share from continuing
operations increased from $1.29 per share in 2000 to $1.96 per share in 2001. In
total, diluted earnings per common share increased from $1.33 in 2000 to $1.86
in 2001, reflecting, in addition to the factors discussed preceding, the $0.28
loss per share impact of discontinued operations in 2000 and the $0.11 loss per
share from early extinguishment of debt in 2001.
RESULTS OF OPERATIONS
We manage our various businesses by, among other things, allocating capital
and monitoring operating performance. This management process includes dividing
the company into business segments so that performance can be effectively
monitored and reported for a limited number of discrete businesses. Currently,
we manage and report our operations in the following business segments:
BUSINESS SEGMENT BUSINESS CONDUCTED REFERRED TO AS:
---------------- ------------------ ---------------
Natural Gas Pipeline Company of
America and certain
affiliates...................... The ownership and operation of a Natural Gas Pipeline
major interstate natural gas Company of America
pipeline and storage system
Retail Natural Gas Distribution... The regulated transportation, ▇▇▇▇▇▇ ▇▇▇▇▇▇ Retail
distribution and sale of natural
gas to residential, commercial and
industrial customers and the
non-regulated sales of natural gas
to certain utility customers under
the Choice Gas Program
Power Generation and Other........ The construction and operation of Power and Other
natural gas-fired electric
generation facilities, together
with various other activities not
constituting separately managed or
reportable business segments
25
In previous periods, we owned and operated other lines of business, which
we discontinued during 1999. In addition, our direct investment in the natural
gas transmission and storage business has significantly decreased as a result of
(i) the December 31, 1999 transfer to ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners of ▇▇▇▇▇▇
▇▇▇▇▇▇ Interstate Gas Transmission LLC, referred to in this report as "▇▇▇▇▇▇
▇▇▇▇▇▇ Interstate Gas Transmission" and (ii) the December 22, 2000 transfer to
▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Texas Pipeline. The results of
operations of these two businesses are included in our financial statements
until their disposition.
The accounting policies we apply in the generation of business segment
information are generally the same as those described in Note 1 to the
accompanying Consolidated Financial Statements, except that certain items below
the "Operating Income" line are either not allocated to business segments or are
not considered by management in its evaluation of business segment performance.
An exception to this is that, with respect to ▇▇▇▇▇▇ ▇▇▇▇▇▇ Power, which
routinely conducts its business activities in the form of joint operations with
other parties that are accounted for under the equity method of accounting, we
include its equity in earnings of these investees in its operating results.
These equity method earnings are included in "Other Income and (Expenses)" in
our Consolidated Statements of Operations. In addition, (i) certain items
included in operating income (such as merger-related and severance costs and
general and administrative expenses) are not allocated to individual business
segments and (ii) gains and losses from incidental sales of assets are included
in segment earnings. With adjustment for these items, we currently evaluate
business segment performance primarily based on operating income in relation to
the level of capital employed. We account for intersegment sales at market
prices, while we account for asset transfers at either market value or, in some
instances, book value. As necessary for comparative purposes, we have
reclassified prior period results and balances to conform to the current
presentation.
Following are operating results by individual business segment (before
intersegment eliminations), including explanations of significant variances
between the periods presented.
NATURAL GAS PIPELINE COMPANY OF AMERICA
YEAR ENDED DECEMBER 31,
------------------------------
2001 2000 1999
-------- -------- --------
(IN THOUSANDS EXCEPT
SYSTEMS THROUGHPUT)
Operating Revenues................................... $646,804 $622,002 $626,888
======== ======== ========
Gross Margin......................................... $515,360 $510,586 $511,407
======== ======== ========
Segment Earnings..................................... $346,569 $344,405 $306,695
======== ======== ========
Systems Throughput (Trillion Btus)................... 1,398.9 1,459.3 1,449.9
======== ======== ========
Natural Gas Pipeline Company of America's segment earnings increased by
$2.2 million, or 0.6%, from 2000 to 2001. Operating results for 2001 were
positively affected, relative to 2000, by (i) increased natural gas
transportation and storage margins and (ii) a $6.1 million pre-tax gain on the
sale of offshore laterals in 2001. These positive impacts were partially offset
by (i) increased operations and maintenance expenses, primarily attributable to
the higher costs of electric power for compression, (ii) increased ad valorem
taxes and (iii) the fact that 2000 results include a $3.3 million refund of
previously expensed transportation charges from an unaffiliated interstate
pipeline and $1.5 million of pre-tax gains from asset sales.
Although Natural Gas Pipeline Company of America experienced a reduction in
its systems throughput in 2001, this has not had any significant impact on its
revenues or contracting level. Recontracting in 2001 has been very successful
with 100% of nominated storage service and demand storage service capacity
contracted and in excess of 96% of long-haul transportation capacity contracted.
The decrease in throughput can be attributed to several factors. In 2001,
Natural Gas Pipeline Company of America's market area experienced the warmest
November-December period on record. Storage customers have not withdrawn gas as
pricing favored continuing to hold inventories. Market area deliveries
26
in general have been affected by decreased natural gas consumption in the
industrial sector. Demand that disappeared during the 2000-01 winter, when the
price of natural gas was relatively high, has been slow to return, especially as
a result of the economic downturn. Another factor impacting Natural Gas Pipeline
Company of America's market area deliveries is the increase in Canadian supply
via the Alliance Pipeline. This impact has been mitigated by the fact that close
to half of Alliance's volumes move into Vector Pipeline and on to points east of
the Chicago area.
Natural Gas Pipeline Company of America's segment earnings increased by
$37.7 million, or 12.3%, from 1999 to 2000. Operating results for 2000 were
positively affected, relative to 1999, by (i) increased operational efficiency
and the associated favorable impact of increased natural gas prices on
operational natural gas sales in 2000, (ii) increased storage service revenues,
(iii) a reduction in amortization resulting from the July 1999 change in
amortization rates (see Note 5 of the accompanying Notes to Consolidated
Financial Statements), (iv) reduced 2000 operations and maintenance expenses due
to successful cost control measures and to the sales of certain gathering assets
and offshore laterals and (v) reduced ad valorem taxes. These positive effects
were partially offset by (i) reduced 2000 revenues due to the sales of certain
gathering assets and offshore laterals, (ii) decreased 2000 unit revenues
largely attributable to competing pipeline capacity in the upper Midwest,
Natural Gas Pipeline Company of America's principal market area, and reduced
transport revenue due to the sale of a marketing affiliate during 2000.
In accordance with the "fee-based" aspect of our business strategy, Natural
Gas Pipeline Company of America has achieved significant success extending
existing contracts and obtaining new contracts for firm transportation capacity
on its pipeline system. In addition to extending key capacity arrangements, we
have also pursued throughput growth on Natural Gas Pipeline Company of America's
system through new transportation and balancing services and by pursuing
agreements to provide natural gas transportation and storage services to new and
existing gas-fired electric generation facilities along the system. On October
2, 2001, we announced that Natural Gas Pipeline Company of America had signed a
firm-transportation contract to provide FPL Energy, LLC, a subsidiary of FPL
Group, Inc., with natural gas to power its new 1,789-megawatt electric
generating facility in ▇▇▇▇▇▇▇ County, located ▇▇ ▇▇▇▇▇ ▇▇▇▇ ▇▇ ▇▇▇▇▇▇, ▇▇▇▇▇.
Under the long-term agreement, FPL Energy has subscribed for 250,000 MMBtus per
day of firm capacity on the Natural Gas Pipeline Company of America system,
effective with the startup of operations at the new plant in mid-year 2003. FPL
Energy also agreed to extend an existing 50,000 MMBtus per day firm-
transportation service contract it holds on Natural Gas Pipeline Company of
America for an additional 18 years. In recent periods, Natural Gas Pipeline
Company of America has contracted to supply natural gas transportation services
to approximately 23 natural gas-fired electric generation facilities along its
system totaling approximately 13,000 megawatts of electric generation capacity.
In addition to internal growth on Natural Gas Pipeline Company of America's
existing pipeline system, we are also pursuing opportunities to expand the
system. Two major expansion projects under way are the Horizon Pipeline project
in Northern Illinois (see Note 6 of the accompanying Notes to Consolidated
Financial Statements) and the extension of Natural Gas Pipeline Company of
America's system into the metropolitan east area of St. Louis. Both the Horizon
Pipeline and the St. Louis extension are expected to be placed into service by
summer of 2002.
Substantially all of Natural Gas Pipeline Company of America's pipeline
capacity is committed under firm transportation contracts ranging from one to
five years. Under these contracts, over 90% of the revenues are derived from a
demand charge and, therefore, are collected regardless of the volume of gas
actually transported. The principal impact of the actual level of gas
transported is on fuel recoveries, which are received in-kind as volumes move on
the system. Approximately 71% of the total transportation volume committed under
Natural Gas Pipeline Company of America's long-term firm transportation
contracts in effect on January 1, 2002 had remaining terms of less than three
years. Natural Gas Pipeline Company of America continues to actively pursue the
renegotiation, extension and/or replacement of expiring contracts. Nicor Gas and
Peoples Energy are Natural Gas Pipeline Company of America's two largest
customers. Contracts representing 28% of Natural Gas Pipeline Company of
America's total long-term contracted firm transport capacity as of January 1,
2002 are scheduled to expire during 2002.
27
For 2002, ▇▇▇▇▇▇ ▇▇▇▇▇▇ currently expects that Natural Gas Pipeline Company
of America will experience 3-5% growth in segment earnings. This increase in
earnings is expected to be derived primarily from the Horizon Pipeline and St.
Louis expansions expected to come on-line, augmenting contract renewals that
create a stable earnings base. In addition, incremental revenues are anticipated
from new electric power generation load and, potentially, from storage capacity
expansion. However, as discussed following, there are factors beyond our control
that can affect our results, including developments in the regulatory arena and
as yet unforeseen competitive developments. Accordingly, our actual future
results may differ significantly from our projections.
Our principal exposure to market variability is related to the variation in
natural gas prices and basis differentials, which can affect gross margins in
our Natural Gas Pipeline Company of America segment. "Basis differential" is a
term that refers to the difference in natural gas prices between two locations
or two points in time. These price differences can be affected by, among other
things, natural gas supply and demand, available transportation capacity,
storage inventories and deliverability, prices of alternative fuels and weather
conditions. In recent periods, additional competitive pressures have been
generated in midwest natural gas markets due to the introduction and planned
introduction of pipeline capacity to bring additional supplies of natural gas
into the Chicago market area, although incremental pipeline capacity to take gas
out of the area has also been constructed. We have attempted to reduce our
exposure to this form of market variability by pursuing long-term, fixed-rate
type contract agreements to utilize the capacity on Natural Gas Pipeline Company
of America's system. In addition, as discussed under "Risk Management" elsewhere
in this document and in Note 15 of the accompanying Notes to Consolidated
Financial Statements, we utilize a comprehensive risk management program to
mitigate our exposure to changes in the market price of natural gas and
associated transportation.
The majority of Natural Gas Pipeline Company of America's system is subject
to rate regulation under the jurisdiction of the Federal Energy Regulatory
Commission. Currently, there are no material proceedings challenging the rates
on any of our pipeline systems. Nonetheless, shippers on our pipelines do have
rights to challenge the rates we charge under certain circumstances prescribed
by applicable regulations. There can be no assurance that we will not face
challenges to the rates we receive for services on our pipeline systems in the
future.
▇▇▇▇▇▇ ▇▇▇▇▇▇ RETAIL
YEAR ENDED DECEMBER 31,
------------------------------
2001 2000 1999
-------- -------- --------
(IN THOUSANDS EXCEPT
SYSTEMS THROUGHPUT)
Operating Revenues................................... $285,142 $229,509 $182,912
======== ======== ========
Gross Margin......................................... $111,063 $100,698 $ 75,648
======== ======== ========
Segment Earnings..................................... $ 56,398 $ 49,755 $ 20,055
======== ======== ========
Systems Throughput (Trillion Btus)................... 42.0 44.0 36.8
======== ======== ========
▇▇▇▇▇▇ ▇▇▇▇▇▇ Retail's segment earnings increased by $6.6 million, or
13.4%, from 2000 to 2001. ▇▇▇▇▇▇ ▇▇▇▇▇▇ Retail's operating results were
positively impacted in 2001, relative to 2000, by (i) continued successful risk
management of gas supply needs, which has reduced, but not eliminated,
weather-related volatility in earnings (refer to the heading "Risk Management"
in this Item and Note 15 of the accompanying Notes to Consolidated Financial
Statements for a more detailed discussion of our risk management policies) and
(ii) the inclusion, in 2001 results, of income from the Wolf Creek storage
system. These positive impacts were partially offset by higher operating
expenses resulting from overall system expansion.
▇▇▇▇▇▇ ▇▇▇▇▇▇ Retail's segment earnings increased by $29.7 million, or
148.1% from 1999 to 2000. Operating results for 2000 were positively impacted,
relative to 1999, by (i) increased system throughput in 2000, although a portion
of this increase represents volumes transported for relatively low margins,
28
(ii) increased service revenues in 2000 and (iii) reduced 2000 operating
expenses. The increase in gross margins (operating revenues minus gas purchases
and other costs of sales) which resulted from increased throughput volumes was
principally due to increased irrigation demand in the third quarter of 2000 and
increased space heating demand in the fourth quarter. Weather-related demand in
▇▇▇▇▇▇ ▇▇▇▇▇▇ Retail's service territory was affected by colder than normal
weather in the fourth quarter of 2000, compared with warmer than normal weather
in the fourth quarter of 1999. The reduced 2000 operating expenses resulted from
(i) a reduction in advertising and marketing expenses for the Choice Gas program
(unregulated sales of natural gas made to certain of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Retail's
utility customers), (ii) continued focus on efficient operations, (iii) reduced
ad valorem and use taxes in 2000 and (iv) reduced costs for certain
administrative functions due to renegotiation of a contract with a third-party
service provider.
For 2002, we currently expect that ▇▇▇▇▇▇ ▇▇▇▇▇▇ Retail will experience
4-6% growth in segment earnings. With a stable base of earnings due to its
regulated business, as supplemented by our weather hedging program, increased
earnings are expected to derive from the impact of the Citizens acquisition as
discussed following and from the impact of a full year of cost savings resulting
from capital projects to reduce operating costs through efficiency improvements.
However, as discussed following, there are factors beyond our control that can
affect our results, including developments in the regulatory arena, currently
unforeseen competitive developments and weather-related impacts outside our
hedging program. Accordingly, our actual future results may differ significantly
from our projections.
During the fourth quarter of 2001, ▇▇▇▇▇▇ ▇▇▇▇▇▇ Retail successfully
completed the acquisition of natural gas distribution facilities from Citizens
Communications Company (NYSE: CZN, CZB) for approximately $11 million in cash
and assumed liabilities. The natural gas distribution assets serve approximately
13,400 residential, commercial and agricultural customers in Bent, Crowley,
Otero, Archuleta, La Plata and Mineral Counties in Colorado.
A significant portion of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Retail's business is subject to rate
regulation by various state and local jurisdictions in Colorado, Wyoming and
Nebraska. There are currently no material proceedings challenging the rates on
any of our intrastate pipeline or distribution systems. Nonetheless, there can
be no assurance that we will not face challenges to the rates we receive for
these services in the future. ▇▇▇▇▇▇ ▇▇▇▇▇▇ Retail is also subject to market
variability in natural gas prices and basis differentials. Please refer to the
discussion of basis differentials under the heading "Natural Gas Pipeline
Company of America" in this Item.
POWER AND OTHER
YEAR ENDED DECEMBER 31,
----------------------------
2001 2000 1999
-------- ------- -------
(IN THOUSANDS)
Operating Revenues..................................... $125,045 $80,697 $59,305
======== ======= =======
Gross Margin........................................... $ 89,142 $61,044 $46,384
======== ======= =======
Segment Earnings....................................... $ 63,348 $33,460 $34,379
======== ======= =======
Our Power and Other segment earnings increased by $29.9 million, or 89.3%,
from 2000 to 2001. Operating results for 2001 were positively impacted, relative
to 2000, by (i) increased power plant development fee revenues of $26.8 million,
principally resulting from our development of two 550-megawatt electric
generating plants currently under construction in Wrightsville, Arkansas and
Jackson, Michigan, (ii) increased equity in the earnings of Thermo Cogeneration
Partnership, (iii) $1.9 million of increased earnings from our agreements with
▇▇▇▇-▇▇▇▇▇ Gathering LLC (formerly HS Resources, Inc.), (iv) improved
performance from our natural gas distribution operations in Mexico and (v) the
fact that 2000 results include $2.3 million of losses related to the disposition
of certain of our power turbine purchase agreements. These positive impacts were
partially offset by (i) increased operations and maintenance expenses related to
power plant site development, (ii) increased depreciation expense
29
from corporate computer and telecommunications equipment and (iii) the fact that
2000 results included $0.8 million of gains from asset sales.
Power and Other segment earnings decreased by $0.9 million, or 2.7%, from
1999 to 2000. Operating results for 2000 were negatively impacted, relative to
1999, by (i) a decrease in earnings from equity investments largely attributable
to increased fuel (natural gas) costs related to electricity generation and (ii)
increased operating expenses associated with other operations, principally our
agreements with ▇▇▇▇-▇▇▇▇▇ Gathering LLC and certain telecommunications assets
used primarily by internal business units. These negative impacts were partially
offset by profits from development of the Wrightsville, Arkansas power plant.
For 2002, we currently expect that our Power and Other segment will
experience a decline of 20-25% in segment earnings. The power plants in
Wrightsville, Arkansas and Jackson, Michigan that contributed approximately $32
million in construction fee revenues during 2001 are expected to be completed in
mid 2002. The Jackson, Michigan plant is the first of six plants we agreed to
construct under an agreement with The ▇▇▇▇▇▇▇▇ Companies announced in early
2001. Several other sites have been selected, are currently under consideration
or are currently in the permitting process, although there is no certainty that
we will construct additional power generation facilities at these or other
sites. Therefore, we have not projected additional power plant construction
revenues for 2002 beyond those attributable to power plants currently under
construction. In addition, our Wattenberg natural gas facility that was
previously included in this segment was sold to ▇▇▇▇-▇▇▇▇▇ Gathering LLC at
December 28, 2001. Accordingly, there will be no future segment earnings from
that asset. Given (i) the lengthy development phase, including the lengthy and
uncertain permitting process that precedes actual construction of a power
generation facility and (ii) the impact that projections of future electrical
demand and pricing can have on the desirability, timing and locations for new
power plant development, it is difficult to determine the level of future
earnings for a project-driven segment such as this one. Accordingly, our actual
future results may differ significantly from our projections.
▇▇▇▇▇▇ ▇▇▇▇▇▇ TEXAS PIPELINE
We transferred ▇▇▇▇▇▇ ▇▇▇▇▇▇ Texas Pipeline to ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy
Partners in December of 2000. See Note 6 of the accompanying Notes to
Consolidated Financial Statements for more information regarding these
transactions.
YEAR ENDED DECEMBER 31,
-----------------------
2000 1999
----------- ---------
(IN THOUSANDS EXCEPT
SYSTEMS THROUGHPUT)
Operating Revenues.......................................... $1,747,499 $872,161
========== ========
Gross Margin................................................ $ 81,330 $ 67,487
========== ========
Segment Earnings............................................ $ 29,318 $ 16,554
========== ========
Systems Throughput (Trillion Btus).......................... 654.4 575.3
========== ========
Operating revenues for ▇▇▇▇▇▇ ▇▇▇▇▇▇ Texas Pipeline increased by $875.3
million, or 100.4%, from 1999 to 2000. This increased revenue reflects a 75%
increase in the average sales price of natural gas during 2000 (the increased
price of natural gas is directly reflected in the overall sales rate, of which
it is a component part), together with a 17% increase in sales volumes. Gross
margin (operating revenues minus gas purchases and other costs of sales)
increased by $13.8 million, or 20.5%, from 1999 to 2000, as the increased
operating revenues were offset approximately proportionally by the increased
cost of natural gas purchased. Segment earnings increased by $12.8 million, or
77.1%, from 1999 to 2000 as the increase in gross margin discussed preceding was
partially offset by increased ad valorem taxes.
30
▇▇▇▇▇▇ ▇▇▇▇▇▇ INTERSTATE GAS TRANSMISSION
YEAR ENDED
DECEMBER 31,
1999
--------------------
(IN THOUSANDS EXCEPT
SYSTEMS THROUGHPUT)
Operating Revenues.......................................... $113,207
========
Gross Margin................................................ $ 99,253
========
Segment Earnings............................................ $ 53,630
========
Systems Throughput (Trillion Btus).......................... $ 203.1
========
OTHER INCOME AND (EXPENSES)
YEAR ENDED DECEMBER 31,
---------------------------------
2001 2000 1999
--------- --------- ---------
(IN THOUSANDS)
Interest Expense, Net............................. $(216,200) $(243,155) $(251,920)
Equity in Earnings of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy
Partners:
Equity in Earnings.............................. 277,504 140,913 15,733
Amortization of Excess.......................... (25,644) (27,593) (7,335)
Equity in Earnings of Power Segment............... 5,299 3,669 10,511
Other Equity in Earnings (Losses)................. (5,054) (10,255) 14,140
Minority Interests................................ (36,740) (24,121) (24,845)
Gains from Sales of Assets........................ 22,621 61,684 157,938
Other, Net........................................ 1,131 10,881 4,627
--------- --------- ---------
$ 22,917 $ (87,977) $ (81,151)
========= ========= =========
"Other Income and (Expense)" was a net decrease to earnings of $88.0
million in 2000 and a net increase of $22.9 million in 2001. This positive
change of $110.9 million was principally due to: (i) an increase of $138.5
million in equity in earnings of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners, net of
associated amortization, (ii) a decrease of $27.0 million in net interest
expense in 2001, reflecting reduced interest rates and reduced debt outstanding
and (iii) a reduction of $6.8 million from equity in losses of equity method
investees other than ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners, principally TransColorado
Gas Transmission Company. These favorable impacts were partially offset by (i) a
decrease of $39.1 million in 2001 net gains from sales of assets, (ii) an
increase of $12.6 million in expense due to minority interest in 2001,
principally due to the issuance of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Management shares as discussed
under "Financing Activities" and (iii) a decrease of $9.8 million in income from
"Other, Net" in 2001, largely due to the items included in 2000 results as
discussed following.
The increase of $6.8 million, or 8.4%, in net expense under "Other Income
and (Expenses)" from 1999 to 2000 is principally due to decreased gains from
sales of assets and reduced other equity in earnings in 2000, partially offset
by higher 2000 equity in earnings of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners and increased
"Other, Net." The decrease in gains from sales of assets in 2000 reflects the
fact that 1999 results include (i) a gain of $127.0 million from the transfer to
▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Interstate Gas Transmission and
interests in two equity method investments and (ii) a gain of $28.9 million from
the sale of two offshore pipeline assets, while 2000 results include a gain of
$61.6 million from the sale of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Texas Pipeline to ▇▇▇▇▇▇ ▇▇▇▇▇▇
Energy Partners. The equity in earnings of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners and
associated amortization during 2000 and 1999 result from our October 1999
acquisition of interests in ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners and, thus, 1999
includes only one quarter of earnings on this investment while 2000 reflects
earnings for the full year. The decrease in other equity in earnings from 1999
to 2000 is principally due to the sale of various equity
31
method investments. In addition, 2000 results reflect increased equity in losses
of the TransColorado pipeline joint venture, which was placed in service March
31, 1999. The expense associated with "Minority Interests" in each period
principally represents the costs associated with our two series of Capital
Securities. These securities are described in Note 13 of the accompanying Notes
to Consolidated Financial Statements. The increase in "Other, Net" from 1999 to
2000 reflects the fact that, while each period includes miscellaneous items of
income and expense, 2000 results also include (i) $4.1 million due to the
recovery of note receivable proceeds in excess of its carrying value and (ii)
$3.9 million due to the settlement of a regulatory matter for an amount less
than that previously reserved.
INCOME TAXES -- CONTINUING OPERATIONS
YEAR ENDED DECEMBER 31,
-----------------------------
2001 2000 1999
-------- -------- -------
(IN THOUSANDS)
Income Tax Provision.................................. $168,601 $123,017 $79,124
======== ======== =======
Effective Tax Rate.................................... 41.4% 40.0% 36.9%
======== ======== =======
The increase of $45.6 million in the income tax provision from 2000 to 2001
is almost solely due to increased 2001 pre-tax income. The apparent increase in
the effective tax rate in 2001 is due to the fact that the minority interest in
the earnings of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Management is presented net of its associated tax
expense. The increase of $43.9 million in the income tax provision from 1999 to
2000 is comprised of (i) an increase of $34.2 million due to an increase in
pretax income and (ii) an increase of $9.7 million due to an increase in the
effective tax rate in 2000. The increased effective tax rate for 2000 is
principally due to an increased effective rate associated with state income
taxes.
DISCONTINUED OPERATIONS
YEAR ENDED DECEMBER 31,
------------------------
2000 1999
---------- -----------
(IN THOUSANDS)
Loss from Discontinued Operations, Net of Tax............... $ -- $ (50,941)
======== =========
Loss on Disposal of Discontinued Operations, Net of Tax..... $(31,734) $(344,378)
======== =========
During the third quarter of 1999, we adopted and implemented a plan to
discontinue the direct marketing of non-energy products and services
(principally under the "Simple Choice" brand), which activities had been carried
on largely through our EN-able joint venture with PacifiCorp. During the fourth
quarter of 1999, we adopted and implemented plans to discontinue the following
lines of business: (i) gathering and processing of natural gas, including
short-haul intrastate pipelines and providing field services to natural gas
producers, (ii) wholesale marketing of natural gas and natural gas liquids and
(iii) international operations. We recorded a loss of $344.4 million,
representing the estimated loss to be recognized upon final disposal of these
businesses, including estimated operating losses prior to disposal. During 2000,
we completed the disposition of these businesses, with the exception of
international operations (principally consisting of a natural gas distribution
system under construction in Hermosillo, Mexico), which, in the fourth quarter
of 2000, we decided to retain. Neither the decision to dispose of our
international operations nor our subsequent decision to retain them had any
material effect on our results of operations, commitments and contingencies,
known trends or capital resources. In the fourth quarter of 2000, we recorded an
incremental loss on disposal of discontinued operations of $31.7 million,
representing the impact of the final disposition transactions and adjustment of
previously recorded estimates. We had a remaining liability of approximately
$5.2 million at December 31, 2001 associated with these discontinued operations.
We do not expect significant additional financial impacts associated with these
matters. Note 7 of the accompanying Notes to Consolidated Financial Statements
contains certain additional financial information with respect to these
discontinued operations.
32
LIQUIDITY AND CAPITAL RESOURCES
The following table illustrates the sources of our invested capital. In
addition to our results of operations, these balances are affected by our
financing activities as discussed following.
DECEMBER 31,
------------------------------------
2001 2000 1999
---------- ---------- ----------
(DOLLARS IN THOUSANDS)
Long-term Debt................................... $2,404,967 $2,478,983 $3,293,326
Minority Interests............................... 817,513 4,910 9,523
Common Equity.................................... 2,259,997 1,777,624 1,649,615
Capital Securities............................... 275,000 275,000 275,000
---------- ---------- ----------
Capitalization................................. 5,757,477 4,536,517 5,227,464
Short-term Debt, Less Cash and Cash
Equivalents.................................... 613,918 766,244 555,189
---------- ---------- ----------
Invested Capital............................... $6,371,395 $5,302,761 $5,782,653
========== ========== ==========
Capitalization:
Long-term Debt................................. 41.8% 54.6% 63.0%
Minority Interests............................. 14.2% 0.1% 0.2%
Common Equity.................................. 39.2% 39.2% 31.5%
Capital Securities............................. 4.8% 6.1% 5.3%
Invested Capital:
Total Debt..................................... 47.4% 61.2% 66.6%
Equity, Including Capital Securities and
Minority Interests.......................... 52.6% 38.8% 33.4%
In addition to the direct sources of financing shown in the preceding
table, we obtain financing indirectly through our ownership interests in
unconsolidated entities. Our largest unconsolidated investment is in ▇▇▇▇▇▇
▇▇▇▇▇▇ Energy Partners. As discussed in detail in Note 2 of the accompanying
Notes to Consolidated Financial Statements, holders of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Management
shares may exchange each one of their shares for one common unit of ▇▇▇▇▇▇
▇▇▇▇▇▇ Energy Partners owned by us and our affiliates. This exchange feature is
subject to our right to settle the exchange in cash rather than common units. It
was intended and expected that these securities would trade within a narrow
range. During the period the ▇▇▇▇▇▇ ▇▇▇▇▇▇ Management shares have been
outstanding, the difference between the market price of the ▇▇▇▇▇▇ ▇▇▇▇▇▇
Management shares and the ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners common units has been
minimal and, in recent periods, the ▇▇▇▇▇▇ ▇▇▇▇▇▇ Management shares have traded
at a slight premium to the price of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners' common units.
Accordingly, the exchange feature does not represent a significant financial
asset to the holder. Kinder ▇▇▇▇▇▇ ▇.▇., Inc., our subsidiary that is the
general partner in ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners, is obligated to support the
operations and debt service payments of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners. This
obligation, however, does not arise until the assets of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy
Partners have been fully utilized in meeting its own obligations and, in any
event, does not extend beyond the assets of Kinder ▇▇▇▇▇▇ ▇.▇., Inc.
33
We utilize equity method accounting for several investees and have
interests in or obligations with respect to these entities as shown following:
At December 31, 2001
----------------------- Incremental
INVESTMENT INVESTMENT ENTITY ENTITY INVESTMENT DEBT
ENTITY AMOUNT PERCENT ASSETS(1) DEBT OBLIGATION RESPONSIBILITY
------ ---------- ---------- --------- ------ ----------- --------------
(Dollars in millions)
TransColorado Gas
Transmission Company(2).... $134.3 50.0% $ 300 $ -- $ -- $ --
Horizon Pipeline Company..... -- 50.0% 79 45(3) --(4) --(5)
Ft. ▇▇▇▇▇▇ Power Plant....... 138.9 49.5% 186 149(6) -- --
Igasamex..................... 6.1 21.0% 18 5 -- 1
▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy
Partners, L.P.............. 1,336.0 20.3% 6,733 2,792 -- 522(7)
---------------
(1) At recorded value, in each case, consisting principally of property, plant
and equipment.
(2) There is litigation with respect to this investment; see "Legal and
Environmental" elsewhere herein.
(3) Currently recorded as payable to the partners of Horizon Pipeline. Total
project is expected to be 3rd party project financed at 60% debt and 40%
equity.
(4) No incremental investment is necessary unless project financing is not
obtained. The maximum incremental investment obligation possible is $17
million.
(5) Expected to be non-recourse to owners.
(6) Non-recourse to owners.
(7) We would only be obligated if ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners, L.P. and/or its
assets cannot satisfy its obligations.
AMOUNT OF COMMITMENT EXPIRATION PER PERIOD
-----------------------------------------------------
LESS THAN
TOTAL 1 YEAR 2-3 YEARS 4-5 YEARS AFTER 5 YEARS
---------- --------- ----------- ----------- -------------
(IN THOUSANDS)
CONTRACTUAL OBLIGATIONS
Long-Term Debt, including current
maturities......................... $2,619,375 $206,267 $502,534 $507,284 $1,403,290
Operating Leases..................... 62,055 9,697 18,504 18,100 15,754
Commercial Paper Outstanding......... 423,785 423,785
▇▇▇▇▇▇ ▇▇▇▇▇▇ -- Obligated
Mandatorily Redeemable Preferred
Capital Trust Securities of
Subsidiary Trust Holding Solely
Debentures of ▇▇▇▇▇▇ ▇▇▇▇▇▇........ 275,000 275,000
Incremental Investment in Power
Plants............................. 118,000 118,000
---------- -------- -------- -------- ----------
Total Contractual Cash Obligations... $3,498,215 $757,749 $521,038 $525,384 $1,694,044
========== ======== ======== ======== ==========
OTHER COMMERCIAL COMMITMENTS:
Standby Letters of Credit............ $ 10,384 $ 10,384 $ -- $ -- $ --
========== ======== ======== ======== ==========
We have sufficient liquidity to satisfy our near-term obligations through
the combination of free cash flow and our credit facilities totaling $900
million.
34
CONTINGENCY AMOUNT OF CONTINGENT LIABILITY
----------- ------------------------------
CONTINGENT LIABILITIES:
Guarantor of the Bushton Gas Default by ONEOK, Inc. Averages $23 million per year
Processing Plant Lease through 2012; Total $247.4
million
Assumption of Power Plant Long-term Financing not Approximately $250 million
Note obtained by March 29, 2002
Power Plant Incremental Operational Performance $3 to 8 million per year for
Investment 16 years
Power Plant Incremental Cash Flow Performance Up to a total of $25 million
Investment beginning in the 17th year
following commercial
operations
CASH FLOWS
The following discussion of cash flows should be read in conjunction with
the accompanying Consolidated Statements of Cash Flows and related supplemental
disclosures. All highly liquid investments purchased with an original maturity
of three months or less are considered to be cash equivalents.
NET CASH FLOWS FROM OPERATING ACTIVITIES
"Net Cash Flows Provided by Operating Activities" increased from $167.1
million in 2000 to $437.3 million in 2001, an increase of $270.2 million, or
162%. This increase is primarily due to (i) a decrease of $106.7 million in cash
flows used for discontinued operations, primarily attributable to the
termination of our receivables sales program (see "Net Cash Flows from Financing
Activities" following), (ii) a $117.5 million increase in cash distributions
received in 2001 attributable to our interest in ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners
(see Note 3 of the accompanying Notes to Consolidated Financial Statements and
the discussion following) and (iii) a $20.8 million increase in cash inflow in
2001 due to decreased deferred purchase gas costs resulting from lower natural
gas prices.
"Net Cash Flows Provided by Operating Activities" decreased from $321.2
million in 1999 to $167.1 million in 2000, a decline of $154.1 million, or 48%.
This decline is primarily due to an increase in cash flows used for discontinued
operations, which increased from a source of $94.5 million in 1999 to a use of
$110.4 million in 2000, a $204.9 million increased use of cash reflecting (i)
$124.7 million of cash outflow in 2000 attributable to the termination of our
receivable sale program and (ii) $124.7 million of cash inflow in 1999
attributable to the receivable sale program (see "Net Cash Flows from Financing
Activities" following). The decline in "Net Cash Flows Provided by Operating
Activities" for discontinued operations was partially offset by an increase in
cash flows provided by continuing operations, which increased from a source of
$226.7 million in 1999 to a source of $277.5 million in 2000. This $50.8 million
of increased cash flow is primarily due to (i) $121.3 million of cash
distributions received in 2000 attributable to our interest in ▇▇▇▇▇▇ ▇▇▇▇▇▇
Energy Partners and (ii) a decrease in cash used in 2000 to make interest
payments, reflecting the decreased average debt balance outstanding. Partially
offsetting this increase was an increase of $97.3 million in cash used for
working capital in 2000, primarily due to January 2000 payments associated with
December 1999 gas supply purchases.
In general, distributions from ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners are declared
in the month following the end of the quarter to which they apply and are paid
in the month following the month of declaration to the general partner and unit
holders of record as of the end of the month of declaration. Therefore, the
accompanying Statements of Consolidated Cash Flows for 2001 and 2000 reflect the
receipt of a total of $238.8 million and $121.3 million, respectively, of cash
distributions from ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners for the fourth quarter of 2000
and the first nine months of 2001, and for the fourth quarter of 1999 and the
first nine months of 2000, respectively. The cash distributions attributable to
our interest for the three months and twelve months ended December 31, 2001
total $70.3 million and $264.5 million, respectively.
35
The cash distributions attributable to our interest for the three months and
twelve months ended December 31, 2000 totaled $44.5 million and $149.9 million,
respectively. The increase in distributions during 2000 and 2001 reflects, among
other factors, acquisitions made by ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners and its
results of operations. Summarized financial information for ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy
Partners is contained in Note 20 of the accompanying Notes to Consolidated
Financial Statements.
NET CASH FLOWS FROM INVESTING ACTIVITIES
"Net Cash Flows Provided by (Used in) Investing Activities" decreased from
a source of $498.7 million in 2000 to a use of $1.3 billion in 2001, a net
decrease of $1.8 billion. This decrease is principally due to (i) an outflow of
$991.9 million in 2001 for additional investment in ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy
Partners, (ii) a $500.3 million decrease due to the fact that 2000 cash flows
included proceeds from our December 1999 and December 2000 transfers of certain
assets and interests to ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners, (iii) an outflow of
$298.0 million in 2001 for investments in power plant facilities, partially
offset by proceeds of $247.0 million received in 2001 from the sale of our
investment in the Jackson, Michigan power plant facilities, (iv) an outflow of
$104.7 million in 2001 for additional investment in TransColorado Gas
Transmission Company and (v) a $128.4 million decrease in cash flows from
discontinued investing activities in 2001 as a result of (1) $25.7 million
received in 2001 for discontinued operations sold during 2000 and (2) for 2000,
an inflow of $163.9 million received for discontinued operations sold, partially
offset by an outflow of $59.9 million for a lease buyout on assets included in
discontinued operations prior to divestiture. Please refer to Notes 6 and 7 of
the accompanying Notes to Consolidated Financial Statements for additional
information regarding these transactions.
"Net Cash Flows Provided by (Used in) Investing Activities" decreased from
$1.02 billion in 1999 to $498.7 million in 2000, a decline of $521.5 million
principally due to the sale of approximately $1.1 billion of government
securities during 1999, with the proceeds utilized to repay a short-term note
assumed in conjunction with the January 1998 acquisition of MidCon Corp.
Partially offsetting this decrease was (i) $500.3 million of cash received
during 2000 from the sale of certain interests and assets to ▇▇▇▇▇▇ ▇▇▇▇▇▇
Energy Partners and (ii) cash flows of discontinued investing activities
increasing from a use of $46.6 million in 1999 to a source of $154.2 million in
2000, principally a result of the $163.9 million of proceeds received in 2000
from the sale to ONEOK, Inc. of gathering and processing businesses in Oklahoma,
Kansas and West Texas.
Total proceeds received in 2001 from asset sales were $32.8 million, of
which $25.7 million represented proceeds from the 2000 sale of our gathering and
processing businesses in Oklahoma, Kansas and West Texas as well as our
marketing and trading business to ONEOK. During the year 2000, major asset
dispositions included (i) ▇▇▇▇▇▇ ▇▇▇▇▇▇ Texas Pipeline, the Casper and ▇▇▇▇▇▇▇
Natural Gas Gathering and Processing Systems, our 50 percent interest in Coyote
Gas Treating, LLC and our 25 percent interest in Thunder Creek Gas Services,
L.L.C. to ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners, (ii) gathering and processing
businesses in Oklahoma, Kansas and West Texas as well as our marketing and
trading business to ONEOK, (iii) three natural gas gathering systems and a
natural gas processing facility to WBI Holdings, Inc. and (iv) certain assets
within Wildhorse Energy Partners, LLC to ▇▇▇ ▇▇▇▇▇, Inc. Total proceeds received
in 2000 from asset sales were $730.3 million of which $330 million represented
proceeds from the 1999 transfer of assets to ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners.
Major asset dispositions during 1999 included (i) ▇▇▇▇▇▇ ▇▇▇▇▇▇ Interstate Gas
Transmission, ▇▇▇▇▇▇ ▇▇▇▇▇▇ Trailblazer LLC and our interest in Red Cedar
Gathering Company to ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners, (ii) all of our major
offshore assets in the Gulf of Mexico area, including our interests in Stingray
Pipeline Company L.L.C. and West Cameron Dehydration Company L.L.C., and the
HIOS and UTOS offshore pipeline systems and (iii) MidCon Gas Products of New
Mexico Corp. Total proceeds received in 1999 from asset sales were $111.1
million. Notes 6 and 7 of the accompanying Notes to Consolidated Financial
Statements and "Net Cash Flows from Financing Activities" following contain more
information concerning these transactions.
36
NET CASH FLOWS FROM FINANCING ACTIVITIES
"Net Cash Flows Provided By (Used In) Financing Activities" increased from
a use of $550.3 million in 2000 to a source of $711.6 million in 2001, an
increase of $1.3 billion. This increase is principally due to (i) net proceeds
of $888.1 million in 2001 from the issuance of membership shares by ▇▇▇▇▇▇
▇▇▇▇▇▇ Management (see Note 2 of the accompanying Notes to Consolidated
Financial Statements), (ii) $495.7 million of cash used in 2001 for the early
extinguishment of three series of debt securities (see Note 13 of the
accompanying Notes to Consolidated Financial Statements), (iii) $265.7 million
of cash used in 2001 to repurchase a portion of our outstanding common stock,
(iv) proceeds of $460.4 million in 2001 from the issuance of 13,382,474 shares
of additional common stock due to the maturity of our Premium Equity
Participating Security Units, primarily offset by cash used for the retirement
of the $400 million of 6.45% Series of Senior Notes (see Note 13 of the
accompanying Notes to Consolidated Financial Statements) and (v) a change in net
short-term borrowing of $798.2 million principally due to (1) a reduction in net
short-term borrowing in 2000 facilitated by cash inflows from investing
activities (see "Net Cash Flows from Investing Activities" above) and (2) an
increase in net short-term borrowing in 2001, principally to fund a portion of
the early extinguishment of long-term debt and the reacquisition of a portion of
our outstanding common shares, in each case as discussed preceding.
"Net Cash Flows Provided by (Used in) Financing Activities" decreased from
a use of approximately $1.3 billion in 1999 to a use of $550.3 million in 2000,
a decline of approximately $786.7 million. This decrease was principally due to
the first-quarter 1999 repayment of a $1.39 billion short-term note as discussed
preceding, partially offset by increased short-term borrowings during the same
period, as well as reduced cash payments for dividends in 2000.
SHORT-TERM LIQUIDITY AND FINANCING TRANSACTIONS
Our principal sources of short-term liquidity are our revolving bank
facilities, our commercial paper program (which is supported by our revolving
bank facilities) and cash provided by operations. As of December 31, 2001, we
had available a $500 million 364-day facility dated October 23, 2001, and a $400
million amended and restated five-year revolving credit agreement dated January
30, 1998. These bank facilities can be used for general corporate purposes,
including as backup for our commercial paper program. At December 31, 2001, we
had $423.8 million of bank borrowings and commercial paper issued and
outstanding. The corresponding amount outstanding was $477.7 million at February
1, 2002. After inclusion of applicable letters of credit, the remaining
available borrowing capacity under the bank facilities was $465.8 million and
$411.9 million at December 31, 2001 and February 1, 2002, respectively. The bank
facilities include covenants that are common in such arrangements. For example,
the $500 million facility requires consolidated debt to be less than 68% of
consolidated total capitalization. The $400 million facility requires that
consolidated debt must be less than 67% of consolidated total capitalization.
Both of the bank facilities require the debt of consolidated subsidiaries to be
less than 10% of our consolidated debt and require the consolidated debt of each
material subsidiary to be less than 65% of our consolidated total
capitalization. The $400 million facility requires our consolidated net worth
(inclusive of trust preferred securities) be at least $1.236 billion plus 50
percent of consolidated net income earned for each fiscal quarter beginning with
the last quarter of 1998. The $500 million facility requires our consolidated
net worth (inclusive of trust preferred securities) be at least $1.236 billion
plus 50 percent of consolidated net income earned for each fiscal quarter
beginning with the last quarter of 1999.
Our short-term debt of $630.1 million at December 31, 2001 consisted of (i)
$423.8 million of borrowings under our commercial paper program, (ii) $200
million of Floating Rate Notes due October 10, 2002 and (iii) $6.3 million of
miscellaneous current maturities of long-term debt. Our current liabilities, net
of our current assets, represents an additional short-term obligation of
approximately $67.4 million. Given our expected cash flows from operations and
our unused debt capacity as discussed preceding, including our five-year
revolving credit facility, and based on our projected cash needs in the near
term, we do not expect any liquidity issues in the foreseeable future.
37
On February 14, 2002, we paid a cash dividend on our common stock of $0.05
per share to common stockholders of record as of January 31, 2002.
On November 30, 2001, our Premium Equity Participating Security Units
matured, which resulted in our receipt of $460 million in cash and our issuance
of 13,382,474 shares of additional common stock. We used the cash proceeds to
retire the $400 million of 6.45% Series of Senior Notes that became due on the
same date and a portion of our short-term borrowings then outstanding.
On October 10, 2001, we issued $200 million of Floating Rate Notes due
October 10, 2002 in an offering made pursuant to Rule 144A of the regulations of
the Securities and Exchange Commission. These notes bear interest at the
three-month London Interbank Offered Rate (LIBOR) plus 95 basis points, with
interest paid quarterly. The proceeds from the offering were used to retire a
portion of outstanding short-term borrowings.
On September 10, 2001, we retired our $45 million of 9.625% Series Sinking
Fund Debentures due March 1, 2021, utilizing incremental short-term borrowings.
In March 2001, we retired (i) our $400 million of Reset Put Securities due March
1, 2021 and (ii) our $20 million of 9.95% Series Sinking Fund Debentures due
2020, utilizing a combination of cash and incremental short-term borrowings. In
conjunction with these early extinguishments of debt, we recorded extraordinary
losses of $13.6 million (net of associated tax benefit of $9.0 million). These
losses are included under the caption, "Extraordinary Item, Loss on Early
Extinguishment of Debt" in the accompanying Consolidated Statements of
Operations.
On August 14, 2001, we announced a plan to repurchase $300 million of our
outstanding common stock under a program that was largely completed by the end
of 2001. At the trading price at the time of the announcement, the $300 million
represented approximately 5.7 million shares, or about 4.4 percent of the shares
outstanding. As of December 31, 2001, we had repurchased approximately $270.4
million (5,294,800 shares) of our outstanding common stock under the program,
and an additional $33.5 million was repurchased in January 2002, completing the
previously announced plan. On February 5, 2002, we announced that our Board of
Directors had approved expanding the repurchase plan to a total of $400 million.
As further described under "Risk Management" following, in August 2001, we
entered into $1 billion face value of fixed-to-floating interest rate swaps,
effectively converting the interest expense associated with two of our
fixed-rate debt issues to a floating rate based on the three-month LIBOR. These
swaps are accounted for as fair value ▇▇▇▇▇▇ under Statement of Financial
Accounting Standards ("SFAS") No. 133, Accounting for Derivative Instruments and
Hedging Activities.
In May 2001, ▇▇▇▇▇▇ ▇▇▇▇▇▇ Management, one of our indirect subsidiaries,
issued and sold its shares in an underwritten initial public offering. The net
proceeds from the offering were used by ▇▇▇▇▇▇ ▇▇▇▇▇▇ Management to buy i-units
from ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners for $991.9 million. Upon purchase of the
i-units, ▇▇▇▇▇▇ ▇▇▇▇▇▇ Management became a partner in ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy
Partners and assumed the responsibility to manage and control its business and
affairs. The i-units are a class of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners' limited
partner interests that have been, and will be, issued only to ▇▇▇▇▇▇ ▇▇▇▇▇▇
Management.
In the initial public offering, 10 percent of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Management's
shares were purchased by us, with the balance purchased by the public. The
equity interest in ▇▇▇▇▇▇ ▇▇▇▇▇▇ Management (which we consolidate for financial
reporting purposes) purchased by the public created an additional minority
interest on our balance sheet of $892.7 million at the time of the transaction.
We have certain rights and obligations with respect to these securities,
including an obligation to purchase the ▇▇▇▇▇▇ ▇▇▇▇▇▇ Management shares or
exchange them for ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners, L.P. common units that we own
or for cash.
In September 1999, we established an accounts receivable sales facility
that provided up to $150 million of additional liquidity. In accordance with
this agreement, we received proceeds of $150 million on September 30, 1999. Cash
flows associated with this facility are included with "Cash flows from Operating
Activities" in the accompanying Consolidated Statements of Cash Flows in 1999
and 2000. In February 2000, we reduced our participation in this receivables
sales program by $124.9 million,
38
principally as a result of our then-pending disposition of our wholesale gas
marketing business. On April 25, 2000, we repaid the residual balance and
terminated the agreement.
On January 4, 1999, we repaid a short-term note for $1.4 billion which we
had assumed in connection with the early-1998 acquisition of MidCon Corp. and
that had been payable to Occidental Petroleum Corporation. The note was repaid
using the proceeds of approximately $1.1 billion from the sale of U.S.
government securities that had been held as collateral, with the balance of the
funds provided by an increase in short-term borrowings.
CAPITAL EXPENDITURES AND COMMITMENTS
Capital expenditures in 2001 were $124.2 million. The 2002 capital
expenditure budget totals approximately $145.8 million, before expenditures that
may be made on the Horizon Pipeline project. We expect that funding for the
capital expenditure budget will be provided from internal sources and, if
necessary, incremental borrowings. Approximately $16.9 million of this amount
had been committed for the purchase of plant and equipment at December 31, 2001.
Additional information on commitments is contained in Note 18 of the
accompanying Notes to Consolidated Financial Statements.
LITIGATION AND ENVIRONMENTAL
Our anticipated environmental capital costs and expenses for 2002,
including expected costs for remediation efforts, are approximately $6 million,
compared to approximately $4 million of such costs and expenses incurred in
2001. A substantial portion of our environmental costs are either recoverable
through insurance and indemnification provisions or have previously recorded
liabilities associated with them. We had an established environmental reserve of
approximately $18 million at December 31, 2001 to address remediation issues
associated with approximately 35 projects. This reserve is primarily established
to address and clean up soil and ground water impacts from former releases to
the environment at facilities we have acquired. Reserves for each project are
established by reviewing existing documents, conducting interviews and
performing site inspections to determine the overall size and impact to the
environment. Reviews are made on a quarterly basis to determine the status of
the cleanup, the costs associated with the effort and to identify if the reserve
allocation is appropriately valued. In assessing environmental exposure in
conjunction with proposed acquisitions, we perform thorough reviews of all
records relating to environmental issues, conduct site inspections, interview
employees, and, if necessary, collect soil and groundwater samples. After
consideration of reserves established, we believe that costs for environmental
remediation and ongoing compliance with these regulations will not have a
material adverse effect on our cash flows, financial position or results of
operations or diminish our ability to operate our businesses. However, there can
be no assurances that future events, such as changes in existing laws, the
promulgation of new laws, or the development of new facts or conditions will not
cause us to incur significant unanticipated costs.
Refer to Notes 10(A) and 10(B) of the accompanying Consolidated Financial
Statements for additional information on our pending litigation and
environmental matters. We believe we have established adequate reserves such
that the resolution of pending litigation and environmental matters will not
have a material adverse impact on our business, cash flows, financial position
or results of operations.
REGULATION
See Note 9 of the accompanying Notes to Consolidated Financial Statements
for information regarding regulatory matters.
RISK MANAGEMENT
The following discussion should be read in conjunction with Note 15 of the
accompanying Notes to Consolidated Financial Statements, which contains
additional information on our risk management activities.
39
Effective January 1, 2001, we adopted SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities, as amended by SFAS No. 137,
Accounting for Derivative Instruments and Hedging Activities -- Deferral of the
Effective Date of FASB Statement No. 133 and SFAS No. 138, Accounting for
Certain Derivative Instruments and Certain Hedging Activities, collectively,
"Statement 133." Statement 133 established accounting and reporting standards
requiring that every derivative financial instrument (including certain
derivative instruments embedded in other contracts) be recorded in the balance
sheet as either an asset or liability measured at its fair value. Statement 133
requires that changes in the derivative's fair value be recognized currently in
earnings unless specific hedge accounting criteria are met. If the derivatives
meet those criteria, Statement 133 allows a derivative's gains and losses to
offset related results on the hedged item in the income statement, and requires
that a company formally designate a derivative as a hedge and document and
assess the effectiveness of derivatives associated with transactions that
receive hedge accounting.
We enter into derivative contracts solely for the purpose of hedging
exposures that accompany our normal business activities. As a result of the
adoption of Statement 133, the fair value of our derivative financial
instruments utilized for hedging activities as of January 1, 2001 (a loss of
$11.9 million) was reported as accumulated other comprehensive income. In
accordance with the provisions of Statement 133, we designated these instruments
as ▇▇▇▇▇▇ of various exposures as discussed following, and we test the
effectiveness of changes in the value of these hedging instruments with the risk
being hedged. Hedge ineffectiveness is recognized in income in the period in
which it occurs.
We enter into these transactions only with counterparties whose debt
securities are rated investment grade by the major rating agencies. In general,
the risk of default by these counterparties is low. However, we recently
experienced a loss as discussed following.
During the fourth quarter of 2001, we determined that Enron Corp. was no
longer likely to honor the obligations it had to us in conjunction with
derivatives we were accounting for as ▇▇▇▇▇▇ under Statement 133. Upon making
that determination, we (i) ceased to account for those derivatives as ▇▇▇▇▇▇,
(ii) entered into new derivative transactions with other counterparties to
replace our position with Enron, (iii) designated the replacement derivative
positions as ▇▇▇▇▇▇ of the exposures that had been hedged with the Enron
positions and (iv) recognized a $5.0 million pre-tax loss (included with
"General and Administrative Expenses" in the accompanying Consolidated Statement
of Operations for 2001) in recognition of the fact that it was unlikely that we
would be paid the amounts then owed under the contracts with Enron. While we
enter into derivative transactions only with investment grade counterparties and
actively monitor their credit ratings, it is nevertheless possible that
additional losses will result from counterparty credit risk in the future.
Our businesses require that we purchase, sell and consume natural gas.
Specifically, we purchase, sell and/or consume natural gas (i) to serve our
regulated natural gas distribution sales customers, (ii) to serve certain of our
retail natural gas distribution customers in areas where regulatory
restructuring has provided for competition in natural gas supply, for customers
who have selected the Company as their supplier of choice under our "Choice Gas"
program, (iii) as fuel in our Colorado power generation facilities, (iv) as fuel
for compressors located on Natural Gas Pipeline Company of America's pipeline
system and (v) for operational sales of gas by Natural Gas Pipeline Company of
America. With respect to item (i), we have no commodity risk because the
regulated retail gas distribution regulatory structure provides that actual gas
cost is "passed-through" to our customers. With respect to item (iii), only one
of these power generation facilities is not covered by a long-term, fixed price
gas supply agreement at a level sufficient for the current and projected
capacity utilization. With respect to item (iv), this fuel is supplied by
in-kind fuel recoveries that are part of the transportation tariff. Items (ii),
(v) and the one power facility included under item (iii) that is not covered by
a long-term fixed-price natural gas supply agreement, give rise to natural gas
commodity price risk which we have chosen to substantially mitigate through our
risk management program. We provide this mitigation through the use of financial
derivative products, and we do not utilize these derivatives for any purpose
other than risk mitigation.
40
Under our Choice Gas program, customers in certain areas served by ▇▇▇▇▇▇
▇▇▇▇▇▇ Retail are allowed to choose their natural gas supplier from a list of
qualified suppliers, although the transportation of the natural gas to the homes
and businesses continues to be provided by ▇▇▇▇▇▇ ▇▇▇▇▇▇ Retail in all cases.
When those customers choose an affiliate of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Retail as their
supplier, we enter into agreements providing for sales of gas to these customers
during a one-year period at fixed prices per unit, but variable volumes. We
mitigate the risk associated with these anticipated sales of gas by purchasing
natural gas futures contracts on the New York Mercantile Exchange ("NYMEX") and,
as applicable, over-the-counter basis swaps to mitigate the risk associated with
the difference in price changes between ▇▇▇▇▇ Hub (NYMEX) basis and the expected
physical delivery location. In addition, we mitigate a portion of the volumetric
risk through the purchase of over-the-counter natural gas options. The time
period covered by this risk management strategy does not extend beyond one year.
With respect to the power generation facility described above that is not
covered by an adequately sized, fixed-price gas supply contract, we are exposed
to changes in the price of natural gas as we purchase it to use as fuel for the
electricity-generating turbines. In order to mitigate this exposure, we purchase
natural gas futures on the NYMEX and, as discussed above, over-the-counter basis
swaps on the NYMEX, in amounts representing our expected fuel usage in the near
term. In general, we do not hedge this exposure for periods longer than one
year.
With respect to operational sales of natural gas made by Natural Gas
Pipeline Company of America, we are exposed to risk associated with changes in
the price of natural gas during the periods in which these sales are made. We
mitigate this risk by selling natural gas futures and, as discussed above,
over-the-counter basis swaps, on the NYMEX in the periods in which we expect to
make these sales. In general, we do not hedge this exposure for periods in
excess of 18 months.
We use a Value-at-Risk model to measure the risk of price changes in the
natural gas and natural gas liquids markets. Value-at-Risk is a statistical
measure of how much the marked-to-market value of a portfolio could change
during a period of time, within a certain level of statistical confidence. We
use a closed form model to evaluate risk on a daily basis. Our Value-at-Risk
computations use a confidence level of 97.7 percent for the resultant price
movement and a holding period of one day chosen for the calculation. The
confidence level used means that there is a 97.7 percent probability that the
▇▇▇▇-to-market losses for a single day will not exceed the Value-at-Risk amount
presented. Instruments evaluated by the model include forward physical gas,
storage and transportation contracts and financial products including commodity
futures and options contracts, fixed price swaps, basis swaps and
over-the-counter options. During 2001, Value-at-Risk reached a high of $9.5
million and a low of $6.5 million. Value-at-Risk at December 31, 2001, was $7.7
million and, based on quarter-end values, averaged $8.0 million for 2001.
Our calculated Value-at-Risk exposure represents an estimate of the
reasonably possible net losses that would be recognized on our portfolio of
derivatives assuming hypothetical movements in future market rates, and is not
necessarily indicative of actual results that may occur. It does not represent
the maximum possible loss or any expected loss that may occur, since actual
future gains and losses will differ from those estimated. Actual gains and
losses may differ from estimates due to actual fluctuations in market rates,
operating exposures and the timing thereof, as well as changes in our portfolio
of derivatives during the year.
During 2001, all of our natural gas derivative activities were designated
and qualified as cash flow ▇▇▇▇▇▇. We recognized approximately $5,000 of pre-tax
loss during 2001 as a result of ineffectiveness of these ▇▇▇▇▇▇, which amount is
reported within the caption "Gas Purchases and Other Costs of Sales" in the
accompanying Consolidated Statement of Income for the year ended December 31,
2001. There was no component of these derivative instruments' gain or loss
excluded from the assessment of hedge effectiveness.
As the hedged sales and purchases take place and we record them into
earnings, we will also reclassify the gains and losses included in accumulated
other comprehensive income into earnings. We expect to reclassify into earnings,
during 2002, substantially all of the accumulated other comprehensive income
balance of $9.8 million, representing unrecognized net gains on derivative
activities at
41
December 31, 2001. During 2001, we reclassified no gains or losses into earnings
as a result of the discontinuance of cash flow ▇▇▇▇▇▇ due to a determination
that the forecasted transactions would no longer occur by the end of the
originally specified time period.
We also provide certain administrative risk management services to ▇▇▇▇▇▇
▇▇▇▇▇▇ Energy Partners, although ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners retains the
obligations and rights arising from all derivative transactions entered into on
its behalf.
In order to maintain a cost effective capital structure, it is our policy
to borrow funds utilizing a mixture of fixed-interest-rate and
floating-interest-rate debt. In August 2001, in order to move closer to a mix of
50% fixed, 50% floating, we entered into fixed-to-floating interest rate swap
agreements with a notional principal amount of $1.0 billion. These agreements
effectively converted the interest expense associated with our 6.65% senior
notes and our 7.25% debentures from fixed rates to floating rates based on
three-month LIBOR plus a credit spread. These swaps have been designated as fair
value ▇▇▇▇▇▇ as defined by Statement 133. These swaps meet the conditions
required to assume no ineffectiveness under Statement 133 and, therefore, we
have accounted for them utilizing the "shortcut" method prescribed for fair
value ▇▇▇▇▇▇. Accordingly, the carrying value of the swap is adjusted to its
fair value as of each reporting period, with an offsetting entry to adjust the
carrying value of the debt whose fair value is being hedged. We record interest
expense equal to the floating rate payments, which is accrued monthly and paid
semi-annually. Based on short-term borrowings outstanding and the long-term debt
effectively converted to floating rate debt as a result of the swap discussed
above, at December 31, 2001, the market risk related to a one percent change in
interest rates would result in a $16.5 million annual impact on pre-tax income.
RECENT ACCOUNTING PRONOUNCEMENTS
Statement of Financial Accounting Standards No. 141 supercedes Accounting
Principles Board Opinion No. 16 and requires that all transactions fitting the
description of a business combination be accounted for using the purchase method
and prohibits the use of the pooling of interests for all business combinations
initiated after June 30, 2001. The Statement also modifies the accounting for
the excess of fair value of net assets acquired as well as intangible assets
acquired in a business combination. The provisions of this statement apply to
all business combinations initiated after June 30, 2001, and all business
combinations accounted for by the purchase method that are completed after July
1, 2001. This Statement requires disclosure of the primary reasons for a
business combination and the allocation of the purchase price paid to the assets
acquired and liabilities assumed by major balance sheet caption.
In June 2001, the FASB issued SFAS No. 142, Goodwill and Other Intangible
Assets. This Statement addresses financial accounting and reporting for (i)
intangible assets acquired individually or with a group of other assets (but not
those acquired in a business combination) at acquisition and (ii) goodwill and
other intangible assets subsequent to their acquisition. This Statement
supersedes APB Opinion No. 17, Intangible Assets. Under the provisions of this
Statement, if an intangible asset is determined to have an indefinite useful
life, it shall not be amortized until its useful life is determined to be no
longer indefinite. An intangible asset that is not subject to amortization shall
be tested for impairment annually, or more frequently if events or changes in
circumstances indicate that the asset might be impaired. Goodwill will not be
amortized. Goodwill will be tested for impairment on an annual basis and between
annual tests in certain circumstances at a level of reporting referred to as a
reporting unit. This Statement is required to be applied starting with fiscal
years beginning after December 15, 2001. Goodwill and intangible assets acquired
after June 30, 2001 will be subject immediately to the nonamortization and
amortization provisions of this Statement. At December 31, 2001, we had
approximately $25 million of goodwill recorded in conjunction with the 1998
acquisition of the Thermo Companies. In accordance with the provisions of SFAS
No. 142, we will complete our analysis of that goodwill balance for impairment
no later than June 30, 2002 and will record any indicated impairment during
2002. In addition, we have a significant amount of "excess investment" or
"equity method goodwill," principally as a result of our investment in ▇▇▇▇▇▇
▇▇▇▇▇▇ Energy Partners. As provided in SFAS No. 142, this type of investment
will continue to be tested for impairment in accordance with the
42
provisions of Accounting Principles Board Opinion No. 18, The Equity Method of
Accounting for Investments in Common Stock. We estimate that the reduction in
amortization expense resulting from the cessation of amortization of both the
goodwill and the equity method goodwill will result in $0.13 of earnings per
diluted common share in 2002.
In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement
Obligations. This Statement addresses financial accounting and reporting for
obligations associated with the retirement of tangible long-lived assets and the
associated asset retirement costs. This Statement requires that the fair value
of a liability for an asset retirement obligation be recognized in the period in
which it is incurred if a reasonable estimate of fair value can be made. The
associated asset retirement costs are capitalized as part of the carrying amount
of the long-lived asset. This Statement contains disclosure requirements that
provide descriptions of asset retirement obligations and reconciliations of
changes in the components of those obligations. This Statement is effective for
financial statements issued for fiscal years beginning after June 15, 2002.
Earlier applications are encouraged. We have not yet quantified the impacts of
adopting this Statement on our financial position or results of operations.
In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment
or Disposal of Long-Lived Assets. This Statement addresses financial accounting
and reporting for the impairment or disposal of long-lived assets. This
Statement retains the requirements to (i) recognize an impairment loss only if
the carrying amount of a long-lived asset is not recoverable from its
undiscounted cash flows and (ii) measure an impairment loss as the difference
between the carrying amount and fair value of the asset. This Statement removes
goodwill from its scope, eliminating the requirement to allocate goodwill to
long-lived assets to be tested for impairment. This Statement requires that a
long-lived asset to be abandoned, exchanged for a similar productive asset, or
distributed to owners in a spin-off be considered held and used until it is
disposed of. This Statement requires the accounting model for long-lived assets
to be disposed of by sale be used for all long-lived assets, whether previously
held and used or newly acquired. Discontinued operations are no longer measured
on a net realizable value basis, and future operating losses are no longer
recognized before they occur. This Statement broadens the presentation of
discontinued operations in the income statement to include a component of an
entity (rather than a segment of a business). A component of an entity comprises
operations and cash flows that can be clearly distinguished, operationally and
for financial reporting purposes, from the rest of the entity. The provisions of
this Statement are effective for financial statements issued for fiscal years
beginning after December 15, 2001, and interim periods within those fiscal
years, with early application encouraged. The provisions of this Statement
generally are to be applied prospectively.
INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
This filing includes forward-looking statements within the meaning of
Section 27A of the Securities Act of 1933 and Section 21E of the Securities
Exchange Act of 1934. These forward-looking statements are identified as any
statement that does not relate strictly to historical or current facts. They use
words such as "anticipate," "believe," "intend," "plan," "projection,"
"forecast," "strategy," "position," "continue," "estimate," "expect," "may,"
"will," or the negative of those terms or other variations of them or by
comparable terminology. In particular, statements, express or implied,
concerning future operating results or the ability to generate sales, income or
cash flow are forward-looking statements. Forward-looking statements are not
guarantees of performance. They involve risks, uncertainties and assumptions.
The future results of our operations may differ materially from those expressed
in these forward-looking statements. Many of the factors that will determine
these results are beyond our ability to control or predict. Specific factors
that could cause actual results to differ from those in the forward-looking
statements include but are not limited to the following:
- price trends, stability and overall demand for natural gas and
electricity in the United States; economic activity, weather, alternative
energy sources, conservation and technological advances that may affect
price trends and demand;
43
- national, international, regional and local economic, competitive and
regulatory conditions and developments;
- the various factors which affect ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners' ability
to maintain or increase its level of earnings and distributions;
- our ability to integrate any acquired operations into our existing
operations;
- changes in laws or regulations, third-party relationships and approvals,
decisions of courts, regulators and governmental bodies that may affect
our business or our ability to compete;
- our ability to achieve cost savings and revenue growth;
- conditions in capital markets;
- rates of inflation;
- interest rates;
- political and economic stability of oil producing nations;
- the pace of deregulation of retail natural gas and electricity;
- acts of sabotage and terrorism for which insurance is not available at
reasonable premiums;
- the timing and extent of changes in commodity prices for oil, natural
gas, electricity and certain agricultural products; and
- the timing and success of business development efforts.
You should not put an undue reliance on forward-looking statements.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Information required by this item is in Item 7 under the heading "Risk
Management."
44
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
INDEX
PAGE
-----
Report of Independent Accountants........................... 46
Consolidated Statements of Operations....................... 47
Consolidated Statements of Comprehensive Income............. 48
Consolidated Balance Sheets................................. 49
Consolidated Statements of Stockholders' Equity............. 50
Consolidated Statements of Cash Flows....................... 51
Notes to Consolidated Financial Statements.................. 52-91
Selected Quarterly Financial Data (unaudited)............... 92-93
45
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors
and Stockholders of ▇▇▇▇▇▇ ▇▇▇▇▇▇, Inc.
In our opinion, the consolidated financial statements listed in the
accompanying index present fairly, in all material respects, the financial
position of ▇▇▇▇▇▇ ▇▇▇▇▇▇, Inc. (formerly K N Energy, Inc.) and its subsidiaries
at December 31, 2001 and 2000, and the results of their operations and their
cash flows for each of the three years in the period ended December 31, 2001 in
conformity with accounting principles generally accepted in the United States of
America. In addition, in our opinion, the financial statement schedule appearing
under Item 14(a)(2) on page 95 presents fairly, in all material respects, the
information set forth therein when read in conjunction with the related
consolidated financial statements. These financial statements and financial
statement schedule are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements and
financial statement schedule based on our audits. We conducted our audits of
these statements in accordance with auditing standards generally accepted in the
United States of America, which 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, assessing
the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
As discussed in Note 15 to the financial statements, the Company changed
its method of accounting for derivative instruments and hedging activities
effective January 1, 2001.
/s/ PRICEWATERHOUSECOOPERS LLP
Houston, Texas
February 15, 2002
46
CONSOLIDATED STATEMENTS OF OPERATIONS
▇▇▇▇▇▇ ▇▇▇▇▇▇, INC. AND SUBSIDIARIES
YEAR ENDED DECEMBER 31,
------------------------------------
2001 2000 1999
---------- ---------- ----------
(IN THOUSANDS EXCEPT
PER SHARE AMOUNTS)
OPERATING REVENUES:
Natural Gas Transportation and Storage...................... $ 645,369 $ 596,774 $ 745,179
Natural Gas Sales........................................... 301,994 1,965,633 1,004,097
Other....................................................... 107,555 117,315 87,092
---------- ---------- ----------
Total Operating Revenues................................ 1,054,918 2,679,722 1,836,368
---------- ---------- ----------
OPERATING COSTS AND EXPENSES:
Gas Purchases and Other Costs of Sales...................... 339,353 1,926,068 1,050,250
Operations and Maintenance.................................. 126,564 164,286 184,888
General and Administrative.................................. 70,386 58,087 85,591
Depreciation and Amortization............................... 108,290 108,165 147,933
Taxes, other than Income Taxes.............................. 26,006 27,973 34,561
Merger-related and Severance Costs.......................... -- -- 37,443
---------- ---------- ----------
Total Operating Costs and Expenses...................... 670,599 2,284,579 1,540,666
---------- ---------- ----------
OPERATING INCOME............................................ 384,319 395,143 295,702
---------- ---------- ----------
OTHER INCOME AND (EXPENSES):
▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners:
Equity in Earnings........................................ 277,504 140,913 15,733
Amortization of Excess Investment......................... (25,644) (27,593) (7,335)
Equity in Earnings (Losses) of Other Equity Investments..... 245 (6,586) 24,651
Interest Expense, Net....................................... (216,200) (243,155) (251,920)
Minority Interests.......................................... (36,740) (24,121) (24,845)
Other, Net.................................................. 23,752 72,565 162,565
---------- ---------- ----------
Total Other Income and (Expenses)....................... 22,917 (87,977) (81,151)
---------- ---------- ----------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES....... 407,236 307,166 214,551
Income Taxes................................................ 168,601 123,017 79,124
---------- ---------- ----------
INCOME FROM CONTINUING OPERATIONS........................... 238,635 184,149 135,427
---------- ---------- ----------
DISCONTINUED OPERATIONS, NET OF TAX:
Loss from Discontinued Operations........................... -- -- (50,941)
Loss on Disposal of Discontinued Operations................. -- (31,734) (344,378)
---------- ---------- ----------
Total Loss from Discontinued Operations................. -- (31,734) (395,319)
---------- ---------- ----------
Income (Loss) Before Extraordinary Item..................... 238,635 152,415 (259,892)
Extraordinary Item -- Loss on Early Extinguishment of Debt,
Net of Income Tax Benefit of $9,044....................... (13,565) -- --
---------- ---------- ----------
NET INCOME (LOSS)........................................... 225,070 152,415 (259,892)
Less -- Preferred Dividends................................. -- -- 129
Less -- Premium Paid on Preferred Stock Redemption.......... -- -- 350
---------- ---------- ----------
EARNINGS (LOSS) AVAILABLE FOR COMMON STOCK.................. $ 225,070 $ 152,415 $ (260,371)
========== ========== ==========
BASIC EARNINGS (LOSS) PER COMMON SHARE:
Income from Continuing Operations........................... $ 2.07 $ 1.62 $ 1.68
Loss from Discontinued Operations........................... -- -- (0.63)
Loss on Disposal of Discontinued Operations................. -- (0.28) (4.29)
Extraordinary Item -- Loss on Early Extinguishment of
Debt...................................................... (0.12) -- --
---------- ---------- ----------
Total Basic Earnings (Loss) Per Common Share............ $ 1.95 $ 1.34 $ (3.24)
========== ========== ==========
Number of Shares Used in Computing Basic Earnings (Loss) Per
Common Share (Thousands).................................. 115,243 114,063 80,284
========== ========== ==========
DILUTED EARNINGS (LOSS) PER COMMON SHARE:
Income from Continuing Operations........................... $ 1.97 $ 1.61 $ 1.68
Loss from Discontinued Operations........................... -- -- (0.63)
Loss on Disposal of Discontinued Operations................. -- (0.28) (4.29)
Extraordinary Item -- Loss on Early Extinguishment of
Debt...................................................... (0.11) -- --
---------- ---------- ----------
Total Diluted Earnings (Loss) Per Common Share.......... $ 1.86 $ 1.33 $ (3.24)
========== ========== ==========
Number of Shares Used in Computing Diluted Earnings (Loss)
Per Common Share (Thousands).............................. 121,326 115,030 80,358
========== ========== ==========
DIVIDENDS PER COMMON SHARE.................................. $ 0.20 $ 0.20 $ 0.65
========== ========== ==========
The accompanying notes are an integral part of these statements.
47
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
▇▇▇▇▇▇ ▇▇▇▇▇▇, INC. AND SUBSIDIARIES
YEAR ENDED DECEMBER 31,
-------------------------------
2001 2000 1999
-------- -------- ---------
(IN THOUSANDS)
NET INCOME (LOSS)........................................... $225,070 $152,415 $(259,892)
-------- -------- ---------
OTHER COMPREHENSIVE INCOME, NET OF TAX:
Change in Fair Value of Derivatives Utilized for Hedging
Purposes (Net of tax of $24,068)....................... 36,102 -- --
Reclassification of Change in Fair Value of Derivatives to
Net Income (Net of tax benefit of $9,567).............. (14,351)
Reclassification of Unrealized Gain on Available-for-Sale
Securities (Net of tax of $1,068 and $498 in 2000 and
1999, respectively).................................... -- 1,602 852
Cumulative Effect Transition Adjustment (Net of tax
benefit of $7,922)..................................... (11,883) -- --
-------- -------- ---------
OTHER COMPREHENSIVE INCOME.................................. 9,868 1,602 852
-------- -------- ---------
COMPREHENSIVE INCOME (LOSS)................................. $234,938 $154,017 $(259,040)
======== ======== =========
The accompanying notes are an integral part of these statements.
48
CONSOLIDATED BALANCE SHEETS
▇▇▇▇▇▇ ▇▇▇▇▇▇, INC. AND SUBSIDIARIES
DECEMBER 31,
-----------------------
2001 2000
---------- ----------
(IN THOUSANDS)
ASSETS
CURRENT ASSETS:
Cash and Cash Equivalents................................... $ 16,134 $ 141,923
Restricted Deposits......................................... 15,010 14,063
Notes Receivable:
Related Party............................................. 22,576 --
Other..................................................... 18,890 --
Accounts Receivable, Net:
Trade..................................................... 161,926 109,722
Related Parties........................................... 29,502 2,046
Other..................................................... -- 56,750
Inventories................................................. 61,959 19,600
Gas Imbalances.............................................. 50,775 40,838
Other....................................................... 44,260 48,700
---------- ----------
421,032 433,642
---------- ----------
INVESTMENTS:
▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners............................... 2,806,146 1,819,281
Other....................................................... 449,056 263,146
---------- ----------
3,255,202 2,082,427
---------- ----------
PROPERTY, PLANT AND EQUIPMENT, NET.......................... 5,703,952 5,667,991
---------- ----------
DEFERRED CHARGES AND OTHER ASSETS........................... 152,899 202,929
---------- ----------
TOTAL ASSETS................................................ $9,533,085 $8,386,989
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Current Maturities of Long-term Debt........................ $ 206,267 $ 808,167
Notes Payable............................................... 423,785 100,000
Accounts Payable:
Trade..................................................... 160,309 126,245
Related Parties........................................... 70,606 13,556
Accrued Interest............................................ 76,606 72,222
Accrued Taxes............................................... 14,933 26,584
Gas Imbalances.............................................. 58,266 39,496
Payable for Purchase of Thermo Companies.................... -- 15,000
Reserve for Loss on Disposal of Discontinued Operations..... 5,209 23,694
Other....................................................... 102,492 129,911
---------- ----------
1,118,473 1,354,875
---------- ----------
OTHER LIABILITIES AND DEFERRED CREDITS:
Deferred Income Taxes....................................... 2,428,504 2,273,177
Other....................................................... 228,631 222,420
---------- ----------
2,657,135 2,495,597
---------- ----------
LONG-TERM DEBT.............................................. 2,404,967 2,478,983
---------- ----------
▇▇▇▇▇▇ ▇▇▇▇▇▇-OBLIGATED MANDATORILY REDEEMABLE PREFERRED
CAPITAL TRUST
SECURITIES OF SUBSIDIARY TRUST HOLDING SOLELY DEBENTURES
OF ▇▇▇▇▇▇ ▇▇▇▇▇▇........................................ 275,000 275,000
---------- ----------
MINORITY INTERESTS IN EQUITY OF SUBSIDIARIES................ 817,513 4,910
---------- ----------
COMMITMENTS AND CONTINGENT LIABILITIES (NOTES 2, 10 AND 18)
STOCKHOLDERS' EQUITY:
Preferred Stock (Note 14)................................... -- --
Common Stock:
Authorized -- 150,000,000 Shares, Par Value $5 Per Share;
Outstanding -- 129,092,689 and 114,578,800
Shares, Respectively, Before Deducting 5,165,911 and
96,140 Shares Held in Treasury.......................... 645,463 572,894
Additional Paid-in Capital.................................. 1,652,846 1,189,270
Retained Earnings........................................... 219,995 17,787
Treasury Stock.............................................. (263,967) (2,327)
Other....................................................... 5,660 --
---------- ----------
Total Stockholders' Equity.................................. 2,259,997 1,777,624
---------- ----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY.................. $9,533,085 $8,386,989
========== ==========
The accompanying notes are an integral part of these statements.
49
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
▇▇▇▇▇▇ ▇▇▇▇▇▇, INC. AND SUBSIDIARIES
YEAR ENDED DECEMBER 31,
------------------------------------------------------------------------------
2001 2000 1999
------------------------ ------------------------ ------------------------
SHARES AMOUNT SHARES AMOUNT SHARES AMOUNT
----------- ---------- ----------- ---------- ----------- ----------
(DOLLARS IN THOUSANDS)
PREFERRED STOCK:
Beginning Balance.............................. -- $ -- -- $ -- 70,000 $ 7,000
Redemption of Preferred Stock.................. -- -- -- -- (70,000) (7,000)
----------- ---------- ----------- ---------- ----------- ----------
Ending Balance................................. -- -- -- -- -- --
=========== ---------- =========== ---------- =========== ----------
COMMON STOCK:
Beginning Balance.............................. 114,578,800 572,894 112,838,379 564,192 68,645,906 343,230
Acquisition of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Delaware.......... -- -- -- -- 41,683,323 208,417
Acquisitions of Other Businesses............... -- -- 946,207 4,731 2,065,909 10,330
Conversion of Premium Equity Participating
Security Units (PEPS)........................ 13,382,474 66,912 -- -- -- --
Employee and Executive Benefit Plans........... 1,131,415 5,657 794,214 3,971 443,241 2,215
----------- ---------- ----------- ---------- ----------- ----------
Ending Balance................................. 129,092,689 645,463 114,578,800 572,894 112,838,379 564,192
----------- ---------- ----------- ---------- ----------- ----------
ADDITIONAL PAID-IN CAPITAL:
Beginning Balance.............................. 1,189,270 1,203,008 694,223
Costs Related to PEPS Offering................. (504) (1,151) (514)
Revaluation of KMP Investment (Note 6)......... 28,322 (51,074) --
Gain on KMP Units Exchanged for ▇▇▇▇▇▇ ▇▇▇▇▇▇
Management Shares (Note 2)................... 15,722 -- --
Issuance Costs Related to ▇▇▇▇▇▇ ▇▇▇▇▇▇
Management Offering.......................... (4,548) -- --
Acquisition of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Delaware.......... -- -- 470,831
Acquisition of Other Businesses................ (72) 23,824 34,670
Conversion of PEPS............................. 393,446 -- --
Employee and Executive Benefit Plans........... 31,210 14,663 3,798
---------- ---------- ----------
Ending Balance................................. 1,652,846 1,189,270 1,203,008
---------- ---------- ----------
RETAINED EARNINGS (DEFICIT):
Beginning Balance.............................. 17,787 (111,841) 196,147
Net Income (Loss).............................. 225,070 152,415 (259,892)
Cash Dividends:
Common....................................... (22,862) (22,787) (47,967)
Preferred.................................... -- -- (129)
---------- ---------- ----------
Ending Balance................................. 219,995 17,787 (111,841)
---------- ---------- ----------
TREASURY STOCK AT COST:
Beginning Balance.............................. (96,140) (2,327) (172,402) (4,142) (48,598) (1,417)
Treasury Stock Acquired........................ (5,297,132) (270,533) (1,743) (62) (135,510) (2,956)
Treasury Stock Issued.......................... 227,361 8,893 78,005 1,877 11,706 231
----------- ---------- ----------- ---------- ----------- ----------
Ending Balance................................. (5,165,911) (263,967) (96,140) (2,327) (172,402) (4,142)
----------- ---------- ----------- ---------- ----------- ----------
OTHER:
DEFERRED COMPENSATION:
Beginning Balance............................ -- -- (10,686)
Executive Benefit Plans...................... (4,208) -- 10,686
---------- ---------- ----------
Ending Balance............................... (4,208) -- --
---------- ---------- ----------
ACCUMULATED OTHER COMPREHENSIVE INCOME (NET OF
TAX):
Beginning Balance............................ -- (1,602) (2,454)
Unrealized Gain on Derivatives Utilized for
Hedging Purposes........................... 21,751 -- --
Sale of ▇▇▇ ▇▇▇▇▇, Inc. Common Stock......... -- 1,602 --
Unrealized Gain on Equity Securities......... -- -- 852
Cumulative Effect Transition Adjustment...... (11,883) -- --
---------- ---------- ----------
Ending Balance............................... 9,868 -- (1,602)
---------- ---------- ----------
TOTAL OTHER...................................... 5,660 -- (1,602)
----------- ---------- ----------- ---------- ----------- ----------
TOTAL STOCKHOLDERS' EQUITY....................... 123,926,778 $2,259,997 114,482,660 $1,777,624 112,665,977 $1,649,615
=========== ========== =========== ========== =========== ==========
The accompanying notes are an integral part of these statements.
50
CONSOLIDATED STATEMENTS OF CASH FLOWS
▇▇▇▇▇▇ ▇▇▇▇▇▇, INC. AND SUBSIDIARIES
YEAR ENDED DECEMBER 31,
-------------------------------------
2001 2000 1999
----------- --------- -----------
(IN THOUSANDS)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (Loss)........................................... $ 225,070 $ 152,415 $ (259,892)
Adjustments to Reconcile Net Income (Loss) to
Net Cash Flows from Operating Activities:
Loss from Discontinued Operations, Net of Tax............. -- 31,734 395,319
Extraordinary Losses on Early Extinguishment of Debt...... 22,609 -- --
Depreciation and Amortization............................. 108,290 108,165 147,933
Deferred Income Taxes..................................... 129,911 105,714 46,000
Equity in Earnings of ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners....... (251,860) (113,320) (8,398)
Distributions from ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners.......... 238,775 121,323 15,918
Deferred Purchased Gas Costs.............................. 23,499 2,685 6,646
Net Gains on Sales of Facilities.......................... (22,621) (61,684) (157,938)
Changes in Other Working Capital Items (Note 1(O))........ (29,659) (65,030) 32,316
Changes in Deferred Revenues.............................. (5,228) (4,457) (15,641)
Other, Net................................................ 2,253 (58) 24,425
----------- --------- -----------
Net Cash Flows Provided by Continuing Operations............ 441,039 277,487 226,688
Net Cash Flows Provided by (Used in) Discontinued
Operations................................................ (3,737) (110,399) 94,488
----------- --------- -----------
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES............. 437,302 167,088 321,176
----------- --------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital Expenditures........................................ (124,171) (85,654) (92,841)
Proceeds from Sales to ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners........ -- 500,302 --
Other Acquisitions.......................................... (23,899) (19,412) (34,565)
Investment in ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners (Note 2)........ (991,869) -- --
Other Investments........................................... (414,648) (80,511) (14,847)
Proceeds from Sale of Investment in Power Plant............. 247,029 -- --
Proceeds from Sale of ▇▇▇ ▇▇▇▇▇, Inc. Stock................. -- 14,823 28,650
Sale of U.S. Government Securities.......................... -- -- 1,092,415
Proceeds from Sales of Other Assets......................... 7,077 14,998 87,949
----------- --------- -----------
Net Cash Flows Provided by (Used in) Continuing Investing
Activities................................................ (1,300,481) 344,546 1,066,761
Net Cash Flows Provided by (Used in) Discontinued Investing
Activities................................................ 25,742 154,176 (46,568)
----------- --------- -----------
NET CASH FLOWS PROVIDED BY (USED IN) INVESTING ACTIVITIES... (1,274,739) 498,722 1,020,193
----------- --------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-Term Debt, Net........................................ 323,785 (474,400) (1,117,446)
Floating Rate Notes Issued.................................. 200,000 -- --
Long-Term Debt Retired...................................... (872,185) (14,055) (158,934)
Issuance of Shares by ▇▇▇▇▇▇ ▇▇▇▇▇▇ Management.............. 942,614 -- --
Common Stock Issued for Premium Equity Participating
Securities................................................ 460,358 -- --
Other Common Stock Issued................................... 31,184 17,773 8,323
Premiums Paid on Early Extinguishment of Debt............... (30,694) -- --
Other Financing, Net........................................ 7,951 (45,239) --
Preferred Stock Redeemed.................................... -- -- (7,350)
Treasury Stock Issued....................................... 2,464 1,877 231
Treasury Stock Acquired..................................... (265,706) (62) (2,956)
Cash Dividends, Common and Preferred........................ (22,862) (22,787) (48,096)
Minority Interests, Net..................................... 375 (2,436) 379
Premium Equity Participating Securities Contract Fee........ (10,931) (10,936) (11,097)
Securities Issuance Costs................................... (54,705) -- --
----------- --------- -----------
NET CASH FLOWS PROVIDED BY (USED IN) FINANCING ACTIVITIES... 711,648 (550,265) (1,336,946)
----------- --------- -----------
Net Increase (Decrease) in Cash and Cash Equivalents........ (125,789) 115,545 4,423
Cash and Cash Equivalents at Beginning of Year.............. 141,923 26,378 21,955
----------- --------- -----------
Cash and Cash Equivalents at End of Year.................... $ 16,134 $ 141,923 $ 26,378
=========== ========= ===========
The accompanying notes are an integral part of these statements.
51
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(A) NATURE OF OPERATIONS
We are an energy and related services provider and have operations in the
Rocky Mountain and mid-continent regions, with principal operations in Arkansas,
Colorado, Illinois, Iowa, Kansas, Nebraska, Oklahoma, Texas and Wyoming.
Services we offer include: (i) storing, transporting and selling natural gas,
(ii) providing retail natural gas distribution services, and (iii) designing,
developing, constructing and operating electric generation facilities. We have
both regulated and nonregulated operations. Our common stock is traded on the
New York Stock Exchange under the ticker symbol "KMI." During 1999, we acquired
▇▇▇▇▇▇ ▇▇▇▇▇▇ Delaware as discussed in the following paragraph. As a result, we
own, through ▇▇▇▇▇▇ ▇▇▇▇▇▇ Delaware, the general partner interest in ▇▇▇▇▇▇
▇▇▇▇▇▇ Energy Partners, L.P., a publicly traded pipeline master limited
partnership, referred to in these Notes as "▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners," and
receive a substantial portion of our earnings from returns on this investment.
In October 1999, K N Energy, Inc. (as we were then named), a Kansas
corporation, acquired ▇▇▇▇▇▇ ▇▇▇▇▇▇, Inc., a Delaware corporation, referred to
in these Notes as "▇▇▇▇▇▇ ▇▇▇▇▇▇ Delaware." We then changed our name to ▇▇▇▇▇▇
▇▇▇▇▇▇, Inc. Unless the context requires otherwise, references to "we," "us,"
"our," or the "Company" are intended to mean ▇▇▇▇▇▇ ▇▇▇▇▇▇, Inc. (a Kansas
corporation and formerly known as K N Energy, Inc.) and its consolidated
subsidiaries. During the third and fourth quarters of 1999, we adopted and
implemented plans to discontinue our businesses involved in (i) wholesale
marketing of natural gas and natural gas liquids, (ii) gathering and processing
of natural gas, including field services and short-haul intrastate pipelines,
(iii) direct marketing of non-energy products and services and (iv)
international operations. During the fourth quarter of 2000, we determined that,
due to the start-up nature of these operations and the unwillingness of buyers
to pay for the value created to date, it was not in the best interests of the
Company to dispose of our international operations and, accordingly, we decided
to retain them. Additional information concerning these discontinued operations
is contained in Note 7.
(B) BASIS OF PRESENTATION
The consolidated financial statements include the accounts of ▇▇▇▇▇▇
▇▇▇▇▇▇, Inc. and its majority-owned subsidiaries. Investments in jointly owned
operations in which we have the ability to exercise significant influence over
their operating and financial policies are accounted for under the equity
method, as is our investment in ▇▇▇▇▇▇ ▇▇▇▇▇▇ Energy Partners, which is further
described in Note 3. All material intercompany transactions and balances have
been eliminated. Certain prior year amounts have been reclassified to conform to
the current presentation.
Critical Accounting Policies and Estimates
Our discussion and analysis of financial condition and operations are based
on our consolidated financial statements, prepared in accordance with accounting
principles generally accepted in the United States of America and contained
within this report. Certain amounts included in or affecting our financial
statements and related disclosure must be estimated, requiring us to make
certain assumptions with respect to values or conditions which cannot be known
with certainty at the time the financial statements are prepared. Therefore, the
reported amounts of our assets and liabilities, revenues and expenses and
associated disclosures with respect to contingent assets and obligations are
necessarily affected by these estimates. We evaluate these estimates on an
ongoing basis, utilizing historical experience, consultation with experts and
other methods we consider reasonable in the particular circumstances.
Nevertheless, actual results may differ significantly from our estimates.
In preparing our financial statements and related disclosures, we must use
estimates in determining the economic useful lives of our assets, obligations
under our employee benefit plans, provisions for uncollectible accounts
receivable, unbilled revenues for our natural gas distribution deliveries for
which
52
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
meters have not yet been read, exposures under contractual indemnifications and
to determine various other recorded or disclosed amounts. However, we believe
that certain accounting policies are of more significance in our financial
statement preparation process than others. With respect to revenue recognition,
our power plant development business utilizes the percentage of completion
method to determine what portion of its overall constructor fee has been earned.
We utilize the services of third-party engineering firms to help us estimate the
progress being made on each project, but any such process requires subjective
judgments. Any errors in this estimation process could result in revenues being
reported before or after they were actually earned. Increases or decreases in
revenues resulting from revisions to these estimates are recorded in the period
in which the facts that give rise to the revision become known. With respect to
our environmental exposure, we utilize both internal staff and external experts
to assist us in identifying environmental issues and in estimating the costs and
timing of remediation efforts. Often, as remediation evaluations and efforts
progress, additional information is obtained, requiring revisions to estimated
costs. These revisions are reflected in our income in the period in which they
are reasonable determinable. We record a valuation allowance to reduce our
deferred tax assets to an amount that is more likely than not to be realized.
While we have considered future taxable income and prudent and feasible tax
planning strategies in determining the amount of our valuation allowance, any
difference in the amount that we expect to ultimately realize will be included
in income in the period in which such a determination is reached. As discussed
in Note 15, we enter into derivative contracts (natural gas futures, swaps and
options) solely for the purpose of mitigating risks that accompany our normal
business activities, including interest rates and the price of natural gas and
associated transportation. We account for these derivative transactions as
▇▇▇▇▇▇ in accordance with the authoritative accounting guidelines, marking the
derivatives to market at each reporting date, with the unrealized gains and
losses either recognized as part of comprehensive income or, in the case of
interest rate swaps, as a valuation adjustment to the underlying debt. Any
inefficiency in the performance of the hedge is recognized in income currently
and, ultimately, the financial results of the hedge are recognized concurrently
with the financial results of the underlying hedged item. All but an
insignificant amount of our natural gas related derivatives are for terms of 18
months or less, allowing us to utilize widely available, published forward
pricing curves in determining the appropriate market values. Our interest rate
swaps are similar in nature to many other such financial instruments used for
managing interest rate risk and are valued for us by commercial banks with
expertise in such valuations. Finally, we are subject to litigation as the
result of our business operations and transactions. We utilize both internal and
external counsel in evaluating our potential exposure to adverse outcomes from
judgments or settlements. To the extent that actual outcomes differ from our
estimates, or additional facts and circumstances cause us to revise our
estimates, our earnings will be affected.
(C) ACCOUNTING FOR REGULATORY ACTIVITIES
Our regulated utilities are accounted for in accordance with the provisions
of Statement of Financial Accounting Standards ("SFAS") No. 71, Accounting for
the Effects of Certain Types of Regulation, which prescribes the circumstances
in which the application of generally accepted accounting principles is affected
by the economic effects of regulation. Regulatory assets and liabilities
represent probable future revenues or expenses associated with certain charges
and credits that will be recovered from or refunded to
53
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
customers through the ratemaking process. The following regulatory assets and
liabilities are reflected in the accompanying Consolidated Balance Sheets:
DECEMBER 31,
------------------
2001 2000
-------- -------
(IN THOUSANDS)
REGULATORY ASSETS:
Employee Benefit Costs.................................... $ 6,355 $ 6,576
Debt Refinancing Costs.................................... 1,342 1,664
Deferred Income Taxes..................................... 16,405 16,801
Purchased Gas Costs....................................... 3,431 23,470
Plant Acquisition Adjustments............................. 454 454
Rate Regulation and Application Costs..................... 2,580 3,040
-------- -------
Total Regulatory Assets................................... 30,567 52,005
-------- -------
REGULATORY LIABILITIES:
Employee Benefit Costs.................................... 5,967 5,967
Deferred Income Taxes..................................... 26,311 28,930
Purchased Gas Costs....................................... 19,890 22,405
-------- -------
Total Regulatory Liabilities.............................. 52,168 57,302
-------- -------
NET REGULATORY LIABILITIES.................................. $(21,601) $(5,297)
======== =======
As of December 31, 2001, $23.8 million of our regulatory assets and $46.2
million of our regulatory liabilities were being recovered from or refunded to
customers through rates over periods ranging from 1 to 12 years.
(D) REVENUE RECOGNITION POLICIES
We recognize revenues as services are rendered or goods are delivered and,
if applicable, title has passed. Our rate-regulated retail natural gas
distribution business bills customers on a monthly cycle billing basis. Revenues
are recorded on an accrual basis, including an estimate at the end of each
accounting period for gas delivered and, if applicable, title has passed but for
which bills have not yet been rendered. With respect to our construction
activities, we utilize the percentage of completion method whereby revenues and
associated expenses are recognized over the construction period based on work
performed in relation to the total expected for the entire project.
We provide various types of natural gas storage and transportation services
to customers, principally through Natural Gas Pipeline Company of America's
pipeline system. The gas remains the property of the customers at all times. In
many cases (generally described as "firm service"), the customer pays a two-
part rate that includes (i) a fixed fee reserving the right to transport or
store gas in our facilities and (ii) a per-unit rate for volumes actually
transported or injected into/withdrawn from storage. The fixed-fee component of
the overall rate is recognized as revenue ratably over the contract period. The
per-unit charge is recognized as revenue when the volumes are delivered to the
customers' agreed upon delivery point, or when the volumes are injected
into/withdrawn from our storage facilities. In other cases (generally described
as "interruptible service"), there is no fixed fee associated with the services
because the customer accepts the possibility that service may be interrupted at
our discretion in order to serve customers who have purchased firm service. In
the case of interruptible service, revenue is recognized in the same manner
utilized for the per-unit rate on firm service.
54
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(E) EARNINGS PER SHARE
Basic earnings per common share is computed based on the monthly
weighted-average number of common shares outstanding during each period. Diluted
earnings per common share is computed based on the monthly weighted-average
number of common shares outstanding during each period, increased by the assumed
exercise or conversion of securities (stock options and Premium Equity
Participating Security Units) convertible into common stock, for which the
effect of conversion or exercise using the treasury stock method would be
dilutive.
2001 2000 1999
------- ------- ------
(IN THOUSANDS)
Weighted Average Common Shares Outstanding............... 115,243 114,063 80,284
Premium Equity Participating Security Units.............. 4,328 -- --
Dilutive Common Stock Options............................ 1,755 967 74
------- ------- ------
Shares Used to Compute Diluted Earnings Per Common
Share.................................................. 121,326 115,030 80,358
======= ======= ======
Weighted-average stock options outstanding totaling 9,200 for 2001, 307,100
for 2000 and 3,824,000 for 1999 were excluded from the diluted earnings per
common share calculation because the effect of including them would have been
antidilutive. Common shares issuable upon conversion of the premium equity
participating security units were not included in diluted earnings per common
share calculations in 1999 and 2000 because to do so would have been
antidilutive. These common shares were given dilutive effect in 2001 and are
included in the weighted-average common shares outstanding beginning with their
issuance in November 2001 as a result of the maturity of the premium equity
participating security units. Preferred stock dividends and premiums paid on
preferred stock redemptions totaling $479 thousand in 1999 were deducted from
net income in arriving at the balance available to common stockholders. Note 13
(B) contains more information regarding premium equity participating security
units, while Note 17 contains more information regarding stock options.
(F) RESTRICTED DEPOSITS
Restricted Deposits consist of monies on deposit with brokers that are
restricted to meet exchange trading requirements; see Note 15.
(G) ACCOUNTS RECEIVABLE
The caption "Accounts Receivable, Net" in the accompanying Consolidated
Balance Sheets is presented net of allowances for doubtful accounts of $3.4
million and $2.3 million at December 31, 2001 and 2000, respectively. The
caption "Accounts Receivable, Net: Other" principally consists of a receivable
from ONEOK due to cash management services provided to them during 2000 in
conjunction with their purchase of certain of our assets as discussed in Note 7.
(H) INVENTORIES
DECEMBER 31,
-----------------
2001 2000
------- -------
(IN THOUSANDS)
Gas in Underground Storage (Current)........................ $46,451 $ 5,145
Materials and Supplies...................................... 15,508 14,455
------- -------
$61,959 $19,600
======= =======
Inventories are accounted for using the following methods, with the percent
of the total dollars at December 31, 2001 shown in parentheses: average cost
(33.48%), last-in, first-out (65.84%) and first-in,
55
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
first-out (0.68%). All non-utility inventories held for resale are valued at the
lower of cost or market. The excess of current cost over the reported last-in,
first-out value of gas in underground storage valued under that method was not
material at December 31, 2001. We also maintain gas in our underground storage
facilities on behalf of certain third parties. We receive a fee from our storage
service customers but do not reflect the value of their gas stored in our
facilities in the accompanying Consolidated Balance Sheets.
(I) OTHER INVESTMENTS
DECEMBER 31,
-------------------
2001 2000
-------- --------
(IN THOUSANDS)
TransColorado Pipeline Company.............................. $134,255 $ 34,824
Power Investments:
Thermo Companies.......................................... 138,939 135,279
Wrightsville/▇▇▇▇▇▇▇ Plant Investments.................... 97,471 64,695
Other Site Development Investments........................ 68,806 11,845
Other....................................................... 9,585 16,503
-------- --------
$449,056 $263,146
======== ========
Investments consist primarily of equity method investments in
unconsolidated subsidiaries and joint ventures, and include ownership interests
in net profits. At December 31, 2001 and 2000, "Other" included an investment in
Igasamex USA, Ltd. of approximately $6 million and assets held for deferred
employee compensation, among other individually insignificant items.
(J) PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment is stated at historical cost, which for
constructed plant includes indirect costs such as payroll taxes, fringe
benefits, administrative and general costs. Expenditures that increase
capacities, improve efficiencies or extend useful lives are capitalized. Routine
maintenance, repairs and renewal costs are expensed as incurred. The cost of
normal retirements of depreciable utility property, plant and equipment, plus
the cost of removal less salvage, is recorded in accumulated depreciation with
no effect on current period earnings. Gains or losses are recognized upon
retirement of non-utility property, plant and equipment, and utility property,
plant and equipment constituting an operating unit or system, when sold or
abandoned.
In accordance with the provisions of SFAS 121, Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, we
review the carrying values of our long-lived assets whenever events or changes
in circumstances indicate that such carrying values may not be recoverable. As
yet, no asset or group of assets has been identified for which the sum of
expected future cash flows (undiscounted and without interest charges) is less
than the carrying amount of the asset(s) and, accordingly, no impairment losses
have been recorded. However, currently unforeseen events and changes in
circumstances could require the recognition of impairment losses at some future
date.
(K) GAS IMBALANCES
We value gas imbalances due to or due from interconnecting pipelines at the
lower of cost or market. Gas imbalances represent the difference between
customer nominated versus actual gas receipts from and gas deliveries to our
interconnecting pipelines under various Operational Balancing Agreements.
Natural gas imbalances are settled in cash or made up in-kind subject to the
pipelines' various terms.
56
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(L) DEPRECIATION AND AMORTIZATION
Depreciation is computed based on the straight-line method over the
estimated useful lives of assets. The range of estimated useful lives used in
depreciating assets for each property type are as follows:
PROPERTY TYPE RANGE OF ESTIMATED USEFUL LIVES OF ASSETS
------------- ------------------------------------------
(IN YEARS)
Natural Gas Pipelines........................ 24 to 68 (Transmission assets: average 56)
Retail Natural Gas Distribution.............. 33
Power Generation............................. 10 to 30
General and Other............................ 3 to 56
(M) INTEREST EXPENSE, NET
YEAR ENDED DECEMBER 31,
--------------------------
2001 2000 1999
------ ------ ------
(IN MILLIONS)
Interest Expense......................................... $221.0 $248.4 $254.3
AFUDC -- Interest........................................ (4.8) (2.6) (1.9)
Interest Income.......................................... -- (2.6) (0.5)
------ ------ ------
Interest Expense, Net.................................... $216.2 $243.2 $251.9
====== ====== ======
"Interest Expense, Net" as presented in the accompanying Consolidated
Statements of Operations is net of (i) the debt component of the allowance for
funds used during construction ("AFUDC -- Interest"), (ii) in 2000, interest
income attributable to (1) our note receivable from Kinder Morgan Energy
Partners associated with the transfer of certain interests (see Note 6) and (2)
interest income associated with settlement of our net cash position with ONEOK
and (iii) in 1999, interest income related to government securities associated
with the acquisition of MidCon Corp.
In conjunction with our sale of certain assets to ONEOK as discussed in
Note 7, we agreed to continue managing cash for these assets for a period of
months, following which an audit was conducted to affirm the assignment of
specific amounts to the two parties based on the timing of the underlying
business transactions. We included the interest income attributable to our net
receivable resulting from this transaction, together with the related interest
expense, in the caption "Interest Expense, Net" in the accompanying consolidated
Statements of Operations.
(N) OTHER, NET
"Other, Net" as presented in the accompanying Consolidated Statements of
Operations includes $22.6 million, $61.7 million and $157.9 million in 2001,
2000 and 1999, respectively, attributable to gains from sales of assets. These
transactions are discussed in Note 6.
(O) CASH FLOW INFORMATION
We consider all highly liquid investments purchased with an original
maturity of three months or less to be cash equivalents. "Other, Net," presented
as a component of "Net Cash Flows From Operating Activities" in the accompanying
Consolidated Statements of Cash Flows includes, among other things,
undistributed equity in earnings of unconsolidated subsidiaries and joint
ventures (other than Kinder Morgan Energy Partners) and other non-cash charges
and credits to income.
57
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
ADDITIONAL CASH FLOW INFORMATION:
CHANGES IN OTHER WORKING CAPITAL ITEMS:
(NET OF EFFECTS OF ACQUISITIONS AND SALES)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
YEAR ENDED DECEMBER 31,
-------------------------------
2001 2000 1999
-------- --------- --------
(IN THOUSANDS)
Accounts Receivable................................. $(42,153) $(172,781) $(16,483)
Materials and Supplies Inventory.................... (1,512) (2,626) 2,894
Gas in Underground Storage -- Current............... (41,306) 30,453 (17,626)
Other Current Assets................................ (6,052) (27,737) 114
Accounts Payable.................................... 33,375 122,421 37,506
Other Current Liabilities........................... 27,989 (14,760) 25,911
-------- --------- --------
$(29,659) $ (65,030) $ 32,316
======== ========= ========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
YEAR ENDED DECEMBER 31,
------------------------------
2001 2000 1999
-------- -------- --------
(IN THOUSANDS)
CASH PAID FOR:
Interest (Net of Amount Capitalized)................. $225,327 $248,177 $284,762
======== ======== ========
Distributions on Preferred Capital Trust
Securities......................................... $ 21,913 $ 21,913 $ 21,913
======== ======== ========
Income Taxes Paid (Received)......................... $ 27,524 $ 7,674 $(10,883)
======== ======== ========
In April 2000, we made the final scheduled payment for our third-quarter
1998 acquisition of interests in the Thermo Companies using 961,153 shares of
our common stock, approximately $30 million of value. For our December 31, 2000
sale of assets to Kinder Morgan Energy Partners, we received both cash and
non-cash consideration. In October 1999, we acquired Kinder Morgan Delaware in a
non-cash transaction. Notes 3 and 6 contain additional information on these
matters.
(P) STOCK-BASED COMPENSATION
SFAS 123, Accounting for Stock-Based Compensation, encourages, but does not
require, entities to adopt the fair value method of accounting for stock-based
compensation plans. As allowed under SFAS 123, we continue to apply Accounting
Principles Board Opinion No. 25, Accounting for Stock Issued to Employees.
Accordingly, compensation expense is not recognized for stock options unless the
options are granted at an exercise price lower than the market price on the
grant date. Note 17 contains information regarding our common stock option and
purchase plans.
(Q) TRANSACTIONS WITH RELATED PARTIES
We account for our investment in Kinder Morgan Energy Partners (among other
entities) under the equity method of accounting. In each accounting period, we
record our share of these investees' earnings, and amortize any "excess"
investment. We adjust the amount of our excess investment when an equity method
investee or a consolidated subsidiary issues additional equity (or reacquires
equity shares) in any manner that alters our ownership percentage. Differences
between the per unit sales proceeds from these equity issuances (or
reacquisitions) and our underlying book basis, as well as the pro rata portion
of the excess investment (including associated deferred taxes), are recorded
directly to paid-in capital rather than
58
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
being recognized as gains or losses. Three such transactions are described in
Note 6. If incremental equity is received in conjunction with sales of assets to
equity method investees, gains and losses are not recognized to the extent of
the interest retained in the assets transferred.
The Notes Receivable and Accounts Receivable related party balances consist
primarily of advances to Horizon Pipeline Company, an enterprise we jointly own
with Nicor, Inc.; see Note 6. The Note Receivable from Horizon Pipeline Company
is expected to be repaid in part and replaced with an equity investment when
Horizon completes its long-term financing in 2002. The Accounts Receivable from
Horizon relates to construction costs that were reimbursed to us in January
2002. The Accounts Payable related party balance is primarily payable to Kinder
Morgan Energy Partners for amounts arising from performing administrative
functions for them, including cash management, hedging activities, centralized
payroll and employee benefits services and expenses incurred in performing as
general partner of Kinder Morgan Energy Partners. The net monthly balance
payable or receivable from these activities is settled in cash in the following
month.
The caption "Gas Purchases and Other Costs of Sales" in the accompanying
Consolidated Statements of Operations includes related-party costs totaling
$47.4 million, $22.2 million and $0.6 million for the years 2001, 2000 and 1999,
respectively, primarily for natural gas transportation and storage services and
natural gas provided by entities owned by Kinder Morgan Energy Partners.
(R) ACCOUNTING FOR RISK MANAGEMENT ACTIVITIES
We utilize energy derivatives for the purpose of mitigating our risk
resulting from fluctuations in the market price of natural gas and associated
transportation. Prior to December 31, 2000, our accounting policy for these
activities was based on a number of authoritative pronouncements including SFAS
No. 80, Accounting for Futures Contracts. This policy is described in detail in
Note 15, as is our new policy, which is based on SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities, which became effective for us on
January 1, 2001.
(S) INCOME TAXES
Deferred income tax assets and liabilities are recognized for temporary
differences between the basis of assets and liabilities for financial reporting
and tax purposes. Changes in tax legislation are included in the relevant
computations in the period in which such changes are effective. Deferred tax
assets are reduced by a valuation allowance for the amount of any tax benefit we
do not expect to be realized. Note 12 contains information about our income
taxes, including the components of our income tax provision and the composition
of our deferred income tax assets and liabilities.
2. KINDER MORGAN MANAGEMENT, LLC
In May 2001, Kinder Morgan Management, LLC, one of our indirect
subsidiaries, issued and sold its limited liability shares in an underwritten
initial public offering. The net proceeds from the offering were used by Kinder
Morgan Management to buy i-units from Kinder Morgan Energy Partners for $991.9
million. Upon purchase of the i-units, Kinder Morgan Management became a partner
in Kinder Morgan Energy Partners and was delegated by Kinder Morgan Energy
Partners' general partner the responsibility to manage and control the business
and affairs of Kinder Morgan Energy Partners. The i-units are a class of Kinder
Morgan Energy Partners' limited partner interests that have been, and will be,
issued only to Kinder Morgan Management. We have certain rights and obligations
with respect to these securities, including an obligation to purchase the Kinder
Morgan Management shares or exchange them for Kinder Morgan Energy Partners'
common units we own or cash as discussed following.
In the initial public offering, Kinder Morgan Management issued a total of
14,875,000 shares, of which 1,487,500 shares (29,750,000 and 2,975,000 shares
respectively, after adjustment for the stock split described following) were
purchased by Kinder Morgan, Inc. (utilizing incremental short-term
59
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
borrowings), with the balance purchased by the public. The equity interest in
Kinder Morgan Management (our consolidated subsidiary) purchased by the public
created a minority interest on our balance sheet of $892.7 million at the time
of the transaction.
On July 18, 2001, Kinder Morgan Energy Partners announced a two-for-one
split of its common units. The common unit split, in the form of a
one-common-unit distribution for each common unit outstanding, occurred on
August 31, 2001. This split resulted in Kinder Morgan, Inc. receiving one
additional common unit for each common unit it owned and Kinder Morgan
Management receiving one additional i-unit for each i-unit it owned. Also on
July 18, 2001, Kinder Morgan Management announced a two-for-one split of its
shares. This share split, in the form of a one-share distribution for each share
outstanding, occurred on August 31, 2001.
Holders of Kinder Morgan Management shares may exchange each of their
shares for one common unit of Kinder Morgan Energy Partners owned by us or our
affiliates. This exchange feature is subject to our right to settle the exchange
in cash rather than common units. It was intended and expected that these
securities would trade within a narrow range. During the period the Kinder
Morgan Management shares have been outstanding, the difference between the
market price of the Kinder Morgan Management shares and the Kinder Morgan Energy
Partners common units has been minimal and, in recent periods, the Kinder Morgan
Management shares have traded at a slight premium to Kinder Morgan Energy
Partners common units. Accordingly, the exchange feature does not represent a
significant financial asset to the holder. As of December 31, 2001,
approximately 2.8 million Kinder Morgan Management shares (after adjustment for
the stock split as discussed preceding) had been exchanged for Kinder Morgan
Energy Partners' common units. As a result of these exchanges, at December 31,
2001, Kinder Morgan, Inc. owned approximately 6.0 million (19.4%) of Kinder
Morgan Management's outstanding shares. Our income statement is not affected by
these exchanges, which are taxable events for income tax purposes. The impacts
on our balance sheet are a decrease in minority interest and a change in paid-in
capital equal to the difference between the book value of the minority interest
associated with the Kinder Morgan Management shares received in the exchange and
the book value of the Kinder Morgan Energy Partners' units surrendered, net of
the associated tax liability. Through December 31, 2001, these exchanges have
increased our paid-in capital by approximately $15.7 million.
On January 17, 2002, Kinder Morgan Management announced that its board of
directors had approved a share distribution equal to $0.55 per share payable on
February 14, 2002 to its shareholders of record as of January 31, 2002. This
distribution was paid in the form of additional shares based on the average
market price of a share determined for a ten-trading day period ending on the
trading day immediately prior to the ex-dividend date for the shares.
3. BUSINESS COMBINATIONS
On October 7, 1999, we completed the acquisition of Kinder Morgan Delaware,
the sole stockholder of the general partner of Kinder Morgan Energy Partners.
Additional information on the assets and operations of Kinder Morgan Energy
Partners is contained in Notes 1 and 20.
To effect the business combination, we issued approximately 41.5 million
shares of our common stock in exchange for all of the outstanding shares of
Kinder Morgan Delaware. Upon closing of the transaction, Richard D. Kinder,
Chairman and Chief Executive Officer of Kinder Morgan Delaware, was named our
Chairman and Chief Executive Officer, and we were renamed Kinder Morgan, Inc.
This acquisition was accounted for as a purchase for accounting purposes
and, accordingly, the assets acquired and liabilities assumed were recorded at
their respective estimated fair market values as of the
60
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
acquisition date. The calculation of the total purchase price and the allocation
of that purchase price to the assets acquired and liabilities assumed based on
their fair market values is shown following:
(MILLIONS OF DOLLARS)
Purchase Price:
Kinder Morgan, Inc. Common Stock Issued................... $ 679
Transaction Fees.......................................... 8
------
Total.................................................. $ 687
======
The Purchase Price was Allocated as Follows:
Investment in Kinder Morgan Energy Partners............... $1,336
Cash and Cash Equivalents................................. 1
Accounts Receivable....................................... 9
Prepayments and Other Current Assets...................... 4
Deferred Charges.......................................... 1
Note Payable Assumed...................................... (149)
Deferred Income Taxes..................................... (503)
Accounts Payable and Accrued Liabilities Assumed.......... (12)
------
Total.................................................. $ 687
======
The allocation of the purchase price resulted in an excess of the purchase
price over Kinder Morgan Delaware's share of the underlying equity in the net
assets of Kinder Morgan Energy Partners totaling $1.3 billion. This excess has
been fully allocated to the Kinder Morgan Delaware investment in Kinder Morgan
Energy Partners and reflects the estimated fair market value of this investment
at the date of acquisition. This excess investment is being amortized over 44
years, approximately the estimated remaining useful life of Kinder Morgan Energy
Partners' assets, and is shown in the accompanying Consolidated Income
Statements as "Amortization of Excess Investment" under the sub-heading "Kinder
Morgan Energy Partners" within "Other Income and (Expenses)." This amortization
will be discontinued in 2002 as a result of the provisions of SFAS No. 142,
Goodwill and Other Intangible Assets, which were effective as of January 1,
2002. The assets, liabilities and results of operations of Kinder Morgan
Delaware are included with those of Kinder Morgan beginning with the October 7,
1999 acquisition date.
The following pro forma information gives effect to our acquisition of
Kinder Morgan Delaware as if the business combination had occurred January 1,
1999. This unaudited pro forma information should be read in conjunction with
the accompanying consolidated financial statements. This pro forma information
does not necessarily indicate the financial results that would have occurred if
this acquisition had taken place on January 1, 1999, nor should it necessarily
be viewed as an indicator of future financial results.
UNAUDITED PRO FORMA FINANCIAL INFORMATION
YEAR ENDED
DECEMBER 31, 1999
--------------------
(DOLLARS IN MILLIONS
EXCEPT PER SHARE
AMOUNTS)
Operating Revenues.......................................... $1,745.5
Net Loss.................................................... $ (233.9)
Loss Per Diluted Common Share............................... $ (2.09)
Number of Shares Used in Computing Loss Per Diluted Common
Share (In Thousands)...................................... 112,334
61
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
On February 22, 1999, Sempra Energy and we announced that our respective
boards of directors had unanimously approved a definitive agreement under which
Sempra and we would combine in a stock-and-cash transaction valued in the
aggregate at $6.0 billion. On June 21, 1999, Sempra and we announced that we had
mutually agreed to terminate the merger agreement. Sempra reimbursed us $5.95
million for expenses incurred in connection with the proposed merger.
4. MERGER-RELATED AND SEVERANCE COSTS
In anticipation of the completion of the transaction with Kinder Morgan
Delaware, during the third quarter of 1999, a number of our officers terminated
their employment with us, as did certain other employees. In addition, we
terminated the employment of a number of additional employees during the fourth
quarter of 1999 and in early 2000 as a result of cost saving initiatives
implemented following the closing of the Kinder Morgan Delaware transaction. In
total, approximately 150 employees were severed. In conjunction with these
terminations, we agreed to provide severance benefits and incurred certain legal
and other associated costs. Also in conjunction with the Kinder Morgan Delaware
transaction, we elected to discontinue certain projects, consolidate certain
facilities and relocate certain employees. The $37.4 million pre-tax expense
($23.6 million after tax or $0.29 per diluted share) associated with these
matters (included in the accompanying Consolidated Statement of Operations for
1999 under the caption "Merger-related and Severance Costs") was composed of the
following: (i) severance and relocation, including restricted stock -- $22.7
million, (ii) facilities costs, including moving expenses -- $5.3 million, (iii)
write-down/write-off of project costs -- $8.0 million and (iv) other -- $1.4
million. Of this total, approximately $9.4 million remained as an accrual at
December 31, 1999, all of which was expended during the first half of 2000.
5. CHANGE IN ACCOUNTING ESTIMATE
Pursuant to a revised study of the useful lives of the underlying assets by
an independent third party, in July 1999, we changed the depreciation rates
associated with the gas plant acquisition adjustment recorded in conjunction
with the acquisition of MidCon Corp. Relative to the amounts which would have
been recorded utilizing the previous depreciation rates, this change had the
effect of decreasing "Depreciation and Amortization" by approximately $19.3
million for the year ended December 31, 1999. Consequently, "Income from
Continuing Operations" and "Net Income" were increased by approximately $12.1
million for the year ended December 31, 1999 ($0.15 per diluted common share).
6. INVESTMENTS AND SALES
On December 28, 2001, we completed the previously announced sale of certain
assets in the Wattenberg field area of the Denver-Julesberg Basin to Kerr-McGee
Gathering LLC (formerly HS Resources, Inc.). Under terms of agreements with
them, Kerr-McGee Gathering LLC has operated these assets since December 1999 and
made monthly payments to us until the sale of assets was completed. We recorded
a pre-tax loss of $22.1 million (approximately $13.3 million after tax or $0.11
per diluted share) in conjunction with this sale, shown in the caption "Other
Net" in the accompanying Consolidated Statement of Operations for 2001.
Effective December 1, 2001, we purchased natural gas distribution assets
from Citizens Communications Company (NYSE: CZN) for approximately $11 million
in cash and assumed liabilities. The natural gas distribution assets serve
approximately 13,400 residential, commercial and agricultural customers in Bent,
Crowley, Otero, Archuleta, La Plata and Mineral Counties in Colorado. On October
31, 2001, the Colorado Public Utilities Commission approved this transaction.
On November 5, 2001, the Horizon Pipeline Company announced that
construction has started on its new $79 million natural gas pipeline in northern
Illinois. Horizon Pipeline is a joint venture of Nicor-Horizon, a subsidiary of
Nicor Inc. (NYSE: GAS), and Natural Gas Pipeline Company of America.
62
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Completion of the entire project is projected for April 2002. The action
allowing work to get under way included a confirmation from the Federal Energy
Regulatory Commission that Horizon Pipeline was in compliance with
pre-construction conditions of the original certificate of public convenience
and necessity issued in July 2001.
The Horizon natural gas pipeline entails the new construction of 27 miles
of 36-inch diameter pipeline, the lease of capacity in 46 miles of existing
pipeline from Natural Gas Pipeline Company of America, and the installation of
gas compression facilities. Upon completion of the project, Horizon Pipeline
will be able to transport 380 million cubic feet of natural gas per day from
near Joliet into McHenry County, connecting the emerging supply hub at Joliet
with the northern part of the Nicor natural gas distribution system and the
existing Natural Gas Pipeline Company of America pipeline system.
In May 2001, Kinder Morgan Energy Partners issued i-units in conjunction
with the Kinder Morgan Management initial public offering of its shares to the
public. This issuance of i-units reduced our percentage ownership of Kinder
Morgan Energy Partners from approximately 22.7 percent to approximately 20.8
percent and had the associated effects of increasing (i) our investment in the
net assets of Kinder Morgan Energy Partners by $145.1 million, (ii) associated
accumulated deferred income taxes by $18.9 million and (iii) paid-in capital by
$28.3 million and reducing (i) our excess investment in Kinder Morgan Energy
Partners by $97.9 million and (ii) the monthly amortization of the excess
investment by $192 thousand; see Notes 1(Q) and 2.
In December 2000, we transferred approximately $300 million of assets to
Kinder Morgan Energy Partners effective December 31, 2000. The largest asset we
transferred was our wholly owned subsidiary Kinder Morgan Texas Pipeline, L.P.
and certain associated entities (the lessee a major intrastate natural gas
pipeline system). We also transferred the Douglas and Casper gas processing
facilities and associated natural gas gathering systems, our 50 percent interest
in Coyote Gas Treating, LLC and our 25 percent interest in Thunder Creek Gas
Services, L.L.C. As consideration for the transfer, we received approximately
$150 million in cash (with an additional cash payment for working capital), 1.3
million Kinder Morgan Energy Partners' common limited partner units and 5.3
million Class-B Kinder Morgan Energy Partners' limited partner units. At
December 31, 2000, we recorded a pre-tax gain of $61.6 million (approximately
$37.0 million after tax or $0.32 per diluted share) in conjunction with this
sale. During 2001, we made a final working capital adjustment associated with
this transfer, and reduced our provision for exposure under an indemnification
provision of the contribution agreement, resulting in positive pre-tax
adjustments of $17.0 million (approximately $10.2 million after tax or $0.08 per
diluted share) and $9.9 million (approximately $5.9 million after tax or $0.05
per diluted share), in each case adjusted for our continuing interest in the
assets transferred.
In May and August of 2000, Kinder Morgan Power announced plans to construct
550-megawatt power generation facilities in Wrightsville, Arkansas and Jackson,
Michigan, respectively. These plants are currently under construction, with
completion on both facilities expected by mid-2002. Kinder Morgan Power has
contracted to operate the facility in Jackson, Michigan. Kinder Morgan Power
does not own either facility, but has an investment in them as discussed in
Notes 1 and 18.
In April 2000, Kinder Morgan Energy Partners issued 9.0 million common
units in a public offering at a price of $39.75 per common unit, receiving total
net proceeds (after underwriting discount) of $171.3 million. We did not acquire
any of these common units. This transaction reduced our then percentage
ownership of Kinder Morgan Energy Partners from approximately 19.9% to
approximately 18.6% and had the associated effects of increasing our investment
in the net assets of Kinder Morgan Energy Partners by $6.1 million and reducing
(i) our excess investment in Kinder Morgan Energy Partners by $81.1 million,
(ii) associated accumulated deferred income taxes by $30.0 million, (iii)
paid-in capital by $45.0 million and (iv) our monthly amortization of the excess
investment by approximately $176 thousand. In February 2000, Kinder Morgan
Energy Partners issued 1.1 million common units,
63
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
assumed approximately $7.0 million in liabilities and paid $0.8 million in cash
as consideration for acquiring all the capital stock of Milwaukee Bulk
Terminals, Inc. and Dakota Bulk Terminal, Inc. This transaction reduced our
percentage ownership of Kinder Morgan Energy Partners and had the associated
effects of increasing our investment in the net assets of Kinder Morgan Energy
Partners by $1.1 million and reducing (i) our excess investment in Kinder Morgan
Energy Partners by $11.3 million, (ii) associated accumulated deferred income
taxes by $4.1 million, (iii) paid-in capital by $6.1 million and (iv) the
monthly amortization of the excess investment by approximately $21 thousand; see
Notes 1(Q) and 3.
In March 2000, we sold the 918,367 shares of Tom Brown, Inc. common stock
we had held since early 1996 (see the discussion of the sale of Tom Brown
preferred stock following). We recorded a pre-tax gain of $1.4 million ($0.8
million after tax or approximately $0.01 per diluted common share) in
conjunction with the sale.
On December 30, 1999, we entered into an agreement with several of our
wholly owned subsidiaries and Kinder Morgan Energy Partners. As a result,
effective as of December 31, 1999, we transferred all of our interests in the
following to Kinder Morgan Energy Partners: (i) our wholly owned subsidiary,
Kinder Morgan Interstate Gas Transmission LLC (formerly K N Interstate Gas
Transmission Co.), (ii) our wholly owned subsidiary, Kinder Morgan Trailblazer
LLC (formerly NGPL-Trailblazer, Inc.), which owns a one-third interest in
Trailblazer Pipeline Company and (iii) our 49% interest in Red Cedar Gathering
Company. In exchange, Kinder Morgan Energy Partners issued to us 19.6 million
common units representing limited partnership interest in Kinder Morgan Energy
Partners. In addition, Kinder Morgan Energy Partners paid us $330 million in
cash in early 2000. We recorded a pre-tax gain of $127.0 million (approximately
$80.7 million after tax or $1.00 per diluted common share) in conjunction with
the transfer of these interests.
On September 30, 1999, we sold (to an unaffiliated party) our interests in
Stingray Pipeline Company, L.L.C., an offshore pipeline that gathers natural
gas, and West Cameron Dehydration Company, L.L.C., which dehydrates natural gas
for shippers on the Stingray Pipeline. On June 30, 1999, we sold our interests
in the HIOS and UTOS offshore pipeline systems and related laterals to Leviathan
Gas Pipeline Partners, L. P. These two sales yielded total cash proceeds of
approximately $75.1 million, resulted in a total pre-tax gain of approximately
$28.9 million (approximately $17.6 million after tax or $0.25 per diluted
share), and substantially eliminated our investment in offshore assets.
On September 3, 1999, we sold 1,000,000 shares of preferred stock of Tom
Brown, Inc. for approximately $29 million in cash. We recorded a pre-tax gain of
$2.2 million (approximately $1.3 million after tax or $0.02 per diluted share)
in conjunction with the sale.
On March 31, 1999, the TransColorado Gas Transmission Company
("TransColorado"), an enterprise we jointly own with Questar Corp., placed in
service a 280-mile-long natural gas pipeline. This pipeline includes two
compressor stations and extends from near Rangely, Colorado, to its southern
terminus at the Blanco Hub near Aztec, New Mexico. The pipeline has a design
transmission capacity of approximately 300 million cubic feet of natural gas per
day. Beginning 24 months after the in-service date, Questar has the right, for a
12-month period, to require that we purchase Questar's ownership interest in
TransColorado for $121 million. This right has been stayed; see Note 10.
See Note 7 for information regarding sales of assets and businesses
included in discontinued operations.
7. DISCONTINUED OPERATIONS
Prior to mid-1999, we had major business operations in the upstream
(gathering and processing), midstream (natural gas pipelines) and downstream
(wholesale and retail marketing) portions of the natural gas industry and, in
addition, had (i) non-energy retail marketing operations in the form of a joint
64
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
venture called EN -- able and (ii) limited international operations. During the
third quarter of 1999, we adopted a plan to discontinue the direct marketing of
non-energy products and services (principally under the "Simple Choice" brand).
During the fourth quarter of 1999 and following our merger with Kinder Morgan
Delaware, we adopted and implemented plans to discontinue the following lines of
business: (i) gathering and processing natural gas, including short-haul
intrastate pipelines and providing field services to natural gas producers, (ii)
wholesale marketing of natural gas and natural gas liquids, and (iii)
international operations, which we subsequently decided to retain as discussed
following.
In accordance with the provisions of Accounting Principles Board Opinion
No. 30, Reporting the Results of Operations -- Reporting the Effects of Disposal
of a Segment of a Business, and Extraordinary, Unusual and Infrequently
Occurring Events and Transactions ("APB 30"), our consolidated financial
statements have been restated to present these businesses as discontinued
operations. Accordingly, the revenues, costs and expenses, assets and
liabilities and cash flows of these discontinued operations have been excluded
from the respective captions in the accompanying Consolidated Statements of
Operations and Consolidated Statements of Cash Flows, and have been reported in
the various statements under the captions "Loss from Discontinued Operations,
Net of Tax"; "Loss on Disposal of Discontinued Operations, Net of Tax"; "Net
Cash Flows Provided by (Used in) Discontinued Operations" and "Net Cash Flows
Provided by (Used in) Discontinued Investing Activities" for all relevant
periods. In addition, certain of these Notes have been restated for all relevant
periods to reflect the discontinuance of these operations.
During the fourth quarter of 2000, we decided that, due to the start-up
nature of these operations and the unwillingness of buyers to pay for the value
created to date, it was not in the best interests of the Company to dispose of
our international operations, which consist principally of a natural gas
distribution system under development in Hermosillo, Mexico. Consequently,
results from our international operations have been reclassified to continuing
operations for all periods presented. The $3.9 million estimated after-tax loss
on disposal recorded in 1999, consisting principally of a write down to
estimated net realizable value including estimated costs of disposal, was
reversed in 2000 and is included under the caption "Loss on Disposal of
Discontinued Operations" in the accompanying Consolidated Statements of
Operations. The following table contains additional information concerning our
international operations.
INTERNATIONAL OPERATIONS
YEAR ENDED DECEMBER 31,
-----------------------
2000 1999
--------- ---------
(THOUSANDS OF DOLLARS)
Total Assets (at December 31)............................... $32,347 $25,325
Total Liabilities (at December 31).......................... $ 3,984 $ 29
Operating Revenues.......................................... $ 5,699 $ 1,129
Operating Loss.............................................. $ 2,071 $ 2,523
65
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Summarized financial data of discontinued operations are as follows:
YEAR ENDED DECEMBER 31,
-----------------------
INCOME STATEMENT DATA 2000 1999
--------------------- --------- -----------
(IN THOUSANDS)
Operating Revenues:
Wholesale Natural Gas and Liquids Marketing............... $580,159 $3,550,568
Gathering and Processing, Including Field Services and
Short-haul Intrastate Pipelines........................ $436,979 $ 630,005
Loss From Discontinued Operations, Net of Tax:
Wholesale Marketing, Net of Tax Benefits of $9,300..... $ (15,046)
Gathering and Processing, Net of Tax Benefits of
$18,177.............................................. $ (29,404)
EN -- able/Orcom, Net of Tax Benefits of $4,150........ $ (6,491)
Loss on Disposal of Discontinued Operations, Net of Tax:
Wholesale Marketing, Net of Tax Benefits of $2,013 and
$34,588.............................................. $ (3,013) $ (55,780)
Gathering and Processing, Net of Tax Benefits of
$21,617 and $169,413................................. $(32,638) $ (273,202)
EN -- able/Orcom, Net of Tax Benefits of $7,340........ $ (11,479)
International Operations, Net of $2,430 of Tax and
$2,430 of Tax Benefits............................... $ 3,917 $ (3,917)
With the exception of our international operations, which, as discussed
above, we decided to retain, we completed the divestiture of our discontinued
operations by December 31, 2000. In the fourth quarter of 2000, we recorded an
incremental loss on disposal of discontinued operations of $31.7 million,
representing the impact of the final disposition transactions and adjustment of
previously recorded estimates. We had a remaining liability of approximately
$5.2 million at December 31, 2001 associated with these discontinued operations,
principally consisting of indemnification obligations under the various sale
agreements. Following is additional information concerning the various
disposition transactions.
We completed the disposition of our investment in EN -- able and sold our
businesses involved in providing field services to natural gas producers (K N
Field Services, Inc. and Compressor Pump and Engine, Inc.) and MidCon Gas
Products of New Mexico Corp., a wholly owned subsidiary providing natural gas
gathering and processing services, prior to the end of 1999. We received $23.3
million in cash as consideration for these sales.
Effective March 1, 2000, ONEOK purchased (i) our gathering and processing
businesses in Oklahoma, Kansas and West Texas, (ii) our marketing and trading
business and (iii) certain storage, gathering and transmission pipelines in the
Mid-continent region. As consideration, ONEOK paid us approximately $108 million
plus approximately $56 million for estimated net working capital at closing. In
addition, ONEOK assumed (i) the operating lease associated with the Bushton,
Kansas processing plant (although we remain secondarily liable as discussed in
Note 18) and (ii) long-term throughput capacity commitments on Natural Gas
Pipeline Company of America and Kinder Morgan Interstate.
During the second quarter of 2000, we completed the sale of three natural
gas gathering systems and a natural gas processing facility to WBI Holdings,
Inc., the natural gas pipeline unit of MDU Resources Group, Inc. for
approximately $21 million. Gathering systems included in the sale were the
Bowdoin System located in north-central Montana, the Niobrara System located in
northeastern Colorado and northwestern Kansas, and the Yenter System located in
northeastern Colorado and western Nebraska. The natural gas processing facility
included in the sale was the Yenter Plant, located northwest of Sterling,
Colorado.
66
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
During the fourth quarter of 2000, Wildhorse Energy Partners, LLC
distributed all of its assets to its members and ended its operations. Formed in
1996, Wildhorse was owned 55 percent by us and 45 percent by Tom Brown, Inc. All
the Wildhorse gathering and processing assets were distributed to Tom Brown and
we received the Wolf Creek storage facility (which will be utilized in our
natural gas distribution business) and cash. Also during the fourth quarter of
2000, our Douglas and Casper gas processing facilities and associated natural
gas gathering systems, our 50 percent interest in Coyote Gas Treating, LLC and
our 25 percent interest in Thunder Creek Gas Services, L.L.C. were included as
part of a larger transaction with Kinder Morgan Energy Partners; see Note 6.
8. ACCOUNTS RECEIVABLE SALES FACILITY
In September 1999, certain of our wholly owned subsidiaries entered into a
five-year agreement to sell all of their accounts receivable, on a revolving
basis, to K N Receivables Corporation, our wholly owned subsidiary. K N
Receivables was formed prior to the execution of that receivables agreement for
the purpose of buying and selling accounts receivable and was determined to be
bankruptcy remote. Also in September 1999, K N Receivables entered into a
five-year agreement with a financial institution whereby K N Receivables could
sell, on a revolving basis, an undivided percentage ownership interest in
certain eligible accounts receivable, as defined, up to a maximum of $150
million. This transaction was accounted for as a sale of receivables. Losses
from the sale of these receivables are included in "Other, Net" in the
accompanying Consolidated Statements of Operations during the periods in which
the facility was utilized. We received compensation for servicing that was
approximately equal to the amount an independent servicer would receive.
Accordingly, no servicing assets or liabilities were recorded. The full amount
of the allowance for possible losses was retained by K N Receivables. The fair
value of this recourse liability approximated the allocated allowance for
doubtful accounts given the short-term nature of the transferred receivables.
We received $150 million in proceeds from the sale of receivables in 1999.
The proceeds were used to retire notes payable of Kinder Morgan Delaware that
were outstanding when we acquired it. In 2000 we repaid $150 million and
terminated the agreement. Cash flows associated with this program are included
with "Accounts Receivable" under "Cash Flows from Operating Activities" in the
accompanying Statements of Consolidated Cash Flows for 1999 and 2000.
9. REGULATORY MATTERS
On July 17, 2000, Natural Gas Pipeline Company of America filed its
compliance plan, including pro forma tariff sheets, pursuant to the FERC's Order
Nos. 637 and 637-A. The FERC directed all interstate pipelines to file pro forma
tariff sheets to comply with new regulatory requirements in the Orders regarding
scheduling procedures, capacity segmentation, imbalance management services and
penalty credits, or in the alternative, to explain why no changes to existing
tariff provisions are necessary. A technical conference was held on July 10,
2001 to discuss Natural Gas Pipeline Company of America's Order 637 filing.
Parties have filed comments on Natural Gas Pipeline Company of America's filing
and all parties are awaiting the FERC's decision. Numerous issues regarding
Order Nos. 637, 637-A and 637-B are on appeal in the Court of Appeals for the
District of Columbia. Briefing has been completed and the oral argument was held
on November 29, 2001.
Currently, there are no material proceedings challenging the rates on any
of our pipeline systems. Nonetheless, shippers on our pipelines do have rights
to challenge the rates we charge under certain circumstances prescribed by
applicable regulations. There can be no assurance that we will not face
challenges to the rates we receive for services on our pipeline systems in the
future.
67
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
10. ENVIRONMENTAL AND LEGAL MATTERS
(A) ENVIRONMENTAL MATTERS
We have an established environmental reserve of approximately $18 million,
excluding any cost of remediation described below, at December 31, 2001 to
address remediation issues associated with approximately 35 projects. After
consideration of reserves established, we believe that costs for environmental
remediation and ongoing compliance with these regulations will not have a
material adverse effect on our cash flows, financial position or results of
operations or diminish our ability to operate our businesses. However, there can
be no assurances that future events, such as changes in existing laws, the
promulgation of new laws, or the development of new facts or conditions will not
cause us to incur significant costs.
(B) LITIGATION MATTERS
K N TransColorado, Inc. v. TransColorado Gas Transmission Company, et. al,
Case No. 00-CV-129, District Court, County of Garfield, State of Colorado. On
June 15, 2000, K N TransColorado filed suit against Questar TransColorado, its
parent Questar Pipeline Company, and other affiliated Questar entities,
asserting claims for breach of fiduciary duties, breach of contract,
constructive trust, rescission of the partnership agreement, breach of good
faith and fair dealing, tortious concealment, misrepresentation, aiding and
abetting a breach of fiduciary duty, dissolution of the TransColorado
partnership, and seeking a declaratory judgment, among other claims. The
TransColorado partnership has been made a defendant for purposes of an
accounting. The lawsuit alleges, among other things, Questar breached its
fiduciary duties as a partner. K N TransColorado seeks to recover damages in
excess of $152 million due to Questar's breaches and, in addition, seeks
punitive damages. In response to the complaint, on July 28, 2000, the Questar
entities filed a counterclaim and third party claims against Kinder Morgan and
certain of its affiliates for claims arising out of the construction and
operation of the TransColorado pipeline project. The claims allege, among other
things, that the Kinder Morgan entities interfered with and delayed construction
of the pipeline and made misrepresentations about marketing of capacity. The
Questar entities seek to recover damages in excess of $185 million for an
alleged breach of fiduciary duty and other claims. The parties agreed to stay
the exercise of a contractual provision purportedly requiring K N TransColorado
to purchase Questar's interest in the pipeline and to investigate the
appointment of an independent operator for the pipeline during the litigation.
The Court dismissed Questar's counterclaims for breach of duty of good faith and
fair dealing and for indemnity and contribution and dismissed Questar's Third
Party Complaint. On July 19, 2001, the Court granted K N TransColorado's motion
for summary judgment that: a) fiduciary duties existed between the partners; b)
these fiduciary duties were not modified or waived; and c) the affiliates and
directors of Questar Pipeline Company and Questar TransColorado acting in their
dual capacity had fiduciary obligations which required those individuals to
disclose, to the partnership and the partners, information that affected the
fundamental business purpose of the partnership. On August 14, 2001, the Court
granted leave to Questar to file its First Amended Answer and Counterclaim, once
again naming Kinder Morgan, Inc. as a counterclaim defendant, and making similar
allegations against us as set forth above. Fact discovery and expert discovery
have closed. The case is set for trial on April 1, 2002.
Jack J. Grynberg, individually and as general partner for the Greater Green
River Basin Drilling Program: 72-73 v. Rocky Mountain Natural Gas Company and K
N Energy, Inc., Case No. 90-CV-3686. On June 5, 1990, Jack J. Grynberg filed
suit, which is presently pending in Jefferson County District Court for
Colorado, against Rocky Mountain Natural Gas Company and us alleging breach of
contract and fraud. In essence, Grynberg asserts claims that the named companies
failed to pay Grynberg the proper price, impeded the flow of natural gas,
mismeasured natural gas, delayed his development of natural gas reserves, and
other claims arising out of a contract to purchase natural gas from a field in
northwest Colorado. On February 13, 1997, the trial judge entered partial
summary judgment for Grynberg on his contract claim that he failed to receive
the proper price for his natural gas. This ruling followed an appellate decision
that was adverse to us on the contract interpretation of the price issue, but
which did
68
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
not address the question of whether Grynberg could legally receive the price he
claimed or whether he had illegally diverted natural gas from a prior purchase.
Grynberg has previously claimed damages in excess of $30 million. On August 29,
1997, the trial judge stayed the summary judgment pending resolution of a
proceeding at the FERC to determine if Grynberg was entitled to administrative
relief from an earlier dedication of the same natural gas to interstate
commerce. On March 15, 1999, an Administrative Law Judge for the FERC ruled,
after an evidentiary hearing, that Mr. Grynberg had illegally diverted the
natural gas when he entered the contract with the named companies and was not
entitled to relief. Grynberg filed exceptions to this ruling. In late March
2000, the FERC issued an order affirming in part and denying in part the motions
for rehearing of its Initial Decision. On November 21, 2000, the FERC upheld the
Administrative Law Judge's factual findings and denial of retroactive
abandonment. On June 14, 2001, Rocky Mountain Natural Gas Company filed a motion
for Summary Judgment and To Vacate the February 13, 1997, Partial Summary
Judgment, as a result of the conclusion of the FERC proceedings. On August 16,
2001, the Court granted Plaintiff's Motion to Continue the Stay of these
proceedings pending the proceedings in federal court. The parties have reached a
settlement in principle of this matter and the federal court matter. The
settlement is conditioned on certain findings by a Special Master.
Jack J. Grynberg v. K N Energy, Inc., Rocky Mountain Natural Gas Company,
and GASCO, Inc., Civil Action No. 92-N-2000. On October 9, 1992, Jack J.
Grynberg filed suit in the United States District Court for the District of
Colorado against us, Rocky Mountain Natural Gas Company and GASCO, Inc. alleging
that these entities, the K N Entities, as well as K N Production Company and K N
Gas Gathering, Inc., have violated federal and state antitrust laws. In essence,
Grynberg asserts that the companies have engaged in an illegal exercise of
monopoly power, have illegally denied him economically feasible access to
essential facilities to store, transport and distribute gas, and illegally have
attempted to monopolize or to enhance or maintain an existing monopoly. Grynberg
also asserts certain state causes of action relating to a gas purchase contract.
In February 1999, the Federal District Court granted summary judgment for the K
N Entities as to some of Grynberg's antitrust and state law claims, while
allowing other claims to proceed to trial. Grynberg has previously claimed
damages in excess of $50 million. In addition to monetary damages, Grynberg has
requested that the K N Entities be ordered to divest all interests in natural
gas exploration, development and production properties, all interests in
distribution and marketing operations, and all interests in natural gas storage
facilities, in order to separate these interests from our natural gas gathering
and transportation system in northwest Colorado. The parties have reached a
settlement in principle of this matter and the state court matter. The court has
ordered that the settlement be finalized by March 15, 2002, or the federal case
will proceed to trial. The settlement is conditioned on certain findings by a
Special Master.
United States of America, ex rel., Jack J. Grynberg v. K N Energy, Civil
Action No. 97-D-1233, filed in the U.S. District Court, District of Colorado.
This action was filed on June 9, 1997 pursuant to the federal False Claim Act
and involves allegations of mismeasurement of natural gas produced from federal
and Indian lands. The Department of Justice has decided not to intervene in
support of the action. The complaint is part of a larger series of similar
complaints filed by Mr. Grynberg against 77 natural gas pipelines (approximately
330 other defendants). An earlier single action making substantially similar
allegations against the pipeline industry was dismissed by Judge Hogan of the
U.S. District Court for the District of Columbia on grounds of improper joinder
and lack of jurisdiction. As a result, Mr. Grynberg filed individual complaints
in various courts throughout the country. These cases were recently consolidated
by the Judicial Panel for Multidistrict Litigation, and transferred to the
District of Wyoming. Motions to Dismiss were filed and an oral argument on the
Motion to Dismiss occurred on March 17, 2000. On July 20, 2000 the United States
of America filed a motion to dismiss those claims by Grynberg that deal with the
manner in which defendants valued gas produced from federal leases. Judge Downes
denied the defendant's motion to dismiss on May 18, 2001. The defendants have
sought reconsideration of this Order and have requested a status conference.
69
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Quinque Operating Company, et al. v. Gas Pipelines, et. al., Case No.
99-1390-CM, United States District Court for the District of Kansas. This action
was originally filed on May 28, 1999 in Kansas state court in Stevens County,
Kansas as a class action against approximately 245 pipeline companies and their
affiliates, including certain Kinder Morgan entities. The plaintiffs in the case
seek to have the Court certify the case as a class action, a class of natural
gas producers and fee royalty owners who allege that they have been subject to
systematic mismeasurement of natural gas by the defendants for more than 25
years. Among other things, the plaintiffs allege a conspiracy among the pipeline
industry to under-measure gas and have asserted joint and several liability
against the defendants. Subsequently, one of the defendants removed the action
to Kansas Federal District Court. Thereafter, we filed a motion with the
Judicial Panel for Multidistrict Litigation to consolidate this action for
pretrial purposes with the Grynberg False Claim Act cases referred to above,
because of common factual questions. On April 10, 2000, the MDL Panel ordered
that this case be consolidated with the Grynberg federal False Claims Act cases.
On January 12, 2001, the Federal District Court of Wyoming issued an oral ruling
remanding the case back to the State Court in Stevens County, Kansas. A case
management conference occurred in State Court in Stevens County, and a briefing
schedule was established for preliminary matters. Personal jurisdiction
discovery has commenced. Merits discovery has been stayed. Recently, the
defendants filed a motion to dismiss on grounds other than personal
jurisdiction, and a motion to dismiss for lack of personal jurisdiction for non-
resident defendants.
K N Energy, Inc., et al. v. James P. Rode and Patrick R. McDonald, Case No.
99CV1239, filed in the District Court, Jefferson County, Division 8, Colorado.
The case was filed on May 21, 1999. Defendants counterclaimed and filed third
party claims against several of our former officers and/or directors. Messrs.
Rode and McDonald are former principal shareholders of Interenergy Corporation.
We acquired Interenergy on December 19, 1997 pursuant to a Merger Agreement
dated August 25, 1997. Rode and McDonald allege that K N Energy committed
securities fraud, common law fraud and negligent misrepresentation as well as
breach in contract. Plaintiffs are seeking an unspecified amount of compensatory
damages, greater than $2 million, plus unspecified exemplary or punitive
damages, attorney's fees and their costs. We filed a motion to dismiss, and on
April 21, 2000, the Jefferson County District Court Judge dismissed the case
against the individuals and us with prejudice. On April 6, 2001, the Colorado
Court of Appeals affirmed the dismissal. Defendants also filed a federal
securities fraud action in the United States District Court for the District of
Colorado on January 27, 2000 titled: James P. Rode and Patrick R. McDonald v. K
N Energy, Inc., et al., Civil Action No. 00-N-190. This case initially raised
the identical state law claims contained in the counterclaim and third party
complaint in state court. Rode and McDonald filed an amended Complaint, which
dropped the state-law claims. On June 20, 2000, the federal district court
dismissed this Complaint with prejudice. Rode and McDonald filed notices of
appeal of the federal court dismissal. Briefing on this appeal is complete. A
third related class action case styled, Adams vs. Kinder Morgan, Inc., et al.,
Civil Action No. 00-M-516, in the United States District Court for the District
of Colorado was served on us on April 10, 2000. As of this date no class has
been certified. On February 23, 2001, the federal district court dismissed
several claims raised by the plaintiff, with prejudice, and dismissed the
remaining claims, without prejudice. On April 27, 2001, the Adams plaintiffs
filed their second amended complaint. We have moved to dismiss this complaint
and the briefing on the motion is complete. An oral argument on the motion to
dismiss is set for March 29, 2002.
We believe that we have meritorious defenses to all lawsuits and legal
proceedings in which we are defendants and will vigorously defend against them.
Based on our evaluation of the above matters, and after consideration of
reserves established, we believe that the resolution of such matters will not
have a material adverse effect on our businesses, cash flows, financial position
or results of operations.
70
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
11. PROPERTY, PLANT AND EQUIPMENT
Investments in property, plant and equipment ("PP&E"), at cost, and
accumulated depreciation and amortization ("Accumulated D&A") are as follows:
DECEMBER 31, 2001
------------------------------------------
PROPERTY, PLANT ACCUMULATED
AND EQUIPMENT D&A NET
--------------- ----------- ----------
(IN THOUSANDS)
Natural Gas Pipelines.......................... $5,613,578 $216,302 $5,397,276
Retail Natural Gas Distribution................ 285,674 101,520 184,154
Electric Power Generation...................... 23,087 3,228 19,859
General and Other.............................. 156,495 53,832 102,663
---------- -------- ----------
PP&E Related to Continuing Operations.......... $6,078,834 $374,882 $5,703,952
========== ======== ==========
DECEMBER 31, 2000
------------------------------------------
PROPERTY, PLANT ACCUMULATED
AND EQUIPMENT D&A NET
--------------- ----------- ----------
(IN THOUSANDS)
Natural Gas Pipelines.......................... $5,662,880 $262,073 $5,400,807
Retail Natural Gas Distribution................ 251,660 90,966 160,694
Electric Power Generation...................... 23,070 2,608 20,462
General and Other.............................. 142,773 56,745 86,028
---------- -------- ----------
PP&E Related to Continuing Operations.......... $6,080,383 $412,392 $5,667,991
========== ======== ==========
12. INCOME TAXES
Components of the income tax provision applicable to continuing operations
for federal and state income taxes are as follows:
YEAR ENDED DECEMBER 31,
-----------------------------
2001 2000 1999
-------- -------- -------
(DOLLARS IN THOUSANDS)
TAXES CURRENTLY PAYABLE:
Federal............................................. $ 3,729 $ 3,212 $19,340
State............................................... 25,917 14,091 13,784
-------- -------- -------
Total............................................... 29,646 17,303 33,124
-------- -------- -------
TAXES DEFERRED:
Federal............................................. 128,266 94,688 52,942
State............................................... 10,689 11,026 (6,942)
-------- -------- -------
138,955 105,714 46,000
-------- -------- -------
TOTAL TAX PROVISION................................... $168,601 $123,017 $79,124
======== ======== =======
EFFECTIVE TAX RATE.................................... 41.4% 40.0% 36.9%
======== ======== =======
71
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The difference between the statutory federal income tax rate and our
effective income tax rate is summarized as follows:
YEAR ENDED DECEMBER 31,
-----------------------
2001 2000 1999
----- ----- -----
FEDERAL INCOME TAX RATE..................................... 35.0% 35.0% 35.0%
INCREASE (DECREASE) AS A RESULT OF:
State Income Tax, Net of Federal Benefit.................. 5.7% 5.6% 1.9%
Kinder Morgan Management minority interest................ 1.4% -- --
Other..................................................... (0.7)% (0.6)% --
---- ---- ----
EFFECTIVE TAX RATE.......................................... 41.4% 40.0% 36.9%
==== ==== ====
Income taxes included in the financial statements were composed of the
following:
YEAR ENDED DECEMBER 31,
-------------------------------
2001 2000 1999
-------- -------- ---------
Continuing Operations............................... $168,601 $123,017 $ 79,124
Discontinued Operations............................. -- (21,200) (245,398)
Extraordinary Item.................................. (9,044) -- --
Cumulative Effect Transition Adjustment............. (7,922) -- --
Equity Items........................................ 43,866 (30,311) 568
-------- -------- ---------
Total............................................... $195,501 $ 71,506 $(165,706)
======== ======== =========
Deferred tax assets and liabilities result from the following:
DECEMBER 31,
-----------------------
2001 2000
---------- ----------
(DOLLARS IN THOUSANDS)
DEFERRED TAX ASSETS:
Postretirement Benefits................................... $ 15,133 $ 14,776
Gas Supply Realignment Deferred Receipts.................. 12,154 17,101
State Taxes............................................... 111,828 138,976
Book Accruals............................................. 29,208 39,505
Alternative Minimum Tax Credits........................... 12,283 9,098
Net Operating Loss Carryforwards.......................... 29,540 107,033
Discontinued Operations................................... 2,089 9,584
Capital Loss Carryforwards................................ 28,640 42,914
Other..................................................... 5,020 4,269
Valuation Allowance....................................... (2,462) --
---------- ----------
TOTAL DEFERRED TAX ASSETS................................... 243,433 383,256
---------- ----------
DEFERRED TAX LIABILITIES:
Property, Plant and Equipment............................. 1,972,881 2,009,086
Investments............................................... 688,224 642,944
Derivatives............................................... 6,580 --
Other..................................................... 4,252 4,403
---------- ----------
TOTAL DEFERRED TAX LIABILITIES.............................. 2,671,937 2,656,433
---------- ----------
NET DEFERRED TAX LIABILITIES................................ $2,428,504 $2,273,177
========== ==========
72
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
At December 31, 2001, we had available net operating loss carryforwards for
regular federal income tax purposes of approximately $84.4 million which will
expire in the year 2020. We also had available, at December 31, 2001, capital
loss carryforwards of $71.6 million of which $49.0 million will expire in the
year 2005 and $22.6 million will expire in the year 2006. A valuation allowance
of $2.5 million has been provided for the deferred tax benefits related to the
portion of capital loss carryforwards that may not be utilized in the future. We
also had available, at December 31, 2001, approximately $12.3 million of
alternative minimum tax credit carryforwards, which are available indefinitely.
13. FINANCING
(A) NOTES PAYABLE
At December 31, 2001, we had available a $500 million 364-day facility
dated October 23, 2001, and a $400 million amended and restated five-year
revolving credit agreement dated January 30, 1998. These bank facilities can be
used for general corporate purposes, including backup for our commercial paper
program, and include covenants that are common in such arrangements. For
example, the $500 million facility requires consolidated debt to be less than
68% of consolidated capitalization. The $400 million facility requires that
consolidated debt must be less than 67% of consolidated total capitalization.
Both of the bank facilities require the debt of consolidated subsidiaries to be
less than 10% of our consolidated debt and require the consolidated debt of each
material subsidiary to be less than 65% of our consolidated total
capitalization. The $400 million facility requires our consolidated net worth
(inclusive of trust preferred securities) be at least $1.236 billion plus 50
percent of consolidated net income earned for each fiscal quarter beginning with
the last quarter of 1998. The $500 million facility requires our consolidated
net worth (inclusive of trust preferred securities) be at least $1.236 billion
plus 50 percent of consolidated net income earned for each fiscal quarter
beginning with the last quarter of 1999. Under the bank facilities, we are
required to pay a facility fee based on the total commitment, at a rate that
varies based on our senior debt investment rating. Facility fees paid in 2001
and 2000 were $1.4 million and $1.6 million, respectively. At December 31, 2001
and 2000, $0 million and $100 million, respectively, was outstanding under the
bank facilities.
Commercial paper issued by us and supported by the bank facilities are
unsecured short-term notes with maturities not to exceed 270 days from the date
of issue. During 2001, all commercial paper was redeemed within 92 days, with
interest rates ranging from 1.60 percent to 7.50 percent. Commercial paper
outstanding at December 31, 2001 was $423.8 million. No commercial paper was
outstanding at December 31, 2000. The weighted-average interest rate on
short-term borrowings outstanding at December 31, 2001 was 2.87 percent. Average
short-term borrowings outstanding during 2001 and 2000 were $447.8 million and
$310.6 million, respectively. During 2001 and 2000, the weighted-average
interest rates on short-term borrowings outstanding were 3.91 percent and 6.52
percent, respectively.
On January 4, 1999, we repaid a short-term note for $1.4 billion which had
been payable to Occidental Petroleum Corporation that we had assumed in
connection with the early-1998 acquisition of MidCon Corp. The note was repaid
using the proceeds of approximately $1.1 billion from the sale of U.S.
government securities that had been held as collateral, with the balance of the
funds provided by an increase in short-term borrowings.
73
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(B) LONG-TERM DEBT AND PREMIUM EQUITY PARTICIPATING SECURITY UNITS
DECEMBER 31,
-----------------------
2001 2000
---------- ----------
(IN THOUSANDS)
DEBENTURES:
6.50% Series, Due 2013.................................... $ 50,000 $ 50,000
7.85% Series, Due 2022.................................... 24,025 24,943
8.75% Series, Due 2024.................................... 75,000 75,000
7.35% Series, Due 2026.................................... 125,000 125,000
6.67% Series, Due 2027.................................... 150,000 150,000
7.25% Series, Due 2028.................................... 493,000 493,000
7.45% Series, Due 2098.................................... 150,000 150,000
SINKING FUND DEBENTURES:
9.95% Series Due 2020..................................... -- 20,000
9.625% Series Due 2021.................................... -- 45,000
8.35% Series, Due 2022.................................... 35,000 35,000
SENIOR NOTES:
6.45% Series, Due 2001.................................... -- 400,000
7.27% Series, Due 2002.................................... 5,000 10,000
6.45% Series, Due 2003.................................... 500,000 500,000
6.65% Series, Due 2005.................................... 500,000 500,000
6.80% Series, Due 2008.................................... 300,000 300,000
Floating Rate Notes, Due 2002............................... 200,000 --
Reset Put Securities, 6.30% due 2021........................ -- 400,000
Other....................................................... 12,350 13,617
Carrying Value Adjustment for Interest Rate Swaps(1)........ (4,831) --
Unamortized Debt Discount................................... (3,310) (4,410)
Current Maturities of Long-term Debt........................ (206,267) (808,167)
---------- ----------
TOTAL LONG-TERM DEBT........................................ $2,404,967 $2,478,983
========== ==========
---------------
(1) Adjustment of carrying value of long-term securities subject to interest
rate swaps; see Note 15.
Maturities of long-term debt (in thousands) for the five years ending
December 31, 2006 are $206,267, $501,267, $1,267, $501,267, and $6,017,
respectively.
The 2013 Debentures and the 2003 and 2005 Senior Notes are not redeemable
prior to maturity. The 2022, 2028 and 2098 Debentures and the 2002 and 2008
Senior Notes are redeemable in whole or in part, at our option at any time, at
redemption prices defined in the associated prospectus supplements. The 2024,
2026 and 2027 Debentures are redeemable in whole or in part, at our option after
October 15, 2002, August 1, 2006, and November 1, 2004, respectively, at
redemption prices defined in the associated prospectus supplements. The 2022
Sinking Fund Debentures are redeemable in whole or in part, at our option after
September 15, 2002, at redemption prices defined in the associated prospectus
supplement.
On November 30, 2001, our Premium Equity Participating Security Units
matured, which resulted in our receipt of $460 million in cash and our issuance
of 13,382,474 shares of additional common stock. We used the cash proceeds to
retire the $400 million of 6.45% Series of Senior Notes that became due on the
same date and a portion of our short-term borrowings then outstanding.
74
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
On October 10, 2001, we issued $200 million of Floating Rate Notes due
October 10, 2002 in an offering made pursuant to Rule 144A of the regulations of
the Securities and Exchange Commission. These notes bear interest at the
three-month London Interbank Offered Rate (LIBOR) plus 95 basis points, with
interest paid quarterly. The proceeds from the offering were used to retire a
portion of our short-term borrowings then outstanding.
On September 10, 2001, we retired our $45 million of 9.625% Series Sinking
Fund Debentures due March 1, 2021, utilizing incremental short-term borrowings.
In March 2001, we retired (i) our $400 million of Reset Put Securities due March
1, 2021 and (ii) our $20 million of 9.95% Series Sinking Fund Debentures due
2020, utilizing a combination of cash and incremental short-term borrowings. In
conjunction with these early extinguishments of debt, we recorded extraordinary
losses of $13.6 million (net of associated tax benefit of $9.0 million). These
losses are included under the caption, "Extraordinary Item, Loss on Early
Extinguishment of Debt" in the accompanying Consolidated Statements of
Operations for 2001.
At December 31, 2001 and 2000, the carrying amount of our long-term debt
was $2.6 billion and $3.3 billion, respectively. The estimated fair values of
our long-term debt at December 31, 2001 and 2000 are shown in Note 19.
(C) CAPITAL SECURITIES
Our wholly owned business trusts, K N Capital Trust I and K N Capital Trust
III, are obligated for $100 million of 8.56% Capital Trust Securities maturing
on April 15, 2027 and $175 million of 7.63% Capital Trust Securities maturing on
April 15, 2028, respectively. The transactions and balances of K N Capital Trust
I and K N Capital Trust III are included in our consolidated financial
statements, with the Capital Securities treated as a minority interest, shown in
our Consolidated Balance Sheets under the caption "Kinder Morgan-Obligated
Mandatorily Redeemable Preferred Capital Trust Securities of Subsidiary Trust
Holding Solely Debentures of Kinder Morgan." Periodic payments made to the
holders of these securities are classified under "Minority Interests" in the
accompanying Consolidated Statements of Operations. See Note 19 for the fair
value of these securities.
(D) COMMON STOCK
On February 14, 2002, we paid a cash dividend on our common stock of $0.05
per share to stockholders of record as of January 31, 2002.
On August 14, 2001, we announced a plan to repurchase $300 million of our
outstanding common stock under a program expected to be completed by the end of
2002. At the trading price at the time of the announcement, the $300 million
represented approximately 5.7 million shares, or about 4.4 percent of the shares
outstanding. As of December 31, 2001, we had repurchased under the program
approximately $270.4 million (5,294,800 shares) of our outstanding common stock.
On February 5, 2002, we announced that our Board of Directors had approved
expanding the plan to a total of $400 million.
On November 17, 1999, our Board of Directors approved a reduction in the
quarterly dividend from $0.20 per share to $0.05 per share.
(E) KINDER MORGAN MANAGEMENT, LLC
In May 2001, Kinder Morgan Management, one of our indirect subsidiaries,
issued and sold its shares in an underwritten initial public offering. The net
proceeds from the offering were used by Kinder Morgan Management to buy i-units
from Kinder Morgan Energy Partners for $991.9 million. Upon purchase of the
i-units, Kinder Morgan Management became a partner in Kinder Morgan Energy
Partners and was delegated by Kinder Morgan Energy Partners' general partner the
responsibility to manage and control
75
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Kinder Morgan Energy Partners' business and affairs. The i-units are a class of
Kinder Morgan Energy Partners' limited partner interests that have been, and
will be, issued only to Kinder Morgan Management.
In the initial public offering, 10 percent of Kinder Morgan Management's
shares were purchased by Kinder Morgan, Inc., with the balance purchased by the
public. The equity interest in Kinder Morgan Management (our consolidated
subsidiary) purchased by the public created a minority interest on our balance
sheet of $892.7 million at the time of the transaction. See Note 2 for
additional information regarding these transactions.
14. PREFERRED STOCK
We have authorized 200,000 shares of Class A and 2,000,000 shares of Class
B preferred stock, all without par value.
(A) CLASS A $5.00 CUMULATIVE PREFERRED STOCK
On April 13, 1999, we sent notices to holders of our Class A $5.00
Cumulative Preferred Stock of our intent to redeem these shares on May 14, 1999.
Holders of 70,000 preferred shares were advised that on April 13, 1999, funds
were deposited with the First National Bank of Chicago to pay the redemption
price of $105 per share plus accrued but unpaid dividends. Under the terms of
our Articles of Incorporation, upon deposit of funds to pay the redemption
price, all rights of the preferred stockholders ceased and terminated except the
right to receive the redemption price upon surrender of their stock
certificates.
At December 31, 2001, 2000 and 1999, we did not have any outstanding shares
of Class A $5.00 Cumulative Series Preferred Stock.
(B) CLASS B PREFERRED STOCK
We did not have any outstanding shares of Class B Preferred Stock at
December 31, 2001, 2000 or 1999.
15. RISK MANAGEMENT
Effective January 1, 2001, we adopted SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities, as amended by SFAS No. 137,
Accounting for Derivative Instruments and Hedging Activities -- Deferral of the
Effective Date of FASB Statement No. 133 and SFAS No. 138, Accounting for
Certain Derivative Instruments and Certain Hedging Activities, collectively,
"Statement 133." Statement 133 established accounting and reporting standards
requiring that every derivative financial instrument (including certain
derivative instruments embedded in other contracts) be recorded in the balance
sheet as either an asset or liability measured at its fair value. The
accompanying Consolidated Balance Sheet as of December 31, 2001, includes
balances of approximately $29.0 million, $0.5 million and $13.2 million in the
captions "Current Assets: Other," "Deferred Charges and Other Assets" and
"Current Liabilities: Other," respectively, related to these derivative
financial instruments. Statement 133 requires that changes in the derivative's
fair value be recognized currently in earnings unless specific hedge accounting
criteria are met. If the derivatives meet those criteria, Statement 133 allows a
derivative's gains and losses to offset related results on the hedged item in
the income statement, and requires that a company formally designate a
derivative as a hedge and document and assess the effectiveness of derivatives
associated with transactions that receive hedge accounting.
We enter into derivative contracts solely for the purpose of hedging
exposures that accompany our normal business activities. As a result of the
adoption of Statement 133, the fair value of our derivative financial
instruments utilized for hedging activities as of January 1, 2001 (a loss of
$11.9 million) was reported as a cumulative effect transition adjustment within
accumulated other comprehensive income. All but an insignificant amount of this
transition adjustment was reclassified into earnings during 2001. In
76
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
accordance with the provisions of Statement 133, we designated these instruments
as hedges of various exposures as discussed following, and we test the
effectiveness of changes in the value of these hedging instruments with the risk
being hedged. Hedge ineffectiveness is recognized in income in the period in
which it occurs.
We enter into these transactions only with counterparties whose debt
securities are rated investment grade by the major rating agencies. In general,
the risk of default by these counterparties is low. However, we recently
experienced a loss as discussed following.
During the fourth quarter of 2001, we determined that Enron Corp. was no
longer likely to honor the obligations it had to us in conjunction with
derivatives we were accounting for as hedges under Statement 133. Upon making
that determination, we (i) ceased to account for those derivatives as hedges,
(ii) entered into new derivative transactions with other counterparties to
replace our position with Enron, (iii) designated the replacement derivative
positions as hedges of the exposures that had been hedged with the Enron
positions and (iv) recognized a $5.0 million pre-tax loss (included with
"General and Administrative Expenses" in the accompanying Consolidated Statement
of Operations for 2001) in recognition of the fact that it was unlikely that we
would be paid the amounts then owed under the contracts with Enron. While we
enter into derivative transactions only with investment grade counterparties and
actively monitor their credit ratings, it is nevertheless possible that
additional losses will result from counterparty credit risk in the future.
Our businesses require that we purchase, sell and consume natural gas.
Specifically, we purchase, sell and/or consume natural gas (i) to serve our
regulated natural gas distribution sales customers, (ii) to serve certain of our
retail natural gas distribution customers in areas where regulatory
restructuring has provided for competition in natural gas supply, for customers
who have selected the Company as their supplier of choice under our "Choice Gas"
program, (iii) as fuel in our Colorado power generation facilities, (iv) as fuel
for compressors located on Natural Gas Pipeline Company of America's pipeline
system and (v) for operational sales of gas by Natural Gas Pipeline Company of
America.
With respect to item (i), we have no commodity risk because the regulated
retail gas distribution regulatory structure provides that actual gas cost is
"passed-through" to our customers. With respect to item (iii), only one of these
power generation facilities is not covered by a long-term, fixed price gas
supply agreement at a level sufficient for the current and projected capacity
utilization. With respect to item (iv), this fuel is supplied by in-kind fuel
recoveries that are part of the transportation tariff. Items (ii), (v) and the
one power facility included under item (iii) that is not covered by a long-term
fixed-price natural gas supply agreement, give rise to natural gas commodity
price risk which we have chosen to substantially mitigate through our risk
management program. We provide this mitigation through the use of financial
derivative products, and we do not utilize these derivatives for any purpose
other than risk mitigation.
Under our Choice Gas program, customers in certain areas served by Kinder
Morgan Retail are allowed to choose their natural gas supplier from a list of
qualified suppliers, although the transportation of the natural gas to the homes
and businesses continues to be provided by Kinder Morgan Retail in all cases.
When those customers choose an affiliate of Kinder Morgan Retail as their
supplier, we enter into agreements providing for sales of gas to these customers
during a one-year period at fixed prices per unit, but variable volumes. We
mitigate the risk associated with these anticipated sales of gas by purchasing
natural gas futures contracts on the New York Mercantile Exchange ("NYMEX") and,
as applicable, over-the-counter basis swaps to mitigate the risk associated with
the difference in price changes between Henry Hub (NYMEX) basis and the expected
physical delivery location. In addition, we mitigate a portion of the volumetric
risk through the purchase of over-the-counter natural gas options. The time
period covered by this risk management strategy does not extend beyond one year.
With respect to the power generation facility described above that is not
covered by an adequately sized, fixed-price gas supply contract, we are exposed
to changes in the price of natural gas as we purchase
77
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
it to use as fuel for the electricity-generating turbines. In order to mitigate
this exposure, we purchase natural gas futures on the NYMEX and, as discussed
above, over-the-counter basis swaps on the NYMEX, in amounts representing our
expected fuel usage in the near term. In general, we do not hedge this exposure
for periods longer than one year.
With respect to operational sales of natural gas made by Natural Gas
Pipeline Company of America, we are exposed to risk associated with changes in
the price of natural gas during the periods in which these sales are made. We
mitigate this risk by selling natural gas futures and, as discussed above,
over-the-counter basis swaps, on the NYMEX in the periods in which we expect to
make these sales. In general, we do not hedge this exposure for periods in
excess of 18 months.
During 2001, all of our natural gas derivative activities were designated
and qualified as cash flow hedges. We recognized approximately $5,000 of pre-tax
loss during 2001 as a result of ineffectiveness of these hedges, which amount is
reported within the caption "Gas Purchases and Other Costs of Sales" in the
accompanying Consolidated Statement of Operations for the year ended December
31, 2001. There was no component of the derivative instruments' gain or loss
excluded from the assessment of hedge effectiveness.
As the hedged sales and purchases take place and we record them into
earnings, we will also reclassify the gains and losses included in accumulated
other comprehensive income into earnings. We expect to reclassify into earnings,
during 2002, substantially all of the accumulated other comprehensive income
balance of $9.9 million at December 31, 2001, representing unrecognized net
gains on derivative activities. During 2001, we reclassified no gains or losses
into earnings as a result of the discontinuance of cash flow hedges due to a
determination that the forecasted transactions would no longer occur by the end
of the originally specified time period.
We also provide certain administrative risk management services to Kinder
Morgan Energy Partners, although Kinder Morgan Energy Partners retains the
obligations and rights arising from all derivative transactions entered into on
its behalf.
In order to maintain a cost effective capital structure, it is our policy
to borrow funds utilizing a mixture of fixed-interest-rate and
floating-interest-rate debt. In August 2001, in order to move closer to a mix of
50% fixed, 50% floating, we entered into fixed-to-floating interest rate swap
agreements with a notional principal amount of $1.0 billion. These agreements
effectively converted the interest expense associated with our 6.65% senior
notes and our 7.25% debentures from fixed rates to floating rates based on
three-month LIBOR plus a credit spread. These swaps have been designated as fair
value hedges as defined by Statement 133. These swaps meet the conditions
required to assume no ineffectiveness under Statement 133 and, therefore, we
have accounted for them utilizing the "shortcut" method prescribed for fair
value hedges. Accordingly, the carrying value of the swap is adjusted to its
fair value as of each reporting period, with an offsetting entry to adjust the
carrying value of the debt whose fair value is being hedged. We record interest
expense equal to the floating rate payments, which is accrued monthly and paid
semi-annually. Based on short-term borrowings outstanding and the long-term debt
effectively converted to floating rate debt as a result of the swap discussed
above, at December 31, 2001, the market risk related to a one percent change in
interest rates would result in a $16.5 million annual impact on pre-tax income.
78
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Following is selected information concerning our natural gas risk
management activities:
DECEMBER 31, 2001
----------------------------------------
COMMODITY OVER-THE-COUNTER
CONTRACTS SWAPS AND OPTIONS TOTAL
--------- ----------------- --------
(DOLLARS IN THOUSANDS)
Deferred Net (Loss) Gain....................... $(6,525) $ 22,751 $ 16,226
Contract Amounts -- Gross...................... $52,902 $124,145 $177,047
Contract Amounts -- Net........................ $(3,163) $(84,099) $(87,262)
(NUMBER OF CONTRACTS(1))
Notional Volumetric Positions: Long............ 556 717
Notional Volumetric Positions: Short........... (907) (2,776)
Net Notional Totals To Occur in 2002........... (351) (1,919)
Net Notional Totals To Occur in 2003 and
Beyond....................................... -- (140)
---------------
(1) A term of reference describing a volumetric unit of commodity trading. One
natural gas contract equals 10,000 MMBtus.
Our over-the-counter swaps and options are with a number of parties, each
of which is an investment grade credit. We both owe money and are owed money
under these financial instruments and, at December 31, 2001, if all parties
owing us failed to pay us amounts due at that date under these arrangements, our
pre-tax credit loss would have been $12.2 million. At December 31, 2001, the
largest credit exposure to a single counterparty was $5.3 million.
16. EMPLOYEE BENEFITS
(A) RETIREMENT PLANS
We have defined benefit pension plans covering eligible full-time
employees. These plans provide pension benefits that are based on the employees'
compensation during the period of employment, age and years of service. These
plans are tax-qualified subject to the minimum funding requirements of the
Employee Retirement Income Security Act of 1974, as amended. Our funding policy
is to contribute annually the recommended contribution using the actuarial cost
method and assumptions used for determining annual funding requirements. Plan
assets consist primarily of pooled fixed income, equity, bond and money market
funds. Plan assets included our common stock valued at $12.3 million and $11.5
million as of December 31, 2001 and 2000, respectively.
Net periodic pension cost includes the following components:
YEAR ENDED DECEMBER 31,
------------------------------
2001 2000 1999
-------- -------- --------
(IN THOUSANDS)
Service Cost......................................... $ 5,329 $ 7,306 $ 9,977
Interest Cost........................................ 9,421 8,600 8,170
Expected Return on Assets............................ (15,145) (14,034) (13,381)
Net Amortization and Deferral........................ (1,282) (1,257) (210)
Recognition of Curtailment Gain...................... -- -- (9)
-------- -------- --------
Net Periodic Pension (Benefit) Cost.................. $ (1,677) $ 615 $ 4,547
======== ======== ========
79
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table sets forth the reconciliation of the beginning and
ending balances of the pension benefit obligation:
2001 2000
--------- ---------
(IN THOUSANDS)
Benefit Obligation at Beginning of Year.................... $(125,091)(1) $(118,038)
Service Cost............................................... (5,329) (7,306)
Interest Cost.............................................. (9,421) (8,600)
Actuarial (Gain) Loss...................................... (7,447) 3,922
Benefits Paid.............................................. 7,512 6,915
Plan Amendments............................................ (991) --
--------- ---------
Benefit Obligation at End of Year.......................... $(140,767) $(123,107)
========= =========
---------------
(1) Includes benefit obligation of Hall-Buck Plan, as described below.
The following table sets forth the reconciliation of the beginning and
ending balances of the fair value of the plans' assets, the plans' funded status
and prepaid pension cost. Prepaid pension cost is recognized under the caption
"Other Current Assets" in our Consolidated Balance Sheets:
DECEMBER 31,
------------------------
2001 2000
--------- ---------
(IN THOUSANDS)
Fair Value of Plan Assets at Beginning of Year............. $ 163,096(1) $ 150,900
Actual Return on Plan Assets During the Year............... (6,211) 17,294
Contributions by Employer.................................. 104 --
Benefits Paid During the Year.............................. (7,512) (6,915)
--------- ---------
Fair Value of Plan Assets at End of Year................... 149,477 161,279
Benefit Obligation at End of Year.......................... (140,767) (123,107)
--------- ---------
Plan Assets in Excess of Projected Benefit Obligation...... 8,710 38,172
Unrecognized Net Gain...................................... (2,770) (33,134)
Prior Service Cost Not Yet Recognized in Net Periodic
Pension Costs............................................ 993 88
Adjustment to Recognize Minimum Liability.................. (207) --
Unrecognized Net Asset at Transition....................... (529) (696)
--------- ---------
Prepaid Pension Cost....................................... $ 6,197 $ 4,430
========= =========
---------------
(1) Includes assets of Hall-Buck Plan, as described below.
The rate of increase in future compensation was 3.5 percent for 2001, 2000
and 1999. The expected long-term rate of return on plan assets was 9.5 percent
for 2001, 2000 and 1999. The weighted-average discount rate used in determining
the actuarial present value of the projected benefit obligation was 7.25 percent
for 2001 and 7.75 percent for 2000 and 1999.
Effective January 1, 2001, we added a cash balance plan to our retirement
plan. Certain collectively bargained employees and "grandfathered" employees
will continue to accrue benefits through the defined pension benefit plan
described above. All other employees will accrue benefits through a personal
retirement account in the new cash balance plan. All employees converting to the
cash balance plan were credited with the current fair value of any benefits they
have previously accrued through the defined benefit plan. We make contributions
on behalf of these employees equal to 3% of eligible compensation
80
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
every pay period. In addition, we may make discretionary contributions to the
plan based on our performance. Interest is credited to the personal retirement
accounts at the 30-year U.S. Treasury bond rate in effect each year. Employees
will be fully vested in the plan after five years, and they may take a lump sum
distribution upon termination or retirement.
On December 31, 2000, the Hall-Buck Marine Services Company Pension Plan
("Hall-Buck Plan") was merged into our retirement plan. The Hall-Buck Plan's
projected benefit obligation of $2.0 million, unrecognized transition obligation
of $1.3 million and plan assets of $1.8 million were transferred to our
retirement plan, and the Hall-Buck Plan was terminated. Also on December 31,
2000, all employees who were not previously eligible to participate in our
retirement plan and were not otherwise covered under a collective bargaining
agreement became eligible under the new cash balance plan.
Effective December 31, 2001 we merged the Pinney Dock Retirement Plan, the
Boswell Oil Company Pension Plan, and the River Transportation Retirement Plan
into our retirement plan. As of January 1, 2002, all assets and liabilities of
these plans were transferred to our retirement plan.
In 2000, we merged the Kinder Morgan Bulk Terminals Retirement Savings Plan
and the Kinder Morgan Retirement Savings Plan with the Kinder Morgan Profit
Sharing and Savings Plan, a defined contribution plan. The merged plan was
renamed the Kinder Morgan, Inc. Savings Plan. On July 2, 2000, we began making
regular contributions to the Plan. Contributions are made each pay period in an
amount equal to 4% of compensation on behalf of each eligible employee. All
contributions are in the form of Company stock, which is immediately convertible
into other available investment vehicles at the employee's discretion. On July
25, 2000, our Board of Directors authorized an additional 6 million shares to be
issued through the Plan, for a total of 6.7 million shares available. In
addition to the above contributions, we may make annual discretionary
contributions based on our performance. These contributions are made in the year
following the year for which the contribution amount is calculated. The total
amount contributed for 2001 and 2000 was $9.5 million and $3.7 million,
respectively. No contribution was made to the profit sharing plan for 1999. In
January 1998, we acquired the MidCon Retirement Plan as part of our acquisition
of MidCon Corp. The MidCon plan was a defined contribution plan. Contributions
to the plan were based on age and earnings. Effective January 1, 1999, the
MidCon plan was merged into the Profit Sharing Plan and all eligible MidCon
employees joined our defined benefit pension plans. In 1999, we contributed $0.7
million to the MidCon plan.
(B) OTHER POSTRETIREMENT EMPLOYEE BENEFITS
We have a defined benefit postretirement plan providing medical and life
insurance benefits upon retirement for eligible employees and their eligible
dependents, including former MidCon employees who met the eligibility
requirements on the date of acquisition of MidCon Corp. The MidCon
postretirement medical and life insurance plans were "grandfathered" as of the
acquisition date and no new employees have or will be added to the MidCon plans
subsequent to the acquisition date. We fund the future expected postretirement
benefit cost under the plan by making payments to Voluntary Employee Benefit
Association trusts. Plan assets consist primarily of pooled fixed income funds.
Net periodic postretirement benefit cost includes the following components:
YEAR ENDED DECEMBER 31,
---------------------------
2001 2000 1999
------- ------- -------
(IN THOUSANDS)
Service Cost............................................ $ 340 $ 413 $ 450
Interest Cost........................................... 7,266 7,159 6,655
Expected Return on Assets............................... (5,431) (4,790) (3,720)
Net Amortization and Deferral........................... 1,501 992 908
------- ------- -------
Net Periodic Postretirement Benefit Cost................ $ 3,676 $ 3,774 $ 4,293
======= ======= =======
81
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table sets forth the reconciliation of the beginning and
ending balances of the accumulated postretirement benefit obligation:
2001 2000
--------- --------
(IN THOUSANDS)
Benefit Obligation at Beginning of Year..................... $ (95,178) $(93,080)
Service Cost................................................ (340) (413)
Interest Cost............................................... (7,266) (7,159)
Actuarial Gain (Loss)....................................... (3,209) (8,191)
Benefits Paid............................................... 10,504 15,918
Retiree Contributions....................................... (2,529) (2,253)
Plan Amendments............................................. (3,045) --
--------- --------
Benefit Obligation at End of Year........................... $(101,063) $(95,178)
========= ========
The following table sets forth the reconciliation of the beginning and
ending balances of the fair value of plan assets, the plan's funded status and
the amounts included under the caption "Other" in the category "Other
Liabilities and Deferred Credits" in our Consolidated Balance Sheets:
DECEMBER 31,
--------------------
2001 2000
--------- --------
(IN THOUSANDS)
Fair Value of Plan Assets at Beginning of Year.............. $ 51,156 $ 52,572
Actual Return on Plan Assets................................ 3,496 (2,175)
Contributions by Employer................................... 31,683 1,500
Retiree Contributions....................................... 1,852 1,726
Benefits Paid............................................... (8,089) (2,467)
--------- --------
Fair Value of Plan Assets at End of Year.................... 80,098 51,156
Benefit Obligation at End of Year........................... (101,063) (95,178)
--------- --------
Excess of Projected Benefit Obligation Over Plan Assets..... (20,965) (44,022)
Unrecognized Net (Gain) Loss................................ 17,591 12,779
Unrecognized Net Obligations at Transition.................. 10,220 11,149
Unrecognized Prior Service Cost............................. 2,807 --
--------- --------
Accrued Expense............................................. $ 9,653 $(20,094)
========= ========
The weighted-average discount rate used in determining the actuarial
present value of the accumulated postretirement benefit obligation was 7.25
percent for 2001 and 7.75 percent for 2000 and 1999. The expected long-term rate
of return on plan assets was 9.5 percent for 2001, 2000 and 1999. The assumed
health care cost trend rate for 2001 was 3 percent (7 percent for certain
collectively bargained employees). The assumed health care cost trend rate for
2000 and 1999 was 7 percent (3 percent for the MidCon plans). A
one-percentage-point increase (decrease) in the assumed health care cost trend
rate for each future year would have increased (decreased) the aggregate of the
service and interest cost components of the 2001 net periodic postretirement
benefit cost by approximately $8,089 ($7,424) and would have increased
(decreased) the accumulated postretirement benefit obligation as of December 31,
2001 by approximately $111,943 ($102,729).
17. COMMON STOCK OPTION AND PURCHASE PLANS
We have the following stock option plans: The 1982 Incentive Stock Option
Plan, the 1982 Stock Option Plan for Non-Employee Directors, the 1986 Incentive
Stock Option Plan, the 1988 Incentive Stock
82
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Option Plan, the 1992 Non-Qualified Stock Option Plan for Non-Employee
Directors, the 1994 Kinder Morgan, Inc. Long-term Incentive Plan (which also
provides for the issuance of restricted stock), the American Oil and Gas
Corporation Stock Incentive Plan ("AOG Plan") and the Kinder Morgan, Inc.
Amended and Restated 1999 Stock Option Plan. We also have an employee stock
purchase plan.
On October 8, 1999, our Board of Directors approved the creation of our
1999 stock option plan, a broadly based non-qualified stock option plan. Under
the plan, options may be granted to individuals who are regular full-time
employees, including officers and directors who are employees. Options under the
plan vest in 25 percent increments on the anniversary of the grant over a
four-year period from the date of grant. All options granted under the plan have
a 10-year life, and must be granted at not less than the fair market value of
Kinder Morgan, Inc. common stock at the close of trading on the date of grant.
On January 17, 2001, our Board of Directors approved an additional 5 million
shares for future grants to participants in the 1999 Stock Option Plan, which
brings the aggregate number of shares subject to the plan to 10.5 million. The
Board also recommended, and our shareholders approved at our May 8, 2001 annual
meeting, an additional 0.5 million shares for future grants to participants in
the 1992 Directors' Plan, which brings the aggregate number of shares subject to
that plan to 1.03 million.
Under all plans, except the Long-term Incentive Plan and the AOG Plan,
options are granted at not less than 100 percent of the market value of the
stock at the date of grant. Under the Long-term Incentive Plan options may be
granted at less than 100 percent of the market value of the stock at the date of
grant. Compensation expense was recorded totaling $0.6 million, $0, and $8.6
million for 2001, 2000, and 1999, respectively, relating to restricted stock
grants awarded under the plans.
OPTION SHARES
GRANTED THROUGH
SHARES SUBJECT DECEMBER 31, VESTING EXPIRATION
PLAN NAME TO THE PLAN 2001 PERIOD PERIOD
--------- -------------- --------------- ------------ ------------
1982 Plan............................ 1,332,788 1,332,788 Immediate 10 Years
1982 Directors' Plan................. 186,590 186,590 3 Years 10 Years
1986 Plan............................ 618,750 618,750 Immediate 10 Years
1988 Plan............................ 618,750 618,750 Immediate 10 Years
1992 Directors' Plan................. 1,025,000 457,875 0 - 6 Months 10 Years
Long-term Incentive Plan............. 5,700,000 2,775,763 0 - 5 Years 5 - 10 Years
AOG Plan............................. 775,500 775,500 3 Years 10 Years
1999 Plan............................ 10,500,000 6,776,613 4 Years 10 Years
A summary of the status of our stock option plans at December 31, 2001,
2000 and 1999, and changes during the years then ended is presented in the table
and narrative below:
2001 2000 1999
-------------------- --------------------- --------------------
WTD. AVG WTD. AVG WTD. AVG
EXERCISE EXERCISE EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
--------- -------- ---------- -------- --------- --------
Outstanding at Beginning of
Year........................ 6,093,819 $26.05 7,542,898 $24.92 4,218,191 $24.38
Granted....................... 2,140,200 $51.17 1,364,500 $30.42 4,837,656 $23.81
Exercised..................... (899,664) $25.36 (537,400) $19.26 (602,928) $ 8.00
Forfeited..................... (358,638) $35.14 (2,276,179) $25.69 (910,021) $27.79
--------- ---------- ---------
Outstanding at End of Year.... 6,975,717 $33.12 6,093,819 $26.05 7,542,898 $24.92
========= ====== ========== ====== ========= ======
Exercisable at End of Year.... 2,922,471 $29.93 2,056,771 $27.03 1,918,868 $26.54
========= ====== ========== ====== ========= ======
Weighted-Average Fair Value of
Options Granted............. $21.31 $10.51 $ 5.83
====== ====== ======
83
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The weighted-average fair value of each option grant is estimated on the
date of grant using the Black-Scholes option pricing model with the following
assumptions:
YEAR ENDED DECEMBER 31,
------------------------------------
2001 2000 1999
---------- --------- ---------
Risk-free Interest Rate (%)...................... 4.30 4.97 5.50
Expected Weighted-average Life................... 6.5 years 4.5 years 4.0 years
Volatility....................................... 0.34(1) 0.34 0.31
Expected Dividend Yield (%)...................... 0.36 0.38 3.20
---------------
(1) The volatility assumption for the options issued under the 1992 Directors'
Plan was 0.44.
We account for these plans under Accounting Principles Board Opinion No.
25, Accounting for Stock Issued to Employees. Had compensation cost for these
plans been determined consistent with SFAS No. 123, Accounting for Stock-Based
Compensation ("SFAS 123"), net income and diluted earnings per share would have
been reduced to the pro forma amounts shown in the table below. Because the SFAS
123 method of accounting has not been applied to options granted prior to
January 1, 1995, the resulting pro forma compensation cost may not be
representative of that to be expected in future years. Additionally, the pro
forma amounts include $1.0 million, $0.8 million and $1.0 million related to the
purchase discount offered under the ESP Plan for 2001, 2000 and 1999,
respectively.
YEAR ENDED DECEMBER 31,
----------------------------------------
2001 2000 1999
----------- ----------- ------------
(IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
NET INCOME (LOSS):
As Reported....................................... $225,070 $152,415 $(259,892)
======== ======== =========
Pro Forma......................................... $209,799 $144,960 $(264,744)
======== ======== =========
EARNINGS (LOSS) PER DILUTED SHARE:
As Reported....................................... $ 1.86 $ 1.33 $ (3.24)
======== ======== =========
Pro Forma......................................... $ 1.73 $ 1.27 $ (3.30)
======== ======== =========
The following table sets forth our December 31, 2001, common stock options
outstanding, weighted-average exercise prices, weighted-average remaining
contractual lives, common stock options exercisable and the exercisable
weighted-average exercise price:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
------------------------------------------------------------------------ -----------------------
WTD. AVG. WTD. AVG. WTD. AVG.
NUMBER EXERCISE REMAINING NUMBER EXERCISE
PRICE RANGE OUTSTANDING PRICE CONTRACTUAL LIFE EXERCISABLE PRICE
----------- ----------- --------- ---------------- ----------- ---------
$00.00 - $23.72............. 125,752 $20.91 5.08 years 123,778 $20.87
$23.81 - $23.81............. 3,232,886 $23.81 7.77 years 1,457,226 $23.81
$24.04 - $38.88............. 1,474,114 $29.70 7.69 years 795,903 $30.79
$34.67 - $52.10............. 1,534,015 $49.04 8.93 years 545,564 $47.08
$53.20 - $53.60............. 608,950 $53.22 9.26 years -- $ --
--------- ---------
6,975,717 $33.12 8.09 years 2,922,471 $29.93
========= =========
Under the employee stock purchase plan, we may sell up to 2,400,000 shares
of common stock to eligible employees. Employees purchase shares through
voluntary payroll deductions. Prior to the 2000 plan year, shares were purchased
annually at a 15 percent discount from the market value of the common stock, as
defined in the plan, and issued in the month following the end of the plan year.
Beginning with
84
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
the 2000 plan year, shares are purchased quarterly at a 15 percent discount from
the closing price of the common stock on the last trading day of each calendar
quarter. Employees purchased 88,333 shares, 86,630 shares and 187,567 shares for
plan years 2001, 2000 and 1999, respectively. Using the Black-Scholes model to
assign value to the option inherent in the right to purchase stock under the
provisions of the employee stock purchase plan, the weighted-average fair value
per share of purchase rights granted in 2001, 2000 and 1999 was $10.66, $6.60
and $6.41, respectively.
18. COMMITMENTS AND CONTINGENT LIABILITIES
(A) LEASES
Expenses incurred under operating leases were $7.1 million in 2001, $47.1
million in 2000, and $57.8 million in 1999. Future minimum commitments under
major operating leases as of December 31, 2001 are as follows:
YEAR AMOUNT
---- --------------
(IN THOUSANDS)
2002........................................................ $ 9,697
2003........................................................ 9,108
2004........................................................ 9,396
2005........................................................ 9,529
2006........................................................ 8,571
Thereafter.................................................. 15,754
-------
Total....................................................... $62,055
=======
As a result of our December 1999 sale of assets to ONEOK, ONEOK assumed our
obligation for the lease of the Bushton gas processing facility. We remain
secondarily liable for the lease, which had a remaining minimum obligation of
approximately $247 million at December 31, 2001, with payments that average
approximately $23 million per year through 2012.
(B) CAPITAL EXPENDITURES BUDGET
Approximately $16.9 million of our consolidated capital expenditure budget
for 2002 had been committed for the purchase of plant and equipment at December
31, 2001.
(C) COMMITMENT TO PURCHASE ASSETS
We were committed, during a specified period, to purchase, at the option of
the other party, an incremental 50% interest in a joint venture pipeline,
although the ability of the other party to cause the purchase is currently
stayed: see Notes 6 and 10.
(D) COMMITMENTS FOR INCREMENTAL INVESTMENT
We are obligated to invest approximately an additional $118 million in
power generation facilities in the form of preferred equity and could be
obligated (i) based on operational performance of the equipment at one facility
to invest up to an additional $3 to 8 million per year for the next 16 years and
(ii) based on cash flows generated by the facility, to invest up to an
additional $25 million beginning in year 17, in each case in the form of an
incremental preferred interest.
85
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(E) CONTINGENT OBLIGATION FOR DEBT
In the event that long-term bond financing in the amount of approximately
$250 million for a power facility currently financed by bank debt is not
obtained prior to March 29, 2002, we are obligated to repurchase the debt from
the banks.
19. FAIR VALUE
The following fair values of Long-term Debt and Capital Securities were
estimated based on an evaluation made by an independent securities analyst. Fair
values of "Energy Financial Instruments, Net" reflect the estimated amounts that
we would receive or pay to terminate the contracts at the reporting date,
thereby taking into account the current unrealized gains or losses on open
contracts. Market quotes are available for substantially all instruments we use.
DECEMBER 31,
-----------------------------------------------
2001 2000
--------------------- ---------------------
CARRYING FAIR CARRYING
VALUE VALUE VALUE FAIR VALUE
-------- -------- -------- ----------
(IN MILLIONS)
FINANCIAL LIABILITIES:
Long-term Debt................................ $2,614.5(1) $2,624.5(1) $3,291.6 $3,251.1
Capital Securities............................ $ 275.0 $ 279.7 $ 275.0 $ 278.7
Energy Financial Instruments, Net............. $ 16.2 $ 16.2 $ 14.4 $ 14.4
Interest Rate Swaps........................... $ 4.8 $ 4.8 $ -- $ --
---------------
(1) Includes an adjustment offsetting the value of the interest rate swaps. See
Note 15.
20. SUMMARIZED FINANCIAL INFORMATION FOR KINDER MORGAN ENERGY PARTNERS, L.P.
Following is summarized financial information for Kinder Morgan Energy
Partners, a publicly traded limited partnership in which Kinder Morgan, Inc.
owns, through a wholly owned subsidiary, the general partner interest. In
addition, Kinder Morgan, Inc. owns, directly and through consolidated
subsidiaries, a limited partner interest in the form of Kinder Morgan Energy
Partners common units, i-units and Class B units. This investment, which is
accounted for under the equity method of accounting, is described in more detail
in Note 3. Additional information on Kinder Morgan Energy Partners' results of
operations and financial position are contained in its 2001 Form 10-K.
SUMMARIZED INCOME STATEMENT
INFORMATION
YEAR ENDED DECEMBER 31,
--------------------------------
2001 2000 1999
---------- -------- --------
(IN THOUSANDS)
Operating Revenues.................................. $2,946,676 $816,442 $428,749
Operating Expenses.................................. 2,382,848 500,881 241,342
---------- -------- --------
Operating Income.................................... $ 563,828 $315,561 $187,407
========== ======== ========
Net Income.......................................... $ 442,343 $278,348 $182,302
========== ======== ========
86
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
SUMMARIZED BALANCE SHEET
INFORMATION
AS OF DECEMBER 31,
-------------------------
2001 2000
----------- -----------
(IN THOUSANDS)
Current Assets.............................................. $ 568,043 $ 511,261
========== ==========
Noncurrent Assets........................................... $6,164,623 $4,113,949
========== ==========
Current Liabilities......................................... $ 962,704 $1,098,956
========== ==========
Noncurrent Liabilities...................................... $2,545,692 $1,351,018
========== ==========
Minority Interest........................................... $ 65,236 $ 58,169
========== ==========
21. BUSINESS SEGMENT INFORMATION
In accordance with the manner in which we manage our businesses, including
the allocation of capital and evaluation of business segment performance, we
report our operations in the following segments: (1) Natural Gas Pipeline
Company of America and certain affiliates, referred to as Natural Gas Pipeline
Company of America, a major interstate natural gas pipeline and storage system;
(2) Kinder Morgan Retail, the regulated sale and transportation of natural gas
to residential, commercial and industrial customers and the non-regulated sales
of natural gas to certain utility customers under the Choice Gas Program and (3)
Power and Other, the construction and operation of natural gas-fired electric
generation facilities, together with various other activities not constituting
separately managed or reportable business segments. In previous periods, we
owned and operated other lines of business that we discontinued during 1999. In
addition, our direct investment in the natural gas transmission and storage
business has significantly decreased as a result of (i) the December 2000
transfer of Kinder Morgan Texas Pipeline, L.P. to Kinder Morgan Energy Partners
and (ii) the December 31, 1999 transfer of Kinder Morgan Interstate Gas
Transmission LLC to Kinder Morgan Energy Partners. The results of operations of
these two businesses are included in our financial statements until their
disposition, which is discussed in Note 6.
The accounting policies we apply in the generation of business segment
information are generally the same as those described in Note 1 to the
accompanying Consolidated Financial Statements, except that certain items below
the "Operating Income" line are either not allocated to business segments or are
not considered by management in its evaluation of business unit performance. An
exception to this is that Kinder Morgan Power, which routinely conducts its
business activities in the form of joint operations with other parties that are
accounted for under the equity method of accounting, includes its equity in
earnings of these investees in its operating results. These equity method
earnings are included in "Other Income and (Expenses)" in our Consolidated
Statements of Operations. In addition, (i) certain items included in operating
income (such as merger-related and severance costs and general and
administrative expenses) are not allocated to individual business segments and
(ii) gains and losses from incidental sales of assets are included in segment
earnings. With adjustment for these items, we currently evaluate business
segment performance primarily based on operating income in relation to the level
of capital employed. We account for intersegment sales at market prices, while
we account for asset transfers at either market value or, in some instances,
book value. As necessary for comparative purposes, we have reclassified prior
period results and balances to conform to the current presentation.
Natural Gas Pipeline Company of America's principal delivery market area
encompasses the states of Illinois, Indiana, Iowa and portions of Wisconsin,
Nebraska, Kansas, Missouri and Arkansas. Natural Gas Pipeline Company of America
is the largest transporter of natural gas to the Chicago, Illinois area, its
largest market. During 2001, approximately 45% of Natural Gas Pipeline Company
of America's transportation represented deliveries to this market. Natural Gas
Pipeline Company of America's storage capacity is largely located near its
transportation delivery markets, effectively serving the same customer
87
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
base. Natural Gas Pipeline Company of America has a number of individually
significant customers, including local gas distribution companies in the greater
Chicago area and major natural gas marketers and, during 2001, approximately 50%
of its operating revenues were attributable to its six largest customers. Kinder
Morgan Retail's markets are represented by residential, commercial and
industrial customers located in Colorado, Nebraska and Wyoming. These markets
represent varied types of customers in many industries, but a significant amount
of Kinder Morgan Retail's load is represented by the use of natural gas for
space heating, grain drying and irrigation. The latter two groups of customers
are concentrated in the agricultural industry, and all markets are affected by
the weather. Power's current principal market is represented by the local
electric utilities in Colorado, which purchase the power output from its
generation facilities. Its market will expand geographically as a result of
power generation facilities planned or under construction and it is expected
that future customers may include wholesale power marketers.
During 2001, we did not have revenues from any single customer that
exceeded 10 percent of our consolidated operating revenues. In 2000, we had
revenues from a single customer of $740.5 million, an amount in excess of 10% of
consolidated operating revenues for that year. Both Natural Gas Pipeline Company
of America and Kinder Morgan Texas Pipeline made sales to this customer. Sales
to this customer did not exceed 10% of consolidated operating revenues in 2001
because we transferred Kinder Morgan Texas Pipeline to Kinder Morgan Energy
Partners effective December 31, 2000.
BUSINESS SEGMENT INFORMATION
DECEMBER 31,
YEAR ENDED DECEMBER 31, 2001 2001
------------------------------------------------------------------------ ------------
INCOME FROM REVENUES FROM DEPRECIATION
CONTINUING EXTERNAL INTERSEGMENT AND CAPITAL SEGMENT
OPERATIONS CUSTOMERS REVENUES AMORTIZATION EXPENDITURES ASSETS
----------- ------------- ------------ ------------ ------------ ------------
(IN THOUSANDS)
Natural Gas Pipeline
Company of America... $346,569 $ 646,804 $ -- $ 85,843 $ 88,429 $5,599,766
Kinder Morgan Retail... 56,398 285,098 44 12,328 10,225 356,378
Power and Other........ 63,348 123,016 2,029 10,119 25,517 3,576,941(1)
-------- ---------- ------ -------- -------- ----------
Consolidated......... 466,315 $1,054,918 $2,073 $108,290 $124,171 $9,533,085
========== ====== ======== ======== ==========
General and
Administrative
Expenses............. (70,386)
Other Income and
(Expenses)........... 11,307
--------
Income from Continuing
Operations Before
Income Taxes......... $407,236
========
88
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
DECEMBER 31,
YEAR ENDED DECEMBER 31, 2000 2000
------------------------------------------------------------------------ ------------
INCOME FROM REVENUES FROM DEPRECIATION
CONTINUING EXTERNAL INTERSEGMENT AND CAPITAL SEGMENT
OPERATIONS CUSTOMERS REVENUES AMORTIZATION EXPENDITURES ASSETS
----------- ------------- ------------ ------------ ------------ ------------
(IN THOUSANDS)
Natural Gas Pipeline
Company of America... $344,405 $ 622,020 $(18) $ 84,975 $38,722 $5,478,183
Kinder Morgan Retail... 49,755 229,510 (1) 11,776 13,513 350,042
Kinder Morgan Texas
Pipeline(2).......... 29,318 1,747,499 -- 2,211 16,734 --
Power and Other........ 33,460 80,693 4 9,203 16,685 2,558,764(1)
Discontinued
Operations........... -- -- -- -- 3,185 --
-------- ---------- ---- -------- ------- ----------
Consolidated......... 456,938 $2,679,722 $(15) $108,165 $88,839 $8,386,989
========== ==== ======== ======= ==========
General and
Administrative
Expenses............. (58,087)
Other Income and
(Expenses)........... (91,685)
--------
Income from Continuing
Operations Before
Income Taxes......... $307,166
========
DECEMBER 31,
YEAR ENDED DECEMBER 31, 1999 1999
------------------------------------------------------------------------ ------------
INCOME FROM REVENUES FROM DEPRECIATION
CONTINUING EXTERNAL INTERSEGMENT AND CAPITAL SEGMENT
OPERATIONS CUSTOMERS REVENUES AMORTIZATION EXPENDITURES ASSETS
----------- ------------- ------------ ------------ ------------ ------------
(IN THOUSANDS)
Natural Gas Pipeline
Company of America... $306,695 $ 625,705 $ 1,183 $109,346 $ 41,716 $5,469,050
Kinder Morgan
Interstate(3)........ 53,630 96,531 16,676 16,985 20,743 --
Kinder Morgan Retail... 20,055 182,861 51 11,382 11,749 332,618
Kinder Morgan Texas
Pipeline(2).......... 16,554 872,161 -- 2,466 4,567 255,200
Power and Other........ 34,379 59,110 195 7,754 14,066 2,618,739(1)
Discontinued
Operations........... -- -- -- -- 28,363 718,227
-------- ---------- ------- -------- -------- ----------
Consolidated......... 431,313 $1,836,368 $18,105 $147,933 $121,204 $9,393,834
========== ======= ======== ======== ==========
General and
Administrative
Expenses............. (85,591)
Merger-related and
Severance Costs...... (37,443)
Other Income and
(Expenses)........... (93,728)
--------
Income from Continuing
Operations Before
Income Taxes......... $214,551
========
---------------
(1) Principally the investment in Kinder Morgan Energy Partners, investments in
electric power generating facilities and corporate cash and receivables.
(2) Kinder Morgan Texas Pipeline was transferred to Kinder Morgan Energy
Partners effective December 31, 2000.
89
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(3) Kinder Morgan Interstate was transferred to Kinder Morgan Energy Partners
effective December 31, 1999.
GEOGRAPHIC INFORMATION
All but an insignificant amount of our assets and operations are located in
the continental United States.
22. RECENT ACCOUNTING PRONOUNCEMENTS
Statement of Financial Accounting Standards No. 141 supercedes Accounting
Principles Board Opinion No. 16 and requires that all transactions fitting the
description of a business combination be accounted for using the purchase method
and prohibits the use of the pooling of interests for all business combinations
initiated after June 30, 2001. The Statement also modifies the accounting for
the excess of fair value of net assets acquired as well as intangible assets
acquired in a business combination. The provisions of this statement apply to
all business combinations initiated after June 30, 2001, and all business
combinations accounted for by the purchase method that are completed after July
1, 2001. This Statement requires disclosure of the primary reasons for a
business combination and the allocation of the purchase price paid to the assets
acquired and liabilities assumed by major balance sheet caption.
In June 2001, the FASB issued SFAS No. 142, Goodwill and Other Intangible
Assets. This Statement addresses financial accounting and reporting for (i)
intangible assets acquired individually or with a group of other assets (but not
those acquired in a business combination) at acquisition and (ii) goodwill and
other intangible assets subsequent to their acquisition. This Statement
supersedes APB Opinion No. 17, Intangible Assets. Under the provisions of this
Statement, if an intangible asset is determined to have an indefinite useful
life, it shall not be amortized until its useful life is determined to be no
longer indefinite. An intangible asset that is not subject to amortization shall
be tested for impairment annually, or more frequently if events or changes in
circumstances indicate that the asset might be impaired. Goodwill will not be
amortized. Goodwill will be tested for impairment on an annual basis and between
annual tests in certain circumstances at a level of reporting referred to as a
reporting unit. This Statement is required to be applied starting with fiscal
years beginning after December 15, 2001. Goodwill and intangible assets acquired
after June 30, 2001 will be subject immediately to the nonamortization and
amortization provisions of this Statement. At December 31, 2001, we had
approximately $25 million of goodwill recorded in conjunction with the 1998
acquisition of the Thermo Companies. In accordance with the provisions of SFAS
No. 142, we will complete our analysis of that goodwill balance for impairment
no later than June 30, 2002 and will record any indicated impairment during
2002. In addition, we have a significant amount of "excess investment" or
"equity method goodwill," principally as a result of our investment in Kinder
Morgan Energy Partners. As provided in SFAS No. 142, this type of investment
will continue to be tested for impairment in accordance with the provisions of
Accounting Principles Board Opinion No. 18, The Equity Method of Accounting for
Investments in Common Stock. We estimate that the reduction in amortization
expense resulting from the cessation of amortization of both the goodwill and
the equity method goodwill will result in a $0.13 increase in earnings per
diluted common share in 2002.
In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement
Obligations. This Statement addresses financial accounting and reporting for
obligations associated with the retirement of tangible long-lived assets and the
associated asset retirement costs. This Statement requires that the fair value
of a liability for an asset retirement obligation be recognized in the period in
which it is incurred if a reasonable estimate of fair value can be made. The
associated asset retirement costs are capitalized as part of the carrying amount
of the long-lived asset. This Statement contains disclosure requirements that
provide descriptions of asset retirement obligations and reconciliations of
changes in the components of those obligations. This Statement is effective for
financial statements issued for fiscal years beginning after
90
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
June 15, 2002. Earlier applications are encouraged. We have not yet quantified
the impacts of adopting this Statement on our financial position or results of
operations.
In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment
or Disposal of Long-Lived Assets. This Statement addresses financial accounting
and reporting for the impairment or disposal of long-lived assets. This
Statement retains the requirements to (a) recognize an impairment loss only if
the carrying amount of a long-lived asset is not recoverable from its
undiscounted cash flows and (b) measure an impairment loss as the difference
between the carrying amount and fair value of the asset. This Statement removes
goodwill from its scope, eliminating the requirement to allocate goodwill to
long-lived assets to be tested for impairment. This Statement requires that a
long-lived asset to be abandoned, exchanged for a similar productive asset, or
distributed to owners in a spin-off be considered held and used until it is
disposed of. This Statement requires the accounting model for long-lived assets
to be disposed of by sale be used for all long-lived assets, whether previously
held and used or newly acquired. Discontinued operations are no longer measured
on a net realizable value basis, and future operating losses are no longer
recognized before they occur. This Statement broadens the presentation of
discontinued operations in the income statement to include a component of an
entity (rather than a segment of a business). A component of an entity comprises
operations and cash flows that can be clearly distinguished, operationally and
for financial reporting purposes, from the rest of the entity. The provisions of
this Statement are effective for financial statements issued for fiscal years
beginning after December 15, 2001, and interim periods within those fiscal
years, with early application encouraged. The provisions of this Statement
generally are to be applied prospectively.
91
SELECTED QUARTERLY FINANCIAL DATA
KINDER MORGAN, INC. AND SUBSIDIARIES
QUARTERLY OPERATING RESULTS FOR 2001 AND 2000
2001 - THREE MONTHS ENDED
-------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
-------- --------- ------------- -----------
(IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)
Operating Revenues............................. $325,232 $218,845 $227,026 $283,815
Gas Purchases and Other Costs of Sales......... 133,328 59,301 53,492 93,232
-------- -------- -------- --------
Gross Margin................................... 191,904 159,544 173,534 190,583
Other Operating Expenses....................... 79,482 78,719 82,138 90,907
-------- -------- -------- --------
Operating Income............................... 112,422 80,825 91,396 99,676
Other Income and (Expenses).................... (17,752) 4,259 11,718 24,692
-------- -------- -------- --------
Income Before Income Taxes and Extraordinary
Item......................................... 94,670 85,084 103,114 124,368
Income Taxes................................... 37,868 35,184 43,443 52,106
-------- -------- -------- --------
Income Before Extraordinary Item............... 56,802 49,900 59,671 72,262
Extraordinary Item -- Loss on Early
Extinguishment of Debt, Net of Income Tax
Benefits of $8,080 and $964.................. (12,119) -- (1,446) --
-------- -------- -------- --------
Net Income..................................... $ 44,683 $ 49,900 $ 58,225 $ 72,262
======== ======== ======== ========
BASIC EARNINGS PER COMMON SHARE:
Income Before Extraordinary Item............... $ 0.50 $ 0.43 $ 0.52 $ 0.62
Extraordinary Item -- Loss on Early
Extinguishment of Debt....................... (0.11) -- (0.01) --
-------- -------- -------- --------
Total Basic Earnings Per Common Share.......... $ 0.39 $ 0.43 $ 0.51 $ 0.62
======== ======== ======== ========
Number of Shares Used in Computing Basic
Earnings Per Share........................... 114,844 115,258 114,980 115,892
======== ======== ======== ========
DILUTED EARNINGS PER COMMON SHARE:
Income Before Extraordinary Item............... $ 0.47 $ 0.41 $ 0.49 $ 0.60
Extraordinary Item -- Loss on Early
Extinguishment of Debt....................... (0.10) -- (0.01) --
-------- -------- -------- --------
Total Diluted Earnings Per Common Share........ $ 0.37 $ 0.41 $ 0.48 $ 0.60
======== ======== ======== ========
Number of Shares Used in Computing Diluted
Earnings Per Share........................... 121,320 122,359 121,446 120,298
======== ======== ======== ========
92
SELECTED QUARTERLY FINANCIAL DATA
KINDER MORGAN, INC. AND SUBSIDIARIES
QUARTERLY OPERATING RESULTS FOR 2001 AND 2000
2000 - THREE MONTHS ENDED
------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
-------- -------- ------------ -----------
(IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)
Operating Revenues............................. $480,586 $552,012 $741,417 $905,707
Gas Purchases and Other Costs of Sales......... 278,016 382,531 568,430 697,091
-------- -------- -------- --------
Gross Margin................................... 202,570 169,481 172,987 208,616
Other Operating Expenses....................... 89,881 87,819 87,517 93,294
-------- -------- -------- --------
Operating Income............................... 112,689 81,662 85,470 115,322
Other Income and (Expenses).................... (35,477) (40,581) (40,624) 28,705(1)
-------- -------- -------- --------
Income From Continuing Operations Before Income
Taxes........................................ 77,212 41,081 44,846 144,027
Income Taxes................................... 30,887 16,968 18,138 57,024
-------- -------- -------- --------
Income From Continuing Operations.............. 46,325 24,113 26,708 87,003
Loss on Disposal of Discontinued Operations,
Net of Tax................................... -- -- -- (31,734)(2)
-------- -------- -------- --------
Net Income..................................... $ 46,325 $ 24,113 $ 26,708 $ 55,269
======== ======== ======== ========
BASIC EARNINGS PER COMMON SHARE:
Continuing Operations.......................... $ 0.41 $ 0.21 $ 0.23 $ 0.76
Loss on Disposal of Discontinued Operations.... -- -- -- (0.28)
-------- -------- -------- --------
Total Basic Earnings Per Common Share.......... $ 0.41 $ 0.21 $ 0.23 $ 0.48
======== ======== ======== ========
Number of Shares Used in Computing Basic
Earnings Per Share........................... 113,058 114,196 114,461 114,535
======== ======== ======== ========
DILUTED EARNINGS PER COMMON SHARE:
Continuing Operations.......................... $ 0.41 $ 0.21 $ 0.23 $ 0.74
Loss on Disposal of Discontinued Operations.... -- -- -- (0.27)
-------- -------- -------- --------
Total Diluted Earnings Per Common Share........ $ 0.41 $ 0.21 $ 0.23 $ 0.47
======== ======== ======== ========
Number of Shares Used in Computing Diluted
Earnings Per Share........................... 113,456 114,981 116,177 118,594
======== ======== ======== ========
---------------
(1) Includes a $61.6 million pre-tax gain from the sale of certain assets to
Kinder Morgan Energy Partners; see Note 6 of the accompanying Notes to
Consolidated Financial Statements.
(2) See Note 7 of the accompanying Notes to Consolidated Financial Statements.
93
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.
Certain information required by this item is contained in our Proxy
Statement related to the 2002 Annual Meeting of Stockholders, to be filed
pursuant to Section 14 of the Securities Exchange Act of 1934 and is
incorporated herein by reference.
For information regarding our current executive officers, see Executive
Officers of the Registrant under Part I.
ITEM 11. EXECUTIVE COMPENSATION.
Information required by this item is contained in our Proxy Statement
related to the 2002 Annual Meeting of Stockholders, to be filed pursuant to
Section 14 of the Securities Exchange Act of 1934 and is incorporated herein by
reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
Information required by this item is contained in our Proxy Statement
related to the 2002 Annual Meeting of Stockholders, to be filed pursuant to
Section 14 of the Securities Exchange Act of 1934 and is incorporated herein by
reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Information required by this item is contained in our Proxy Statement
related to the 2002 Annual Meeting of Stockholders, to be filed pursuant to
Section 14 of the Securities Exchange Act of 1934 and is incorporated herein by
reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(a)(1) Financial Statements
Reference is made to the listings of financial statements and
supplementary data under Item 8 in Part II.
(2) Financial Statement Schedules
94
KINDER MORGAN, INC. AND SUBSIDIARIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
YEAR ENDED DECEMBER 31, 2001
------------------------------------------------------------------------------
DEDUCTIONS
BALANCE AT ADDITIONS WRITE-OFF OF DISCONTINUED
BEGINNING OF CHARGED TO COST UNCOLLECTIBLE OPERATIONS BALANCE AT END
PERIOD AND EXPENSES ACCOUNTS DEDUCTIONS OF PERIOD
------------ --------------- ------------- ------------ --------------
(IN MILLIONS)
Allowance for Doubtful
Accounts................... $2.3 $6.7 $(5.6) $-- $3.4
YEAR ENDED DECEMBER 31, 2000
------------------------------------------------------------------------------
DEDUCTIONS
BALANCE AT ADDITIONS WRITE-OFF OF DISCONTINUED
BEGINNING OF CHARGED TO COST UNCOLLECTIBLE OPERATIONS BALANCE AT END
PERIOD AND EXPENSES ACCOUNTS DEDUCTIONS OF PERIOD
------------ --------------- ------------- ------------ --------------
(IN MILLIONS)
Allowance for Doubtful
Accounts................... $1.7 $9.9 $(9.3) $-- $2.3
YEAR ENDED DECEMBER 31, 1999
------------------------------------------------------------------------------
DEDUCTIONS
BALANCE AT ADDITIONS WRITE-OFF OF DISCONTINUED
BEGINNING OF CHARGED TO COST UNCOLLECTIBLE OPERATIONS BALANCE AT END
PERIOD AND EXPENSES ACCOUNTS DEDUCTIONS OF PERIOD
------------ --------------- ------------- ------------ --------------
(IN MILLIONS)
Allowance for Doubtful
Accounts................... $10.8 $3.6 $(0.6) $(12.1) $1.7
The financial statements, including the notes thereto, of Kinder Morgan
Energy Partners, an equity method investee of the Registrant, are incorporated
herein by reference from 74 through 137 of Kinder Morgan Energy Partners'
Annual
Report on Form 10-K for the year ended December 31, 2001.
95
3. Exhibits
Any reference made to K N Energy, Inc. in the exhibit listing that follows
is a reference to the former name of Kinder Morgan, Inc., a Kansas corporation
and the registrant, and is made because the exhibit being listed and
incorporated by reference was originally filed before October 7, 1999, the date
of the change in the Registrant's name.
EXHIBIT
NUMBER DESCRIPTION
------- -----------
Exhibit 2(a) Agreement and Plan of Merger, dated as of July 8, 1999, by
and among K N Energy, Inc., Rockies Merger Corp., and Kinder
Morgan, Inc., (Annex A-1 of Registration Statement on Form
S-4 (File No. 333-85747))
Exhibit 2(b) First Amendment to Agreement and Plan of Merger, dated as of
August 20, 1999, by and among K N Energy, Inc., Rockies
Merger Corp., and Kinder Morgan, Inc., (Annex A-2 of
Registration Statement on Form S-4 (File No. 333-85747))
Exhibit 2(c) Contribution Agreement, dated as of December 30, 1999, by
and among Kinder Morgan, Inc., Natural Gas Pipeline Company
of America, K N Gas Gathering, Inc., Kinder Morgan G.P.,
Inc. and Kinder Morgan Energy Partners, L.P. (Exhibit 99.1
to Current Report on Form 8-K filed on January 14, 2000)
Exhibit 3(a) Restated Articles of Incorporation of Kinder Morgan, Inc.
(Exhibit 3(a) to the Annual Report on Form 10-K/A, Amendment
No. 1 filed on May 22, 2000)
Exhibit 3(b) Certificate of Amendment to the Restated Articles of
Incorporation of Kinder Morgan, Inc. as filed on October 7,
1999, with the Secretary of State of Kansas (Exhibit 3.1 to
Kinder Morgan, Inc.'s Quarterly Report on Form 10-Q for the
quarter ended September 30, 1999)
Exhibit 3(c) Bylaws of Kinder Morgan, Inc., as amended to October 7, 1999
(Exhibit 3.2 to Kinder Morgan, Inc.'s Quarterly Report on
Form 10-Q for the quarter ended September 30, 1999)
Exhibit 4(a) Indenture dated as of September 1, 1988, between K N Energy,
Inc. and Continental Illinois National Bank and Trust
Company of Chicago (Exhibit 4(a) to the Annual Report on
Form 10-K/A, Amendment No. 1 filed on May 22, 2000)
Exhibit 4(b) First supplemental indenture dated as of January 15, 1992,
between K N Energy, Inc. and Continental Illinois National
Bank and Trust Company of Chicago (Exhibit 4.2, File No.
33-45091)
Exhibit 4(c) Second supplemental indenture dated as of December 15, 1992,
between K N Energy, Inc. and Continental Bank, National
Association (Exhibit 4(c) to the Annual Report on Form
10-K/A, Amendment No. 1 filed on May 22, 2000)
Exhibit 4(d) Indenture dated as of November 20, 1993, between K N Energy,
Inc. and Continental Bank, National Association (Exhibit
4.1, File No. 33-51115) (Note -- Copies of instruments
relative to long-term debt in authorized amounts that do not
exceed 10 percent of the consolidated total assets of Kinder
Morgan and its subsidiaries have not been furnished. Kinder
Morgan will furnish such instruments to the Commission upon
request.)
Exhibit 4(e) $500,000,000 364-Day Credit Agreement among Kinder Morgan,
Inc., certain banks listed therein and Bank of America, N.
A. (Exhibit 4(e) to the Annual Report on Form 10-K for the
year ended December 31, 2000)
Exhibit 4(f)* Form of Amendment No. 1 to the $500,000,000 364-Day Credit
Agreement among Kinder Morgan, Inc., certain banks listed
therein and Bank of America, N.A.
96
EXHIBIT
NUMBER DESCRIPTION
------- -----------
Exhibit 4(g) $400,000,000 Amended and Restated Five-Year Credit Agreement
dated January 30, 1998 among K N Energy, Inc., certain banks
listed therein and Morgan Guaranty Trust Company of New
York, as Administrative Agent (Exhibit 4(f) to the Annual
Report on Form 10-K for the year ended December 31, 1997)
Exhibit 4(h) Amendment No. 1 to the $400,000,000 Five-Year Amended and
Restated Credit Agreement dated as of November 6, 1998 among
K N Energy, Inc., certain banks listed therein and Morgan
Guaranty Trust Company of New York, as Administrative Agent
(Exhibit 4(j) to the Annual Report on Form 10-K for the year
ended December 31, 1998)
Exhibit 4(i) Amendment No. 2 to the $400,000,000 Five-Year Amended and
Restated Credit Agreement dated as of January 8, 1999 among
K N Energy, Inc., certain banks listed therein and Morgan
Guaranty Trust Company of New York, as Administrative Agent
(Exhibit 4(l) to the Annual Report on Form 10-K for the year
ended December 31, 1998)
Exhibit 4(j) Rights Agreement between K N Energy, Inc. and the Bank of
New York, as Rights Agent, dated as of August 21, 1995
(Exhibit 1 on Form 8-A dated August 21, 1995)
Exhibit 4(k) Amendment No. 1 to Rights Agreement between K N Energy, Inc.
and the Bank of New York, as Rights Agent, dated as of
September 8, 1998 (Exhibit 10(cc) to the Annual Report on
Form 10-K for the year ended December 31, 1998)
Exhibit 4(l) Amendment No. 2 to Rights Agreement of Kinder Morgan, Inc.
dated July 8, 1999, between Kinder Morgan, Inc. and First
Chicago Trust Company of New York, as successor-in-interest
to the Bank of New York, as Rights Agent (Exhibit 4.1 to
Kinder Morgan, Inc.'s Quarterly Report on Form 10-Q for the
quarter ended September 30, 1999)
Exhibit 4(m)* Form of Amendment No. 3 to Rights Agreement of Kinder
Morgan, Inc. dated September 1, 2001, between Kinder Morgan,
Inc. and First Chicago Trust Company of New York, as Rights
Agent
Exhibit 10(a) 1994 Amended and Restated Kinder Morgan, Inc. Long-term
Incentive Plan (Appendix A to the Kinder Morgan, Inc. 2000
Proxy Statement on Schedule 14A)
Exhibit 10(b) Kinder Morgan, Inc. Amended and Restated 1999 Stock Option
Plan (Appendix B to the Kinder Morgan, Inc. 2000 Proxy
Statement on Schedule 14A)
Exhibit 10(c) Kinder Morgan, Inc. Amended and Restated 1992 Stock Option
Plan for Nonemployee Directors (Appendix C to the Kinder
Morgan, Inc. 2000 Proxy Statement on Schedule 14A)
Exhibit 10(d) 2000 Annual Incentive Plan of Kinder Morgan, Inc. (Appendix
D to the Kinder Morgan, Inc. 2000 Proxy Statement on
Schedule 14A)
Exhibit 10(e) Kinder Morgan, Inc. Employees Stock Purchase Plan (Appendix
E to the Kinder Morgan, Inc. 2000 Proxy Statement on
Schedule 14A)
Exhibit 10(f) Form of Nonqualified Stock Option Agreement (Exhibit 10(f)
to the Annual Report on Form 10-K for the year ended
December 31, 2000)
Exhibit 10(g) Form of Restricted Stock Agreement (Exhibit 10(g) to the
Annual Report on Form 10-K for the year ended December 31,
2000)
Exhibit 10(h) Directors and Executives Deferred Compensation Plan
effective January 1, 1998 for executive officers and
directors of K N Energy, Inc. (Exhibit 10(aa) to the Annual
Report on Form 10-K for the year ended December 31, 1998)
Exhibit 10(i) Employment Agreement dated October 7, 1999, between the
Company and Richard D. Kinder (Exhibit 99.D of the Schedule
13D filed by Mr. Kinder on October 8, 1999)
Exhibit 10(j) Employment Agreement dated April 20, 2000, by and among
Kinder Morgan, Inc., Kinder Morgan G.P., Inc. and David G.
Dehaemers, Jr. (filed as Exhibit 10(a) to Kinder Morgan,
Inc.'s Form 10-Q for the quarter ended March 31, 2000)
97
EXHIBIT
NUMBER DESCRIPTION
------- -----------
Exhibit 10(k) Employment Agreement dated April 20, 2000, by and among
Kinder Morgan, Inc., Kinder Morgan G.P., Inc. and Michael C.
Morgan (filed as Exhibit 10(b) to Kinder Morgan, Inc.'s Form
10-Q for the quarter ended March 31, 2000)
Exhibit 10(l)* Retention Agreement dated January 17, 2002, by and between
Kinder Morgan, Inc. and C. Park Shaper
Exhibit 21.1* Subsidiaries of the Registrant
Exhibit 23.1* Consent of Independent Accountants
Exhibit 99.1* The financial statements of Kinder Morgan Energy Partners,
L.P. and subsidiaries included on pages 74 through 137 on
the Annual Report on Form 10-K of Kinder Morgan Energy
Partners, L.P. for the year ended December 31, 2001
---------------
* Filed herewith.
(b) Reports on Form 8-K
(1) Current Report on Form 8-K dated November 9, 2001 was filed on
November 9, 2001 pursuant to Item 9. of that form.
Pursuant to Item 9. of that form, Kinder Morgan, Inc. announced its
intention to make several presentations beginning on November 9, 2001 to
institutional investors and others to address various strategic and
financial issues relating to the business plans and objectives of Kinder
Morgan, Inc., Kinder Morgan Energy Partners, L.P. and Kinder Morgan
Management, LLC, and the availability of materials to be presented at the
meetings on Kinder Morgan, Inc.'s website.
(2) Current Report on Form 8-K dated January 16, 2002 was filed on
January 16, 2002 pursuant to Item 9. of that form.
Pursuant to Item 9. of that form, Kinder Morgan, Inc. announced its
intention to make presentations on January 17, 2002 to analysts and others
to address various strategic and financial issues relating to the business
plans and objectives of Kinder Morgan, Inc., Kinder Morgan Energy Partners,
L.P. and Kinder Morgan Management, LLC, and the availability of materials
to be presented at the meetings on Kinder Morgan, Inc.'s website.
98
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.
KINDER MORGAN, INC.
(Registrant)
By /s/ C. PARK SHAPER
------------------------------------
C. Park Shaper
Vice President and Chief Financial
Officer
Date: February 18, 2002
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 date indicated.
/s/ EDWARD H. AUSTIN, JR. Director
------------------------------------------------
Edward H. Austin, Jr.
/s/ CHARLES W. BATTEY Director
------------------------------------------------
Charles W. Battey
/s/ STEWART A. BLISS Director
------------------------------------------------
Stewart A. Bliss
/s/ TED A. GARDNER Director
------------------------------------------------
Ted A. Gardner
/s/ WILLIAM J. HYBL Director
------------------------------------------------
William J. Hybl
/s/ RICHARD D. KINDER Chairman, Chief Executive Officer and Director
------------------------------------------------ (Principal Executive Officer)
Richard D. Kinder
/s/ WILLIAM V. MORGAN Vice Chairman and Director
------------------------------------------------
William V. Morgan
/s/ EDWARD RANDALL, III Director
------------------------------------------------
Edward Randall, III
Director
------------------------------------------------
Fayez Sarofim
99
/s/ C. PARK SHAPER Vice President and Chief Financial Officer
------------------------------------------------ (Principal Financial and Accounting Officer)
C. Park Shaper
/s/ H. A. TRUE, III Director
------------------------------------------------
H. A. True, III
100