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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1998
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OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to
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Commission File Number 1-6446
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K N ENERGY, INC.
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(Exact name of registrant as specified in its charter)
Kansas 48-0290000
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(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.)
370 Van Gordon Street
P.O. Box 281304, Lakewood, Colorado 80228-8304
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (303) 989-1740
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Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange on
Title of each class which registered
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Common stock, par value $5 per share New York Stock Exchange
Preferred share purchase rights New York Stock Exchange
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Securities registered pursuant to Section 12(g) of the Act:
Preferred stock, Class A $5 cumulative series
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(Title of class)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (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
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Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
State the aggregate market value of the voting stock held by nonaffiliates of
the registrant.
$1,468,361,624 as of February 22, 1999
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Indicate the number of shares outstanding of each of the registrant's classes of
common stock, as of the latest practicable date.
Common stock, $5 par value; authorized 150,000,000 shares; outstanding
69,651,991 shares as of February 22, 1999
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List hereunder documents incorporated by reference and the Part of the Form 10-K
into which the document is incorporated.
1999 Proxy Statement Part III
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K N ENERGY, INC. AND SUBSIDIARIES
Documents Incorporated by Reference and Index
Page Number
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1999 Proxy Included
Statement Herein
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PART I
ITEMS 1 & 2: BUSINESS AND PROPERTIES.................................................... 3-15
ITEM 3: LEGAL PROCEEDINGS ......................................................... 16
ITEM 4: SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during
the last quarter of 1998.
EXECUTIVE OFFICERS OF THE REGISTRANT....................................... 17-18
PART II
ITEM 5: MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED
STOCKHOLDER MATTERS................................................... 19
ITEM 6: SELECTED FINANCIAL DATA.................................................... 20
ITEM 7: MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS..................................... 21-33
ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Public Accountants ................................ 34
Consolidated Statements of Income for the Three
Years Ended December 31, 1998, 1997 and 1996 ........................ 35
Consolidated Balance Sheets as of December 31, 1998 and 1997............. 36
Consolidated Statements of Common Stockholders' Equity for
the Three Years Ended December 31, 1998, 1997 and 1996............... 37
Consolidated Statements of Cash Flows for the Three
Years Ended December 31, 1998, 1997 and 1996......................... 38
Notes to Consolidated Financial Statements............................... 39-64
Selected Quarterly Financial Data (Unaudited)............................ 65
ITEM 9: CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
There were no such matters during 1998.
PART III
ITEM 10: DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT......................... *
ITEM 11: EXECUTIVE COMPENSATION..................................................... *
ITEM 12: SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT............. *
ITEM 13: CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS............................. *
PART IV
ITEM 14: EXHIBITS AND REPORTS ON FORM 8-K
(a) 1. Financial Statements
Reference is made to the listing of financial
statements and supplementary data under Item 8
in Part II of this index.
2. Financial Statement Schedules
Schedule II - Valuation and Qualifying Accounts 68
3. Exhibits
Exhibit Index................................................... 72-75
List of Executive Compensation Plans and Arrangements...................... 69-70
Exhibit 12 - Ratio of Earnings to Fixed Charges................. 76
Exhibit 13 - 1998 Annual Report to Shareholders**............... 77
Exhibit 21 - Subsidiaries of the Registrant..................... 78-80
Exhibit 23 - Consent of Independent Public Accountants.......... 81
Exhibit 27 - Financial Data Schedule***
(b) Reports on Form 8-K.................................................. 70
SIGNATURES ................................................................................ 71
Note: Individual financial statements of the parent Company are omitted
pursuant to the provisions of Accounting Series Release No. 302.
* Incorporated herein by reference.
** Such report is being furnished for the information of the Securities
and Exchange Commission ("SEC") only and is not to be deemed filed as a
part of this annual report on Form 10-K.
*** Included in SEC copy only.
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PART I
ITEMS 1 and 2: BUSINESS and PROPERTIES
As used in this report "the Company," "K N" and "K N Energy" refer to K N
Energy, Inc., together with its consolidated subsidiaries, unless the context
otherwise requires. All volumes of natural gas referred to herein 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.
The term "Mcf" means thousand cubic feet, the term "MMcf" means million cubic
feet, the term "Bcf" means billion cubic feet and the term "Tcf" means trillion
cubic feet. The term "MMBtus" means million British thermal units ("Btus").
"NGLs" refers to natural gas liquids, which consist of ethane, propane, butane,
iso-butane and natural gasoline. The term "Bbls" means barrels.
On February 22, 1999, Sempra Energy ("Sempra") and the Company announced that
their respective boards of directors had unanimously approved a definitive
agreement (the "Agreement") under which Sempra and the Company would combine in
a stock-and-cash transaction valued in the aggregate at $6.0 billion. Sempra is
an energy services holding company based in San Diego, California, serving 21
million customers through natural gas and electric distribution, as well as a
broad range of energy-related products and services throughout the United
States, Canada, Mexico and other countries in Latin America. Under the terms of
the Agreement, Sempra will acquire all of the Company's outstanding common
shares (the "K N Shares") for a combination of shares of Sempra common stock
(the "Sempra Shares") and cash as described following. The Company's
shareholders will have the option to elect to receive for each of their K N
Shares either (a) .7805 Sempra Shares plus $7.50, (b) 1.115 Sempra Shares or (c)
$25.00, subject to pro-ration, such that 70 percent of the K N Shares will be
converted into Sempra Shares and 30% of the K N Shares will be converted into
cash. This merger is conditioned, among other things, upon the approvals of
shareholders of both companies, the Federal Energy Regulatory Commission and the
state commissions of Colorado and Wyoming and clearance under the
Hart-Scott-Rodino Antitrust Improvements Act of 1976. Closing is currently
expected in six to eight months.
(A) General Description
K N Energy is an integrated energy services provider whose operations include
the gathering, processing, transportation and storage of natural gas, marketing
of natural gas and NGLs and electric power generation and sales. As of December
31, 1998, the Company operated nearly 25,000 miles of interstate and intrastate
pipelines and over 11,000 miles of gathering and processing pipelines that
connect major supply areas with major consuming areas in the Western and
Mid-Continent United States. At December 31, 1998 the Company also owned or had
an interest in 31 natural gas processing plants with total processing and/or
treating capacity of approximately 2,725 MMcf per day, including the Bushton
complex in the Hugoton Basin, one of the largest natural gas extraction
facilities in the United States, and 25 storage facilities with 5,362 MMcf per
day of withdrawal capacity. As of December 31, 1998, the Company's regulated
retail natural gas business served over 210,000 customers in Colorado, Nebraska
and Wyoming. The Company also markets innovative products and services, such as
the Simple Choice(sm) ("Simple Choice") menu of products and call center
services designed for residential consumers, utilities and small businesses
through its 50% owned en*able, LLC ("en*able") affiliate.
The Company's executive offices are located at 370 Van Gordon Street, P.O. Box
281304, Lakewood, Colorado 80228-8304 and its telephone number is (303)
989-1740. K N was incorporated in the State of Kansas on May 18, 1927. The
Company employed 3,308 people at December 31, 1998.
On January 30, 1998, pursuant to a definitive stock purchase agreement, K N
Energy paid approximately $2.1 billion in cash and issued a note in an aggregate
principal amount of approximately $1.39 billion to Occidental Petroleum
Corporation ("Occidental") to acquire the outstanding shares of capital stock of
MidCon Corp.
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("MidCon") and a note in an aggregate principal amount of approximately $1.39
billion issued to Occidental by MidCon's employee stock ownership plan. As a
result of this acquisition, which was recorded as a purchase for accounting
purposes, MidCon became a wholly owned subsidiary of K N Energy.
MidCon is engaged in the purchase, gathering, processing, transmission, storage
and sale of natural gas to utilities, municipalities and industrial and
commercial users. MidCon operates over 14,000 miles of natural gas pipelines
which are located in the center of the North American pipeline grid. These
pipeline assets include two MidCon-owned major interconnected transmission
pipelines terminating in the Chicago area: one originating in West Texas and the
other in the Gulf Coast areas of Texas and Louisiana, as well as a leased major
intrastate pipeline located in Texas.
(B) Narrative Description of Business
Overview
K N Energy is an integrated energy services provider with operations that
include the gathering, processing, transportation and storage of natural gas,
marketing of natural gas and NGLs and electric power generation and sales.
Reflecting the Company's strategy of extracting margins from the various
segments of the energy value stream, the Company has segregated its results of
operations into "Upstream," "Midstream" and "Downstream" components. The
Company's Upstream operations consist of (i) natural gas gathering, (ii) natural
gas processing and (iii) NGLs extraction and marketing activities. Midstream
operations consist of transportation, storage and bundled sales transactions for
K N's interstate and intrastate pipelines. Downstream activities principally
consist of energy marketing, regulated natural gas distribution and electric
power generation and sales. As discussed following, certain of the Company's
operations are regulated by various federal and state entities.
UPSTREAM BUSINESS SEGMENT
K N's Upstream segment consists of natural gas gathering and processing and NGLs
extraction and marketing. Within this business segment, the Company owns and
operates approximately 8,000 miles of gathering and processing pipeline in
eleven states and owns or has an interest in 31 gas processing and/or treating
plants in five states, including the Bushton complex, one of the largest NGLs
extraction facilities in the United States. During 1998, the Company's plants
processed approximately 1.3 Bcf per day of natural gas (and had capacity to
process 2,725 MMcf per day) and produced over 2.5 million gallons of NGLs per
day.
FACILITIES. The Company has an extensive network of gathering and processing
facilities located primarily in the Mid-Continent and Rocky Mountain states and
Texas. Based on average throughput, the Company's largest gathering operation is
its Hugoton Basin system located in Kansas, which gathers approximately 540 MMcf
per day, making K N the largest gatherer in this basin. The Hugoton Basin system
interconnects with several gas processing plants in the area, including K N's
largest processing plant, Bushton, which K N acquired in April 1997 (the
gathering assets were purchased and the processing facilities are operated by
K N under an operating lease) and which has approximately 1.0 Bcf per day of
processing capacity. As of December 31, 1998, the Bushton plant accounted for
approximately 37% of the Company's total processing capacity.
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In addition to the Hugoton Basin system, the Company's Wattenberg system,
located in northeastern Colorado, includes gathering and interstate transmission
lines with total system throughput of approximately 150 MMcf per day. The
Company's West Texas system, located primarily in western Texas and the Texas
Panhandle, includes gathering lines and 11 gas processing plants, with total
system throughput of approximately 125 MMcf per day. The Company also owns
gathering facilities in the Powder River, Big Horn and Wind River basins of
Wyoming and the Piceance and Uintah basins of western Colorado and eastern Utah,
with combined gathering throughput of approximately 220 MMcf per day. In
addition, K N owns a 49% equity interest in the Red Cedar Gathering System in
the northern San Juan basin of Colorado, with total system throughput of
approximately 440 MMcf per day. This system is also connected to the Company's
jointly owned Coyote Gulch processing plant and TransColorado pipeline.
In January 1996, K N and Tom Brown, Inc. ("Tom Brown") formed Wildhorse Energy
Partners, LLC ("Wildhorse"), a joint venture limited liability company currently
owned 55% by K N and 45% by Tom Brown, to provide gathering, processing, storage
and marketing services to Rocky Mountain oil and gas producers and others.
Pursuant to this joint venture, Tom Brown has dedicated all of its uncommitted
Rocky Mountain gas production to Wildhorse, and the Company has contributed
certain gas marketing and storage contracts.
CONTRACTS AND CUSTOMERS. The Company's gathering and processing facilities
perform a wide range of services for its customers, including gathering gas at
the wellhead or other natural gas field aggregation points, transporting gas and
processing gas to extract NGLs and marketing those NGLs to NGL pipelines, end
users and marketers. The Company's customers primarily include oil and gas
producers, gatherers and transporters. Revenues from the Company's gathering and
processing business are generated through gathering and processing fees charged
to producers or other third parties which are based on negotiated rates. In
addition, revenues are generated through the marketing of NGLs processed at the
Company's plants and the marketing of third-party NGLs.
The Company processes gas under three types of contractual arrangements, each
with varying degrees of commodity risk: fee based, percent of proceeds and keep
whole. For the year ended December 31, 1998, as a percentage of total gas
throughput, 20%, 51% and 29% of the Company's contracts were fee based, percent
of proceeds and keep whole, respectively. In addition, K N purchases
approximately 11% of the gas it processes at the wellhead and takes title to the
gas. In general, fee based contracts are for a term of seven to twelve years and
are based on a flat fee for processing. Fee based contracts eliminate the
Company's exposure to commodity price risk for a particular volume of gas since
the producer retains title to the gas and NGLs. Under percent of proceeds
contracts, which are generally for a term of one to ten years, K N processes the
gas and then sells the resulting NGLs and residual gas at market prices for the
producer, while keeping a percentage of the proceeds for itself. Given the
Company's economic interest in a portion of the residual gas and NGLs, percent
of proceeds contracts entail some commodity risk.
Keep whole contracts entail significant commodity risk. Under these contracts,
which are generally for a term of one to five years, K N agrees to take a
certain volume of raw gas from the producer, process it and return gas with a
Btu content equivalent to the input gas to the producer. The processed NGLs are
then marketed by K N for its own account. As a result of K N's obligation under
keep whole contracts to market the NGLs produced and reimburse producers for
shrinkage of the gas during processing and deliver the equivalent Btu content as
explained preceding, K N is exposed to fluctuations in both the price of
processed natural gas as a buyer and to NGLs prices as a seller, as well as the
spread between the two. The "keep whole" component of such contracts benefits
the Company when the value of the NGLs is greater as a liquid than as a portion
of the residue gas stream. However, when the value of the NGLs is lower as a
liquid than as a portion of the residue gas stream, the Company may be adversely
impacted.
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The recent weakness in NGLs prices, coupled with the relative strength of gas
prices, has significantly reduced the margins on K N's keep whole contracts. In
addition, weak NGL prices overall have hurt the Upstream segment's margins. In
an effort to reduce the fluctuations in margins inherent in processing gas under
keep whole contracts, the Company has engaged in certain hedging transactions.
Pursuant to its Board of Directors' approved trading policy, the Company manages
its commodity exposure through continued monitoring of its exposure and
maintenance of proper controls in order to ensure compliance with the
volumetric, mark-to-market and value-at-risk restrictions contained in the
policy.
MIDSTREAM BUSINESS SEGMENT
K N's Midstream segment consists of natural gas transportation and storage as
well as bundled sales transactions for K N's interstate and intrastate
pipelines. Within this segment, the Company operates nearly 25,000 miles of
interstate and intrastate natural gas pipelines and associated storage and
supply lines which are strategically located at the center of the North American
pipeline grid. K N's transportation network provides access to the major gas
supply areas in the Gulf of Mexico, the Gulf Coast, the Permian Basin, the
Mid-Continent, the Rocky Mountains and western Canada, as well as the major
consumer markets in the Midwest and along the Gulf Coast.
TRANSPORTATION
FACILITIES. K N's natural gas transmission business is comprised of both
interstate and intrastate pipelines. These operations are conducted principally
through three major subsidiary pipeline companies: Natural Gas Pipeline Company
of America ("NGPL"), MidCon Texas Pipeline Operator, Inc. ("MidCon Texas") and
K N Interstate Gas Transmission Co. ("KNI"). K N also operates intrastate
systems in West Texas, Colorado and Wyoming.
Through NGPL, K N owns and operates approximately 12,200 miles of interstate
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 61 compressor stations in mainline
and storage service having an aggregate of approximately 1.0 million horsepower.
NGPL's system has over 1,700 points of interconnection with 31 interstate
pipelines, 24 intrastate pipelines and 54 local distribution companies ("LDCs")
and end users, thereby providing significant flexibility in the receipt and
delivery of gas. One of NGPL's primary pipelines, the "Amarillo Line",
originates in the West Texas and New Mexico producing areas and is comprised of
approximately 6,600 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 4,300 miles of mainline and
various small-diameter pipelines. These two main pipelines are connected at
points in Texas and Oklahoma by NGPL's 230-mile Amarillo/Gulf Coast pipeline. In
addition, subsidiaries of NGPL own interests in several regulated natural gas
pipeline systems which are accounted for as equity investments. These pipelines
include High Island Offshore System, U-T Offshore System and Stingray offshore
pipeline in the Gulf of Mexico, and the Trailblazer pipeline which moves gas
from production basins in southwestern Wyoming and northwestern Colorado to
Mid-Continent pipelines.
Through MidCon Texas, the Company operates an intrastate pipeline system
principally located in the Texas Gulf Coast area. This pipeline is leased from
Occidental under a 30-year lease which commenced on December 31, 1996. The
system includes approximately 2,600 miles of pipelines, supply lines, sales
laterals and related facilities. The MidCon Texas pipeline system transports
natural gas from producing fields in South Texas, the Gulf Coast and the Gulf of
Mexico to markets in southeastern Texas and, through interconnections with NGPL
and 22 other intrastate and interstate pipelines, to markets throughout the
United States. A subsidiary of MidCon Gas Services Corp. ("MidCon Gas") owns a
separate Texas intrastate pipeline system (the "Palo Duro System") that includes
approximately 400 miles of pipeline and related facilities. The Palo Duro System
is leased to a nonaffiliate.
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Through KNI, the Company owns and operates over 6,600 miles of transmission
lines in Wyoming, Colorado, Kansas and Nebraska. The system is powered by 120
compressor stations in mainline and storage service having an aggregate of
approximately 127,000 horsepower.
Through the Company's West Texas system, located primarily in western Texas and
the Texas Panhandle, the Company provides transportation and storage services to
the Company's affiliated marketing organization and to LDCs, industrial and
irrigation markets. This 4,800 mile pipeline and storage system is
interconnected with eight interstate pipelines in the West Texas region. Through
American Gas Storage, L.P. ("American Gas Storage"), the Company provides the
region's only storage facility with 16 Bcf (3 Bcf salt cavern) of high
deliverability storage capability.
Through Rocky Mountain Natural Gas Company and Northern Gas Company, the Company
provides transportation services to the Company's affiliated LDCs as well as to
irrigators, grain dryers, gas producers and industrial customers in Colorado and
Wyoming, respectively. These two systems include approximately 1,400 miles of
transmission lines.
In addition, K N is a fifty-fifty joint venture partner with Questar in the
TransColorado pipeline. The TransColorado pipeline, which was completed in
February 1999,is expected to provide the Company with increased flexibility in
accessing multiple natural gas basins in the Rocky Mountain region. This
pipeline extends 290 miles from the Piceance Basin in Colorado to Blanco, New
Mexico, and has a capacity of 300 MMcf per day.
CONTRACTS AND CUSTOMERS. The Company's interstate pipeline system provides
transportation and storage services to affiliates, third-party natural gas
distribution utilities and other shippers. Pursuant to transportation agreements
and FERC tariff provisions, K N offers its customers firm and interruptible
transportation and no-notice services. Under K N'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, time of year and
distance of the transportation service provided. Under no-notice service,
customers pay a fee for the right to have up to a specified volume of natural
gas transported but, unlike with firm transportation service, are able to meet
their peak day requirements without making specific nominations. NGPL'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, NGPL collects higher transportation commodity revenue, higher
interruptible transportation revenue, winter only capacity revenue and higher
peak rates on certain contracts.
NGPL's principal delivery market area encompasses the states of Illinois,
Indiana and Iowa and portions of Wisconsin, Nebraska, Kansas, Missouri and
Arkansas. NGPL is one of the largest transporters of gas to the Chicago market
and the Company believes that its cost of service is one of the most competitive
in the region. In 1998, NGPL delivered an average of 4.1 Bcf per day of natural
gas to this market. Given its strategic location at the center of the North
American pipeline grid, the Company believes 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 NGPL's pipeline capacity to Chicago is committed under firm
transportation contracts ranging from one to five years. As of December 31,
1998, approximately 81% of the total transportation volume committed under
NGPL's firm transportation contracts had remaining terms of less than three
years. K N continues to actively pursue the renegotiation, extension and/or
replacement of expiring contracts. During 1999, contracts representing 30% of
NGPL's total system capacity are scheduled to expire.
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Unlike NGPL, MidCon Texas acts as a merchant provider of natural gas as well as
a transporter. Principal customers of MidCon Texas include the electric and
natural gas utilities that serve the Houston area and industrial customers
located along the Houston Ship Channel and in the Beaumont/Port Arthur area.
Contract terms for the major utilities will expire between 2002 and 2004. Other
contracts vary in length from month-to-month to five or more years. During 1998,
MidCon Texas delivered an average of 1.735 Bcf per day of natural gas to this
area.
The transport and storage customers of K N's West Texas intrastate system
include electric utilities, irrigators, industrials, LDCs and gas marketers.
Approximately 53% of the transport is performed for the Company's marketing
affiliate. Contract terms range from month-to-month to five or more years.
Approximately 13% of KNI's contracts expire within one year, 34% expire within
one to five years and 53% expire in more than five years. Over 90% of the
system's firm transport capacity is currently subscribed, with firm transport
demand revenues accounting for more than 90% of the revenues on the system.
STORAGE
Through NGPL, the Company is one of the nation's largest natural gas storage
operators with approximately 600 Bcf of total natural gas storage capacity, over
200 Bcf of working gas capacity and up to 3.9 Bcf per day of peak deliverability
from its facilities, which are located near the markets NGPL serves. NGPL owns
and operates nine underground storage fields in four states. These storage
assets complement the Company's pipeline facilities and allow K N to optimize
deliveries on its pipelines and meet peak delivery requirements in its principal
markets. NGPL provides firm and interruptible gas storage service pursuant to
storage agreements and FERC-approved tariffs. Firm storage customers pay a
monthly demand charge irrespective of actual volumes stored. Interruptible
storage customers pay a monthly commodity charge based upon actual volumes of
gas stored.
Through MidCon Texas, the Company also developed a salt dome storage facility
located near Markham, Texas with a subsidiary of NIPSCO Industries, Inc.
("NIPSCO"). The facility has two salt dome caverns and approximately 8.3 Bcf of
total storage capacity, over 5.7 Bcf of working gas capacity and up to 500 MMcf
per day of peak deliverability. The storage facility is leased by a partnership
in which subsidiaries of MidCon Texas and NIPSCO are equal partners. MidCon
Texas has executed a 20-year sublease with the partnership under which it has
rights to 50% of the facility's working gas capacity, 85% of its withdrawal
capacity and approximately 70% of its injection capacity.
Through KNI, the Company provides storage services to its customers from its
Huntsman Storage Field in Cheyenne County, Nebraska. The facility has 39.4 Bcf
of total storage capacity, 7.9 Bcf of working gas capacity, and up to 101 MMcf
of peak withdrawal capacity.
Through Northern Gas Company, the Company provides storage services in Wyoming
to its customers from its three storage fields, Oil Springs, Bunker Hill and
Kirk Ranch, with a combined 29.7 Bcf of total storage capacity, 11.7 Bcf of
working gas capacity, and up to 36 MMcf of peak withdrawal capacity.
Through Wildhorse, the Company has 10.1 Bcf of total storage capacity in Pitkin
and Mesa Counties in Colorado, 2.7 Bcf of working gas capacity, and up to 15
MMcf of peak withdrawal capacity.
Through American Gas Storage, the Company provides storage services from two gas
reservoirs and three salt caverns located in Gaines County, Texas, through which
the Company has a combined 25.2 Bcf of total storage capacity, 16.4 Bcf of
working gas capacity, and up to 500 MMcf of peak withdrawal capacity.
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Through AOG Gas Transmission Co., L.P., the Company provides storage services
from the Stratton Ridge salt dome located in Brazoria County, Texas. The Company
has 6.0 Bcf of total storage capacity, 3.5 Bcf of working gas capacity, and up
to 150 MMcf of peak withdrawal capacity.
DOWNSTREAM BUSINESS SEGMENT
K N's Downstream operations principally consist of energy marketing, regulated
natural gas distribution, merchant power and distributed generation. In
addition, this segment also includes unregulated retail services and the
supplying of an array of products and services for the deregulated energy market
through en*able, a fifty-fifty joint venture between K N and PacifiCorp Holdings
Corp. ("PacifiCorp").
ENERGY MARKETING
In the energy marketing area, the Company performs a merchant function whereby
the Company purchases gas supplies at the wellhead, combines such gas with other
supplies of gas, and markets the aggregated gas to consumers. In addition, the
Company provides gas marketing and supply services, including certain storage
services, to producers, various LDCs and end-users. The Company also arranges
the purchase and transportation of producers' excess or uncommitted gas to end
users, acts as shipper or agent for the end users, administers nominations and
provides balancing assistance when needed.
The Company's natural gas marketing customers include LDCs, industrial,
commercial and agricultural end users, electric utilities, Company affiliates,
and other marketers located both on and off K N's pipeline systems. The
Company's Downstream segment sells an average of approximately 3.4 Bcf of gas
per day to third parties.
Natural gas is purchased by K N's Downstream business segment from various
sources, including gas producers, gas processing plants and pipeline
interconnections. As is customary in the industry, most of the Company's gas
purchase agreements are for periods of one year or less, and many are for
periods of 60 days or less. Various agreements permit the purchaser or the
supplier to renegotiate the purchase price or discontinue the purchase under
certain circumstances. Purchase volume obligations under many of the agreements
utilized by this business segment are generally "best efforts" and do not have
traditional take-or-pay provisions. However, certain agreements require the
Company to prepay for, or to receive, minimum quantities of natural gas. Natural
gas is sold to marketing customers pursuant to short-term agreements with both
fixed and index-based pricing.
In conjunction with its merchant function, the Company engages in price risk
management activities in the energy financial instruments market to hedge
certain of its price and basis risk exposure. The Company buys and sells gas and
crude oil futures on the New York Mercantile Exchange and Kansas City Board of
Trade and uses over-the-counter energy swaps and options for the purpose of
reducing adverse price exposure to gas supply costs or specific market margins.
Pursuant to its Board of Directors' approved trading policy, the Company manages
its commodity exposure through constant monitoring of its exposure and
maintenance of proper controls in order to ensure compliance with the
volumetric, mark-to-market and value-at-risk restrictions contained in the
policy.
RETAIL NATURAL GAS DISTRIBUTION
As of December 31, 1998, the Company's retail natural gas business served over
216,000 customers in Colorado, Nebraska and Wyoming through approximately 7,400
miles of distribution pipelines. The Company's intrastate pipelines,
distribution facilities and retail sales in Colorado and Wyoming are subject to
the regulatory authority of each state's utility commission. In Nebraska, retail
gas sales rates for residential and small commercial customers are regulated by
each municipality served.
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The Company's retail operations in Nebraska, Wyoming and northeastern Colorado
serve areas that are primarily rural and agriculturally based where 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 in the fall.
To support its domestic retail business, the Company utilizes its underground
storage facilities to provide gas for load balancing and peak system demand.
Storage services for the Company's retail natural gas services are provided by
three facilities in Wyoming owned by Northern Gas Company, one facility in
Colorado owned by Wildhorse, and one facility located in Nebraska and owned by
KNI. The peak natural gas withdrawal capacity available for the Company's retail
business is approximately 99 MMcf per day.
The Company's domestic retail natural gas business relies on the Company's
interstate pipeline systems, the intrastate pipelines it operates and
third-party pipelines for transportation and storage services required to serve
its markets. The gas supply requirements for K N's domestic retail natural gas
business are met through a combination of purchases from marketing affiliates
and third-party suppliers.
In May 1997, the Mexico Energy Regulatory Commission awarded a franchise to Gas
Natural De Noroeste ("GNN"), a joint venture in which K N has a 75% interest, to
construct and operate an LDC in the cities of Hermosillo, Guaymas and Empalme in
western Mexico. The franchise grants GNN exclusive rights in the region for 12
years and distribution rights for 30 years. Pursuant to this franchise, GNN will
construct a distribution system to connect at least 26,250 residential,
commercial and industrial customers by June 2002. Construction began in April
1998, with a projected capital investment of $21.3 million. On September 30,
1998, GNN opened its distribution system and began supplying 2.5 MMcf of natural
gas per day to industrial customers. GNN's approved rates of return are 16.9%,
with exchange rate protection for dollar/peso conversion.
RETAIL SERVICES
en*able has been developed as a energy deregulation "superstore," offering a
wide array of turnkey and individualized solutions to the energy industry and
others that desire to compete in a deregulated energy market. en*able sells a
full range of services through Simple Choice which, in partnership with local
utilities, provides consumers an opportunity to purchase home, entertainment,
energy and communication products and services with "one call, one bill and one
check." Through licensing agreements, Simple Choice offers utilities across the
country a means of reinforcing their brand and developing greater customer
loyalty. en*able is a limited liability company owned equally by K N Energy and
PacifiCorp. en*able was founded in January 1997 to develop and deliver effective
means of creating more substantial customer relationships to energy providers
across the nation through the Simple Choice brand, and other back office and
marketing support efforts. en*able's wholly owned subsidiary, Orcom Solutions,
is a developer of customer care software solutions.
POWER SERVICES
K N's new power service businesses position the Company to take advantage of the
rapidly changing energy industry and leverage markets with cross commodity
opportunities in convergent energy markets. The Company plans to acquire and
develop gas-fired merchant power generation assets, develop and implement
distributive generation strategy, optimize electric activities in K N's
facilities, monitor and participate in industry restructuring and leverage value
stream assets to create new revenue streams. The Company is currently in the
process of site selection and permitting for a 510 megawatt power plant in Lake
County, Illinois.
K N's acquisition of interests in Thermo provided K N with its first electric
generation assets as well as the
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knowledge and expertise of Thermo's management necessary to undertake the
development of merchant power plants along its pipeline assets. Thermo has
interests in four independent power plants in Colorado representing
approximately 380 megawatts of electric generation capacity with access to
approximately 130 BCF of natural gas reserves.
REGULATION
FEDERAL AND STATE REGULATION
Both the performance of interstate transportation and storage services by
natural gas companies, including interstate pipeline companies, and the rates
charged for such services, are regulated by the FERC under the Natural Gas Act
and, to a lesser extent, the Natural Gas Policy Act.
Legislative and regulatory changes began in 1978 with the passage of the Natural
Gas Policy Act, pursuant to which the process of deregulation of gas sold at the
wellhead was commenced. The restructuring of the natural gas industry continued
with the adoption of (i) Order 380 in 1984, which eliminated purchasers' minimum
bill obligations to the pipelines, thus making gas purchased from third parties,
particularly on the spot market, more economically attractive relative to gas
purchased from pipelines and (ii) Order 436 in 1985, which provided that
interstate transportation of gas under blanket or self-implementing authority
must be provided on an open-access, non-discriminatory basis. After Order 436
was partially overturned in federal court, the FERC issued Order 500 in August
1987 as an interim rule intended to readopt the basic thrust of the regulations
promulgated by Order 436. Order 500 was amended by Orders 500 A through L. The
FERC's stated purpose in issuing Orders 436 and 500, as amended, was to create a
more competitive environment in the natural gas marketplace. This purpose
continued with Order 497, issued in June 1988, which set forth new standards and
guidelines imposing certain constraints on the interaction of interstate
pipelines and their marketing affiliates and imposing certain disclosure
requirements regarding that interaction.
Order 636, issued in April 1992, as amended, was a continuation of the FERC's
efforts to improve the competitive structure of the pipeline industry and
maximize the consumer benefits of a competitive structure of the pipeline
industry and a competitive wellhead gas market. In Order 636, the FERC required
interstate 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 gas supplies whether
purchased from the pipeline or from other merchants such as marketers or
producers. The pipelines must now separately state the applicable rates for each
unbundled service (i.e., for the gas commodity, transportation and storage).
Specifically, Order 636 contains the following procedures to increase
competition in the industry: (i) requiring the unbundling of sales services from
other services, meaning that only a separately identified merchant affiliate of
the pipeline could sell gas at points of entry into the pipeline system; (ii)
permitting holders of firm capacity to release all or a part of their capacity
for resale by the pipeline either to the highest bidder or, under short-term or
maximum rate releases, to shippers in a prepackaged release, with revenues in
both instances credited to the releasing shipper; (iii) allowing shippers to use
as secondary points other receipt points and delivery points on the system,
subject to the rights of other shippers to use those points as their primary
receipt and delivery points; (iv) the issuance of blanket sales certificates to
interstate pipelines for unbundled services; (v) the continuation of pregranted
abandonment of previously committed pipeline sales and transportation services,
subject to certain rights of first refusal, which should make unused pipeline
capacity available to other shippers and clear the way for excess transportation
services to be reallocated to the marketplace; (vi) requiring that firm and
interruptible transportation services be provided by the pipelines to all
parties on a comparable basis; and (vii) generally
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requiring that pipelines derive transportation rates using a
straight-fixed-variable rate method which places all fixed costs in a fixed
reservation fee that is payable without regard to usage, as opposed to the
previously used modified fixed-variable method that allocated a part of the
pipelines' fixed costs to the usage fee. The FERC's stated position is that the
straight-fixed-variable method promotes the goal of a competitive national gas
market by increasing the cost of unnecessarily holding firm capacity rather than
releasing it, and is consistent with its directive to unbundle the pipelines'
traditional merchant sales services. Order 636 has been affirmed in all material
respects upon judicial review and the Company's own FERC orders approving its
unbundling plans are final and not subject to any pending judicial review.
NGPL has been a party to a number of contracts that required NGPL to purchase
natural gas at prices in excess of the prevailing market price. As a result of
Order 636 prohibiting interstate pipelines from using their gas transportation
and storage facilities to market gas to sales customers, NGPL no longer had a
sales market for the gas it is required to purchase under these contracts. Order
636 went into effect on NGPL's system on December 1, 1993. NGPL has agreed to
pay substantial transition costs to reform these contracts with gas suppliers.
Under settlement agreements reached by NGPL and its former sales customers, NGPL
recovered from those customers over a four-year period beginning December 1,
1993, a significant amount of the gas supply realignment "GSR" costs. The FERC
has also permitted NGPL to implement a tariff mechanism to recover additional
portions of its GSR costs in rates charged to transportation customers that were
not party to the settlements. In July 1996, a Federal appellate court remanded
Order 636 to the FERC for further explanation of aspects of its decision
regarding recovery of GSR costs by interstate pipelines. Because of the
settlements and FERC orders authorizing NGPL's GSR cost recovery mechanism, the
remand is not expected to have any significant impact on NGPL. The FERC has
allowed GSR rates to go into effect on December 1, 1997, subject to refund, to
recover any shortfall in recoveries of GSR costs allocated to interruptible
transportation. However, the FERC rejected NGPL's filing for rehearing that NGPL
be allowed to recoup a portion of any shortfall on title transfers and
interruptible transportation to pooling points.
GATHERING AND PROCESSING SERVICES
Under the Natural Gas Act, facilities used for, and operations involving, the
production and gathering of natural gas are exempt from the FERC's jurisdiction,
while facilities used for and operations involving interstate transmission are
not exempt. However, the FERC's determination of what constitutes exempt
gathering facilities as opposed to jurisdictional transmission facilities has
evolved over time. Under current law, facilities which otherwise are classified
as gathering may be subject to ancillary FERC rate and service jurisdiction when
owned by an interstate pipeline company and used in connection with interstate
transportation or jurisdictional sales. The FERC determines jurisdictional
status on a fact-specific basis.
The issue of state jurisdiction over gathering activities has previously been
raised before the Colorado Public Utilities Commission, Kansas Corporation
Commission, Oklahoma Corporation Commission, New Mexico Public Service
Commission, Texas Railroad Commission and Wyoming Public Service Commission, as
well as before state legislative bodies. The Company is closely monitoring
developments in this area.
The Company requested, was granted authority and in 1994 transferred
substantially all of its gathering facilities to a wholly-owned subsidiary. The
FERC determined that after the transfer the gathering facilities would be
nonjurisdictional, but the FERC reserved the right to reassert jurisdiction if
the Company was found to be operating the facilities in an anti-competitive
manner or contrary to open access principles. The Company plans to transfer
MidCon's gathering facilities to a wholly-owned subsidiary in order to make such
facilities nonjurisdictional.
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INTRASTATE TRANSPORTATION AND MARKETING SERVICES
The operations of the Company's intrastate pipeline and marketing subsidiaries
located primarily in Texas 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 gas for any party requesting such service.
INTERSTATE TRANSPORTATION AND STORAGE SERVICES
Facilities for the transportation of natural gas in interstate commerce and for
storage services in interstate commerce are subject to regulation by the FERC
under the Natural Gas Act and the Natural Gas Policy Act. The acquisition of
MidCon's interstate natural gas pipeline system has resulted in a significant
increase in the percentage of the Company's assets subject to regulation by the
FERC. The Company is 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 pipeline of its marketing affiliates and
govern in particular the provision of information by an interstate pipeline to
its marketing affiliates.
On June 1, 1995, NGPL filed a general rate case with the FERC to establish new
rates as well as new or revised services. The FERC permitted NGPL to place new
rates into effect, subject to refund, on December 1, 1995. This date
corresponded to the effective date of new transportation and storage agreements
between NGPL and its principal local distribution customers. Major issues in the
rate case included the terms and conditions of new services, throughput levels
used in the design of rates, discounting adjustments, levels of depreciation
rates and return on investment, and the levels used in the design of fuel rates.
In May 1996, NGPL filed with the FERC an offer of settlement to resolve the
remaining issues in the proceeding. On November 3, 1997, the FERC approved a
settlement of this rate case substantially consistent with what NGPL proposed.
The FERC's order approving the settlement is final and not subject to rehearing
or judicial review.
In January 1997, Amoco Production Company and Amoco Energy Trading Corporation
("Amoco") filed a complaint against NGPL before the FERC contending that NGPL
had improperly provided its affiliate, MidCon Gas, transportation service on
preferential terms, seeking termination of currently effective contracts and the
imposition of civil penalties. A subsequent FERC staff audit made proposed
findings that NGPL had favored MidCon Gas, which NGPL has challenged. In July
1997, Amoco and NGPL agreed to a settlement of this proceeding. Amoco filed to
withdraw its complaint subject to the FERC's procedures. Several intervenors
opposed the withdrawal of the complaint and NGPL filed an answer to that
opposition. By orders issued January 16, 1998 (the "January Order"), the FERC
ruled that NGPL had violated certain of the FERC's regulations regarding its
business relationships with its affiliate, MidCon Gas. Relying upon its
authority under the Natural Gas Policy Act, the FERC provided notice to NGPL
that, in addition to other remedial action, it proposed to assess civil
penalties of $8,840,000. Such orders also required NGPL to take certain other
actions, including making a new tariff filing, and imposed certain restrictions
on the sharing of employees by NGPL and MidCon Gas. The FERC proposed to suspend
one-half of the penalty provided that for two years following the date of the
order NGPL does not violate specified sections of the FERC's regulations. The
Company and other parties sought rehearing in February 1998. The Company also
made several filings in compliance with the January Order, including payment of
the $4.42 million civil penalty. On March 26, 1998, the FERC issued an order
denying all rehearing requests, including those of several parties which had
argued for more onerous penalties or restrictions. The Company and the
Interstate Natural Gas Association of America sought further rehearing and
clarification in April 1998. On May 27, 1998, the FERC issued an order denying
rehearing, but granting, in part, the petitioners' request for clarification.
The Company has sought judicial review of the FERC's orders in the
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U.S. Court of Appeals for the District of Columbia. The Company does not believe
the ultimate resolution of these issues will have a material adverse affect on
its operations and results.
In January 1998, KNI filed a rate case requesting an increase in its rates that
would result in additional annual revenues of $30.2 million. The filing included
the costs of KNI's newly constructed Pony Express pipeline facilities. The FERC,
by an order dated February 26, 1998, accepted the filing and suspended its
effective date for the full five-month period permitted by the Natural Gas Act
thus permitting the rates to go into effect subject to refund August 1, 1998.
Various parties intervened in the proceedings. The administrative law judge
issued an order dated November 5, 1998 finding that KNI had not made a prima
facie case for rolled-in treatment of the Pony Express pipeline facilities. KNI
and others sought FERC review of the order, and on March 3, 1999, the FERC
issued an order affirming the decision of the administrative law judge. The
order held that the Pony Express costs should be removed from the case, that KNI
should charge rates applicable to its preexisting system to Pony Express
shippers, that certain refunds were due, and that KNI can file in the future for
rolled-in or incremental rate treatment of the Pony Express facilities.
Additional proceedings are ongoing before the FERC to resolve differences. The
Company will pursue a negotiated resolution of any differences but the Company
cannot predict with certainty whether the regulatory proceedings will be
resolved through a negotiated settlement or through administrative litigation.
The Company's interstate pipeline business could be adversely affected by an
unsatisfactory outcome.
RETAIL NATURAL GAS SERVICES
Certain of the Company's intrastate pipelines, storage, distribution and/or
retail sales in Colorado, Texas and Wyoming are under the regulatory authority
of each state's utility commission. In Nebraska, certain retail gas sales rates
for residential and small commercial customers are regulated by the municipality
served.
In certain of the incorporated communities in which the Company provides retail
natural gas services, the Company operates under franchises granted by the
applicable municipal authorities. The duration of theses franchises varies. In
unincorporated areas, the Company's natural gas utility services are not subject
to municipal franchise. The Company has been issued various certificates of
public convenience and necessity by the regulatory commissions in Colorado and
Wyoming authorizing it to provide natural gas utility services within certain
incorporated and unincorporated areas of those states.
Continuing regulatory change will provide energy consumers with increasing
choices among their suppliers. The Company emerged as a leader in providing for
customer choice by filing an application with the Wyoming Public Service
Commission in 1995 to allow 10,500 residential and commercial customers to
choose to purchase the gas from a qualified list of suppliers. The proposal
provided that the Company would continue to provide all other utility services.
In early 1996, the Wyoming Public Service Commission issued an order allowing
the Company to bring competition to these 10,500 residential and commercial
customers beginning in mid 1996. Choosing from a menu of three competing
suppliers, approximately 80% of the Company's customers chose to remain with the
Company. The experience gave the Company early and valuable experience in
competing in an unbundled environment and led to the development of new products
and services. The innovative program was one of the first in the nation that
allowed essentially all customers the opportunity to exercise energy choice for
natural gas. In November 1997, the Company 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, 1998, the plan had been approved by 176 communities,
representing approximately 95,000 customers served by the Company in Nebraska.
ENVIRONMENTAL REGULATION
The Company's 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 difficult and costly to comply with and which carry substantial
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.
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The U.S. Environmental Protection Agency ("EPA") recently published a final rule
addressing transport of ground level ozone. The rule affects 22 Eastern and
Midwestern states, including Illinois and Missouri in which the Company operates
gas compression facilities. The rule requires reductions in emissions of
nitrogen oxide, a precursor to ozone formation, from various emission sources,
including utility and non-utility sources. The rule requires that the affected
states prepare and submit State Implementation Plans to the EPA by September
1999, reflecting how the required emissions reductions will be achieved.
Emission controls are required to be installed by May 1, 2003. This rule will
likely result in the Company, as well as its competitors, being required to
install some form of new emissions control technology on certain equipment it
operates. Another impact from the rule is that it may result in broad increased
use of natural gas, as other sources of nitrogen oxide air emissions, including
utilities, seek to achieve the reductions required under the rule. The State
Implementation Plans which will effectuate this rule have yet to be proposed or
promulgated, and will require detailed analysis before their final economic
impact can be ascertained. While additional capital costs are likely to result
from this rule, based on currently available information, the Company does not
believe that these costs will have a material adverse effect on its business,
financial position or results of operations.
On February 6, 1998, the EPA published in the Federal Register a proposed
standard to limit emissions of hazardous air pollutants ("HAPs") from oil and
natural gas production as well as from natural gas transmission and storage
facilities. This is a Maximum Achievable Control Technology ("MACT") standard,
and is mandated under section 112 of the 1990 Amendments to the Clean Air Act.
The proposed MACT standard requires that the affected facilities reduce
emissions of HAPs by 95%. This new standard will require the Company to achieve
this reduction either by process modifications or by installing new emissions
control technology. The MACT standard will affect the Company and its
competitors in a like manner. The USEPA has stated that the standard will be
promulgated in its final form by May 15, 1999. The rule will allow most affected
sources three years to come into compliance. The rule in its final form will
require detailed analysis to determine its overall affect on the Company. While
additional capital costs are likely to result from this rule, the Company
believes that the rule will not have a material adverse effect on the Company's
business, financial position or results of operations.
Based on current information and taking into account reserves established for
environmental matters, the Company does not believe that compliance with
Federal, state and local environmental laws and regulations will have a material
adverse effect on the Company's business, financial position or results of
operations. In addition, the clean-up programs in which the Company is engaged
are not expected to interrupt or diminish the Company's operational ability to
gather or transport natural gas. 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 the Company to incur
significant costs.
Other
Amounts spent by the Company during 1998, 1997 and 1996 on research and
development activities were not material.
(C) Financial Information About Foreign and Domestic Operations and Export
Sales
Substantially all of the Company's operations are in the contiguous 48 states.
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ITEM 3: LEGAL PROCEEDINGS
On October 9, 1992, Jack J. Grynberg filed suit in the United States District
Court for the District of Colorado against the Company, RMNG and GASCO, Inc.
(the "K N Entities") alleging that 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 defendant companies have engaged in
an illegal exercise of monopoly power, have illegally denied him economically
feasible access to essential facilities to transport and distribute gas produced
from fewer than 20 wells located in northwest Colorado, and have illegally
attempted to monopolize or to enhance or maintain an existing monopoly. Grynberg
also asserts certain causes of action relating to a gas purchase contract. On
February 5, 1999, the Federal District Court granted summary judgment regarding
some of Grynberg's antitrust and state law claims, while allowing other claims
to proceed to trial. The Company's potential liability and the amount of such
damages, if any, are subject to dispute between the parties; however, the
Company believes it has a meritorious position in these matters and does not
expect this lawsuit to have a material adverse effect on the Company's business,
financial position or results of operations. In July 1996, the U.S. District
Court, District of Colorado lifted its stay and allowed discovery for a period
of time. Currently, this case is still pending. Discovery is now complete, but
no trial date has yet been set.
On July 26, 1996, the Company and RMNG, along with over 70 other natural gas
companies, were served by Jack J. Grynberg, acting on behalf of the Government
of the United States, with a Civil False Claims Act lawsuit alleging
mismeasurement of the heating content and volume of natural gas resulting in
underpayment of royalties to the federal government. The Company and the other
named companies filed a motion to dismiss the lawsuit on grounds of improper
joinder and lack of jurisdiction. The motion was granted in 1997, but the court
gave Mr. Grynberg leave to refile this action in a court with proper
jurisdiction. Mr. Grynberg appealed the dismissal of the action based on
improper joinder, and the D.C. Court of Appeals affirmed the joinder decision in
October 1998. Mr. Grynberg has filed a new case, modified somewhat from his
original action, in Federal District Court, District of Colorado. The Company
has not yet been served in this new action, which is under seal pending federal
governmental reviews of the merits. The Department of Justice has not yet made a
decision regarding whether to intervene in this new case. The Company has
engaged in both formal and informal discussions with the Government regarding
this case. The Company believes it has a meritorious position in this matter,
and does not expect this lawsuit to have a material adverse effect on the
Company's business, financial position or results of operations.
Pursuant to certain acquisition agreements involving Cabot Corporation
("Cabot"), Cabot indemnified the Company for certain environmental liabilities
associated with assets in Texas, Oklahoma and New Mexico acquired from American
Oil and Gas Corporation. Issues arose concerning Cabot's indemnification
obligations, and the Company and Cabot entered into binding arbitration to
resolve all issues in dispute. The binding decision of the arbitrators resulted
in the requirement that Cabot pay the Company for a substantial portion of past
and future environmental related costs associated with the properties. In
December 1998, the Company recorded a charge of approximately $7.2 million
representing both previously incurred costs which were not awarded in the
arbitration and the recognition of a liability for the Company's share of
estimated future costs. As a result of this settlement, the Company will have no
future expense associated with this matter. The Company does not expect its
potential exposure for the remaining liabilities to have a material adverse
effect on the Company's business, financial position or results of operations.
The Company believes it has meritorious defenses to all lawsuits and legal
proceedings in which it is a defendant and will vigorously defend against them.
Based on its evaluation of the above matters, and after consideration of
reserves established, the Company believes that the resolution of such matters
will not have a material adverse effect on the Company's business, financial
position or results of operations.
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EXECUTIVE OFFICERS OF THE REGISTRANT
(A) Identification and Business Experience of Executive Officers
Name Age Position and Business Experience
- ------------------------------------------------- --- ------------------------------------------------------
Morton C. Aaronson............................... 40 Chief Marketing Officer since April 1996. Vice
President since January 1996. Vice President, MCI/
NewsCorp. Business Development from May 1995 to
January 1996. Vice President, Market Management, MCI
Communications Corporation from August 1994 to May
1995. Vice President, Large Accounts and Global
Markets, MCI Communications Corporation, from July
1993 to August 1994. Director, Major Accounts
Marketing, MCI Communications Corporation from July
1992 to July 1993.
John N. DiNardo.................................. 51 Vice President and General Manager since April 1996.
Vice President - Gas Gathering and Processing from
March 1994 to April 1996. General Manager, K N Gas
Gathering, Inc. and K N Front Range Gathering Company
from May 1993 to March 1994. Director of Project
Development, K N Gas Gathering, Inc. from August 1991
to May 1993.
Jack W. Ellis II................................. 45 Vice President and Controller since December 1997.
Vice President and Controller, NorAm Energy Corp.
from December 1989 to August 1997.
Larry D. Hall.................................... 56 Chairman of the Board since April 1996. Chief
Executive Officer since July 1994. President from May
1988 to July 1998. Chief Operating Officer from May
1988 to July 1994. Director since 1984.
Rose M. Robeson.................................. 38 Vice President and Treasurer since April 1998.
Assistant Treasurer from 1996 to 1998. Assistant
Treasurer of Total Petroleum, Inc. from 1992 to 1996.
Clyde E. McKenzie................................ 51 Vice President and Chief Financial Officer since
April 1996. Vice President and Treasurer, Apache
Corporation from 1988 to 1996.
Iain "Skip" Paterson............................. 45 Vice President, Human Resources since July 1998.
Director of Human Resources for BellSouth Cellular Corp.
from June 1992 to June 1998.
John F. Riordan................................. 63 Director since February 1998. Vice Chairman of the Board
from February 1998 to February 1999. President and Chief
Executive Officer of MidCon Corp. from 1990 to January
1998. Executive Vice President and Director of Occidental
Petroleum Corporation from 1991 to January 1998.
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John H. Weber.................................... 43 President and Chief Operating Officer since August
1998. Executive Vice President of Aeroquip-Vickers
and President Vickers, Incorporated from August 1996
to August 1998. Executive Vice President of Vickers,
Incorporated from January 1996 to August 1996. Group
Vice President - Industrial of Vickers, Incorporated
from 1994 to August 1996. General Manager Industrial
Motors of General Electric Company from 1992 to 1994.
H. Rickey Wells.................................. 42 Executive Vice President since November 1998. Vice
President - Business Operations from April 1996 to
November 1998. Vice President, Operations from June
1988 to April 1996.
Martha B. Wyrsch................................. 41 Vice President, General Counsel and Secretary since
August 1997. Vice President, Deputy General Counsel
and Secretary from April 1996 to August 1997. Deputy
General Counsel from November 1995 to April 1996.
Assistant General Counsel from June 1995 to November
1995. Senior Counsel from June 1993 to June 1995.
These officers generally serve until April of each year.
(B) Involvement in Certain Legal Proceedings
None.
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PART II
ITEM 5: MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER
MATTERS
The Company's common stock is listed for trading on the New York Stock Exchange
under the symbol KNE. Dividends paid and the price range of the Company's common
stock by quarter for the last two years are provided below. All amounts have
been restated to reflect the three-for-two split of the Company's common stock
effective December 31,1998.
1998 1997
---- ----
Market Price Data
(Low-High-Close)
Quarter Ended:
March 31 $33.328 - $39.375 - $39.375 $24.078 - $27.828 - $26.328
June 30 $32.797 - $40.328 - $36.125 $24.578 - $28.750 - $28.078
September 30 $25.000 - $36.125 - $34.172 $26.000 - $31.953 - $30.500
December 31 $22.328 - $34.922 - $24.250 $27.328 - $36.000 - $36.000
Dividends
Quarter Ended:
March 31 $0.1867 $0.1800
June 30 $0.1867 $0.1800
September 30 $0.1867 $0.1800
December 31 $0.2000 $0.1867
Common Stockholders
Year-end 9,659 10,090
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ITEM 6: SELECTED FINANCIAL DATA
FIVE-YEAR REVIEW
K N ENERGY, INC. AND SUBSIDIARIES
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
(In Thousands, Except Per Share Amounts)
OPERATING REVENUES:
Upstream Gathering and
Processing $ 604,830 $ 553,932 $ 357,533 $ 208,071 $ 228,098
Midstream Sales,
Transportation
and Storage 1,504,644 231,108 266,737 303,382 209,449
Downstream Retail and
Marketing 2,801,335 1,669,945 1,164,512 869,609 863,820
Gas and Oil Production -- -- -- 7,437 11,328
Intersegment Eliminations (522,966) (306,004) (348,300) (277,101) (221,418)
----------- ----------- ----------- ----------- -----------
Total Operating Revenues $ 4,387,843 $ 2,148,981 $ 1,440,482 $ 1,111,398 $ 1,091,277
=========== =========== =========== =========== ===========
OPERATING INCOME $ 344,551 $ 146,112 $ 134,801 $ 115,362 $ 54,879
Other Income and (Deductions) (246,290) (32,954) (35,085) (33,790) (30,058)
----------- ----------- ----------- ----------- -----------
INCOME BEFORE INCOME TAXES 98,261 113,158 99,716 81,572 24,821
Income Taxes 38,272 35,661 35,897 29,050 9,500
----------- ----------- ----------- ----------- -----------
NET INCOME 59,989 77,497 63,819 52,522 15,321
Less - Preferred Stock
Dividends 350 350 398 492 630
----------- ----------- ----------- ----------- -----------
EARNINGS AVAILABLE FOR
COMMON STOCK $ 59,639 $ 77,147 $ 63,421 $ 52,030 $ 14,691
=========== =========== =========== =========== ===========
DILUTED EARNINGS PER
COMMON SHARE $ 0.92 $ 1.63 $ 1.43 $ 1.22 $ 0.35
=========== =========== =========== =========== ===========
DIVIDENDS PER COMMON SHARE $ 0.76 $ 0.73 $ 0.70 $ 0.67 $ 0.51
=========== =========== =========== =========== ===========
NUMBER OF SHARES USED IN
COMPUTING DILUTED EARNINGS
PER COMMON SHARE 64,636 47,307 44,436 42,540 42,066
=========== =========== =========== =========== ===========
TOTAL ASSETS $ 9,612,212 $ 2,305,805 $ 1,629,720 $ 1,257,457 $ 1,172,384
=========== =========== =========== =========== ===========
CAPITAL EXPENDITURES $ 256,514 $ 311,093 $ 119,987 $ 79,313 $ 70,511
=========== =========== =========== =========== ===========
ACQUISITIONS $ 3,781,517 $ 153,756 $ 155,909 $ 35,897 $ 31,363
=========== =========== =========== =========== ===========
CAPITALIZATION:
Common Stockholders' Equity $ 1,216,821 25% $ 606,132 48% $ 519,794 55% $ 426,760 57% $ 393,686 54%
Preferred Stock 7,000 -- 7,000 -- 7,000 1% 7,000 1% 7,000 1%
Preferred Stock Subject to
Mandatory Redemption -- -- -- -- -- -- 572 -- 1,715 --
Preferred Capital Trust
Securities 275,000 6% 100,000 8% -- -- -- -- -- --
Long-Term Debt 3,300,025 69% 553,816 44% 423,676 44% 315,564 42% 334,644 45%
----------- --- ----------- --- ----------- --- ----------- --- ----------- ---
Total Capitalization $ 4,798,846 100% $ 1,266,948 100% $ 950,470 100% $ 749,896 100% $ 737,045 100%
=========== === =========== === =========== === =========== === =========== ===
BOOK VALUE PER COMMON SHARE $ 17.74 $ 12.63 $ 11.44 $ 10.13 $ 9.52
=========== =========== =========== =========== ===========
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21
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
GENERAL
The following discussion should be read in conjunction with the accompanying
consolidated financial statements and related notes. As discussed in Note 2 to
the accompanying consolidated financial statements, the Company has engaged in
acquisition and divestiture transactions which may affect the comparison of
results between periods. All per share amounts reflect the impact of the
December 31, 1998, three-for-two common stock split as discussed in Note 7 (D)
to the accompanying consolidated financial statements.
On February 22, 1999, Sempra Energy ("Sempra," an energy services holding
company based in San Diego, California) and the Company announced that their
respective boards of directors had approved a definitive agreement under which
Sempra and the Company would combine in a stock and cash transaction. This
merger is conditioned, among other things, upon the approvals of shareholders of
both companies as well as certain regulatory approvals, including approvals of
the Federal Energy Regulatory Commission and clearance under the
Hart-Scott-Rodino Antitrust Improvements Act of 1976. For additional
information, see Note 1 to the accompanying consolidated financial statements.
CONSOLIDATED FINANCIAL RESULTS
1998 1997 1996
--------- --------- ---------
(Dollars In Millions Except Per Share Amounts)
Operating Revenues $ 4,387.8 $ 2,149.0 $ 1,440.5
Gross Margin 987.8 421.1 378.7
Operating Income 344.6 146.1 134.8
Net Income 60.0 77.5 63.8
Diluted Earnings Per Share $ 0.92 $ 1.63 $ 1.43
Return on Average Common Equity 5.4% 13.7% 13.4%
The Company's results for 1998 reflect increases from 1997 of 104.2 percent in
operating revenues, 134.6 percent in gross margin and 135.9 percent in operating
income. These increases are due, in large part, to the inclusion of the results
of operations of MidCon Corp. ("MidCon") beginning with its January 30, 1998,
acquisition date.
The operating revenues, gross margin and operating income associated with each
of the Company's business segments were negatively affected during 1998 by (i)
low natural gas liquids ("NGLs") prices and associated reduced processing
margins and (ii) reduced pipeline basis differentials reflecting, in part,
weather-related reduction in demand as further described within the individual
segment discussions which follow. In addition, the results of operations for
1998 include (i) $5.8 million of pre-tax expense ($3.5 million after tax or
$0.05 per diluted share) associated with the January 30, 1998, acquisition of
MidCon by K N and (ii) the negative impact of items totaling approximately $27.8
million before tax ($17.0 million after tax or $0.26 per diluted share). The
pre-tax loss associated with these items includes (i) $7.2 million attributable
to settlement of the arbitration of certain environmental litigation as a result
of which the Company will have no future expense associated with this matter,
(ii) a loss of $3.1 million resulting from the sale of several under-performing
natural gas processing facilities, (iii) write-downs totaling approximately $8.8
million due to the revaluation of certain natural gas due from third-parties and
in underground storage and NGLs inventories to reflect current market values,
(iv) $3.7 million in increased allowances for uncollectible accounts receivable
and (v) $5.0 million of increased provisions for regulatory refund obligations.
These charges were partially offset by the $8.5 million pre-tax ($5.2 million
after tax or $0.08 per diluted share) gain from the sale of the Company's Kansas
distribution properties and the
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22
$10.9 million pre-tax ($6.7 million after tax or $0.10 per diluted share) gain
from the sale of certain microwave towers.
There was a significant increase in interest expense in 1998 and an increase in
the effective tax rate, see "Other Income and (Deductions)" and "Income Taxes"
elsewhere herein. Earnings per diluted share for 1998 declined by 43.6 percent
from 1997 reflecting, in addition to the decline in 1998 net income, an increase
of 36.6 percent in average shares outstanding, largely due to the March 1998
common stock issuance associated with the acquisition of MidCon (see Notes 2(D)
and 7(D) to the accompanying consolidated financial statements).
RESULTS OF OPERATIONS
Reflecting the Company's strategy of extracting margins from the various
segments of the energy value stream, the Company has segregated its results of
operations into "Upstream," "Midstream" and "Downstream" components. The
Company's Upstream operations consist of (i) natural gas gathering, (ii) natural
gas processing and (iii) NGLs extraction and marketing activities. Midstream
operations consist of transportation, storage and bundled sales transactions for
K N's interstate and intrastate pipelines. Downstream activities principally
consist of energy marketing, regulated natural gas distribution and electric
power generation and sales. For comparative purposes, the Company's previously
reported segment results have been restated to conform to the current
presentation. The following segment data are before intersegment eliminations.
UPSTREAM GATHERING AND PROCESSING 1998 1997 1996
- --------------------------------- -------- -------- --------
(Dollars In Millions Except Per Gallon Amounts)
Operating Revenues
Gas Sales $ 219.8 $ 156.2 $ 102.5
Natural Gas Liquids Sales 251.0 275.9 188.2
Gathering, Transportation and Other 134.0 121.8 66.8
-------- -------- --------
604.8 553.9 357.5
-------- -------- --------
Operating Costs and Expenses
Gas Purchases and Other Costs of Sales 473.7 391.0 244.5
Operations and Maintenance 111.8 77.6 54.3
Depreciation and Amortization 26.3 16.9 14.5
Taxes, Other Than Income Taxes 11.4 9.6 5.6
-------- -------- --------
623.2 495.1 318.9
-------- -------- --------
Operating (Loss) Income $ (18.4) $ 58.8 $ 38.6
======== ======== ========
Systems Throughput (Trillion Btus)
Gas Sales 116.8 70.7 60.6
Gathering and Transportation 343.5 298.4 280.2
-------- -------- --------
460.3 369.1 340.8
======== ======== ========
Natural Gas Liquids
Sales (Million Gallons) 902.7 717.4 464.6
======== -------- --------
Average Sales Price/Gallon $ 0.28 $ 0.38 $ 0.41
======== ======== ========
Operating revenues and operating expenses for Upstream increased by $50.9
million and $128.1 million, respectively, from 1997 to 1998 due primarily to the
effect of a full year of the results of operations of the Bushton processing
facility. Upstream operating income decreased from income of $58.8 million in
1997 to a loss of $18.4 million in 1998. This net decrease of $77.2 million
included $14.0 million of positive contribution from the 1998 operating results
of assets which were not included in 1997 operating results, including assets
acquired with the MidCon, Red Cedar Gathering Company and Interenergy
Corporation acquisitions. This positive impact was more than offset by
approximately $91.2 million of negative variance associated with assets owned
and operated during both periods. Approximately 55 percent of this negative
variance was attributable to decreased NGLs prices during 1998. The addition of
the Bushton facility in April 1997 was accretive to 1997 earnings. However, due
in part to its contract mix, this acquisition increased Upstream's sensitivity
to NGLs
22
23
prices and to the spread between NGLs prices and natural gas prices. The
remaining negative variance was principally due to the impacts of (i) increased
1998 downtime resulting from plant turnaround and installation of additional
measurement facilities, (ii) operational problems in 1998 associated with
deficient vendor performance, (iii) reduced 1998 pipeline basis differentials
which negatively affected joint venture marketing activities, (iv) 1998 NGLs
storage inventory write-downs and (v) reduced 1998 revenues from the sale of
NGLs marketing rights and processing agreements.
The significant increases in 1997 operating revenues, costs and expenses and
volumetric data over 1996 largely reflect the acquisition of the Bushton
gathering and processing assets effective April 1, 1997. Increased 1997
operating income from the Bushton assets was partially offset by lower 1997 NGLs
prices received at other processing facilities.
MIDSTREAM SALES, TRANSPORTATION AND STORAGE 1998 1997 1996
- ------------------------------------------- -------- -------- --------
(Dollars In Millions)
Operating Revenues
Transportation and Storage $ 652.5 $ 126.5 $ 112.8
Gas Sales 832.8 92.7 140.3
Other 19.3 11.9 13.6
-------- -------- --------
1,504.6 231.1 266.7
-------- -------- --------
Operating Costs and Expenses
Gas Purchases and Other Costs of Sales 754.9 94.7 134.2
Operations and Maintenance 209.6 54.6 56.4
Depreciation and Amortization 155.0 27.6 24.9
Taxes, Other Than Income Taxes 33.0 8.7 8.1
-------- -------- --------
1,152.5 185.6 223.6
-------- -------- --------
Operating Income $ 352.1 $ 45.5 $ 43.1
======== ======== ========
Systems Throughput (Trillion Btus) 2,421.2 503.2 529.7
======== ======== ========
Midstream operating income increased from $45.5 million in 1997 to $352.1
million in 1998. This increase in operating income, as well as the significant
increases in operating revenues, operating expenses and throughput shown in the
preceding table, was principally attributable to the inclusion in 1998 of the
operating results of (i) the interstate and intrastate pipeline operations of
assets acquired with MidCon (see Note 2 (D) to the accompanying consolidated
financial statements) and (ii) the Pony Express Pipeline, which began full
operation in the fourth quarter of 1997. There was no significant variance
attributable to the operating results of assets owned in both periods.
The Pony Express Pipeline accounted for the majority of the improvement in
Midstream operating income from 1996 to 1997. Additionally, 1997 operating
results were positively affected by increased gas supply requirements for the
Company's retail natural gas services and other wholesale customers. These gas
supply requirements increased in 1997 principally due to colder weather and
higher irrigation demand in the northern portions of the Company's operating
area. These positive impacts were partially offset by reduced 1997 wholesale
irrigation demand in the Texas intrastate market area and the transfer of the
Casper processing plant to the Upstream segment in August 1997.
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24
DOWNSTREAM RETAIL AND MARKETING 1998 1997 1996
- ------------------------------- -------- -------- --------
(Dollars In Millions)
Operating Revenues
Gas Sales $2,719.9 $1,552.4 $1,117.5
Transportation and Other 81.4 117.5 47.0
-------- -------- --------
2,801.3 1,669.9 1,164.5
-------- -------- --------
Operating Costs and Expenses
Gas Purchases and Other Costs of Sales 2,686.8 1,547.1 1,030.6
Operations and Maintenance 76.9 63.9 63.4
Depreciation and Amortization 14.6 11.5 11.8
Taxes, Other Than Income Taxes 6.3 5.6 5.6
-------- -------- --------
2,784.6 1,628.1 1,111.4
-------- -------- --------
Operating Income $ 16.7 $ 41.8 $ 53.1
======== ======== ========
Gas Sales (Trillion Btus) 1,253.5 564.1 439.2
======== ======== ========
Downstream operating income decreased from $41.8 million in 1997 to $16.7
million in 1998 primarily due to a decrease in earnings from commodity marketing
and other factors as described following. Operating income for 1998 included
$8.0 million of income from certain new assets and businesses not included in
1997, including K N Power, the Thermo Companies ("Thermo"), K N
Telecommunications and the Company's interest in the Hermosillo, Mexico, natural
gas distribution system. Additionally, 1998 results, as compared to 1997, were
positively affected by the fact that 1997 results included approximately $4.0
million of power marketing losses (the Company is not currently engaged in power
marketing). However, these favorable variances were more than offset by (i) a
$4.6 million decrease attributable to equity in losses of en*able and (ii) a
decrease of $26.8 million in operating income from commodity marketing, which
reflected (1) $6.4 million of adjustments to write down certain natural gas due
from third parties and in underground storage to their current market values,
(2) $3.7 million of increased provision for uncollectible accounts receivable,
(3) reduced 1998 sales of gas in storage and (4) depressed 1998 basis
differentials and milder weather which have a negative impact on certain sales
margins due to the costs associated with transportation commitments.
Downstream results were positively affected in 1997, relative to 1996, by
increased sales of gas in storage, sales of certain non-strategic gas supply and
increases in space-heating and irrigation loads in the northern portions of the
Company's operating area. These positive impacts were more than offset by (i)
$4.0 million of 1997 power marketing losses, (ii) reduced 1997 wholesale
irrigation demand in the Texas intrastate markets and (iii) expenses incurred
during 1997 to centralize the Company's marketing activities in Houston, Texas.
OTHER INCOME AND (DEDUCTIONS) 1998 1997 1996
- ----------------------------- ------- ------- -------
(In Millions)
Interest Expense, Net $(247.2) $ (43.5) $ (35.9)
Minority Interests (16.2) (8.7) (2.9)
Other, Net 17.1 19.2 3.7
------- ------- -------
$(246.3) $ (33.0) $ (35.1)
======= ======= =======
The increase of $203.7 million in "Interest Expense, Net" from 1997 to 1998 was
principally due to incremental debt associated with the MidCon acquisition and
construction costs associated with the Pony Express Pipeline. The increase in
net expense associated with "Minority Interests" in 1998, relative to 1997, was
principally due to the dividend requirements associated with the $175 million of
Capital Trust Securities issued in April 1998. The $2.1 million decrease in
"Other, Net" from 1997 to 1998 reflects the fact that 1998 included (i) a $10.9
million gain from the sale of certain microwave towers, (ii) an $8.5 million
gain from the sale of the Company's Kansas natural gas distribution properties,
(iii) the recognition of $7.2 million in costs related to the settlement of the
arbitration of certain environmental claims, as a result of which the Company
will have no future expense associated
24
25
with this matter, (iv) approximately $5.0 million of expense reflecting an
increased provision for regulatory refund obligations, (v) a loss of
approximately $3.1 million from the sale of certain natural gas processing
facilities and (vi) $13 million of other miscellaneous income items, while 1997
included approximately $7.0 million of income related to the sale of a 50
percent interest in en*able, $3.7 million of gains from the sale of
non-strategic gathering systems, $4.5 million of equity financing costs
associated with the Pony Express Pipeline and $4.0 million of other
miscellaneous income items.
The increase in "Interest Expense, Net" in 1997, relative to 1996, was the
result of additional long-term debt issued in 1997 and higher levels of
short-term debt, principally to fund capital expenditures. The increase in net
expenses associated with "Minority Interests" in 1997 was primarily due to the
dividend requirements associated with the $100 million of Capital Trust
Securities issued in April 1997. The change in "Other, Net" from 1996 to 1997
was principally due to the items recorded in 1997 as described preceding.
INCOME TAXES 1998 1997 1996
- ------------ ------- ------- -------
(Dollars In Millions)
Provision $ 38.3 $ 35.7 $ 35.9
======= ======= =======
Effective Tax Rate 38.9% 31.5% 36.0%
======= ======= =======
The $2.6 million net increase in income tax expense from 1997 to 1998 reflected
a decrease of approximately $4.7 million attributable to a decrease in 1998
pre-tax income and an increase of approximately $7.3 million attributable to an
increase in the 1998 effective tax rate. This increased 1998 effective tax rate
was principally due to (i) certain 1997 adjustments as described following and
(ii) an increase in the 1998 effective state tax rate attributable to the
addition of the results of operations of MidCon.
The $0.2 million net decrease in income tax expense from 1996 to 1997 reflected
an increase of approximately $4.8 million attributable to an increase in 1997
pre-tax income and a decrease of approximately $5.0 million attributable to a
decrease in the 1997 effective tax rate, principally due to the successful
resolution of certain issues from prior years' federal income tax filings.
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26
LIQUIDITY AND CAPITAL RESOURCES
The following table illustrates the sources of the Company's invested capital.
The balances at December 31, 1998, reflect the incremental capital associated
with the acquisition of MidCon, including the post-acquisition refinancings
completed in 1998 (see Notes 2 (D) and 7 to the accompanying consolidated
financial statements).
DECEMBER 31
1998 1997 1996
---------- ---------- ----------
(Dollars In Thousands)
Long-Term Debt $3,300,025 $ 553,816 $ 423,676
Common Equity 1,216,821 606,132 519,794
Preferred Stock 7,000 7,000 7,000
Capital Trust Securities 275,000 100,000 -
---------- ---------- ----------
Capitalization 4,798,846 1,266,948 950,470
Short-Term Debt 1,702,013(1) 359,951 156,271
---------- ---------- ----------
Invested Capital $6,500,859 $1,626,899 $1,106,741
========== ========== ==========
Capitalization:
Long-Term Debt 68.8% 43.7% 44.6%
Common Equity 25.4% 47.8% 54.7%
Preferred Stock 0.1% 0.6% 0.7%
Capital Trust Securities 5.7% 7.9% -
Invested Capital:
Total Debt(2) 76.9% 56.2% 52.4%
Equity, Including Capital
Trust Securities 23.1% 43.8% 47.6%
- --------------------------------------------------------------------------------
(1) Includes the $1,394,846 Substitute Note assumed in conjunction with the
acquisition of MidCon. This note was repaid on January 4, 1999.
(2) If the government securities held as collateral were offset against the
related debt, the ratio of total debt to invested capital at December 31,
1998, would be 72.3 percent.
The following discussion of cash flows should be read in conjunction with the
accompanying Consolidated Statements of Cash Flows and related supplemental
disclosures.
Net Cash Flows From Operating Activities
"Net Cash Flows From Operating Activities" decreased from $97.5 million in 1997
to $95.3 million in 1998, a decrease of $2.2 million or 2.3 percent. This
decrease was principally attributable to the net impact of (i) an increase of
approximately $65.5 million in cash used to increase net working capital in
1998, largely due to the net use of cash resulting from the changes in accounts
receivable and accounts payable, (ii) the increase in earnings before non-cash
charges and credits for 1998, (iii) increased 1998 cash used for gas in
underground storage and (iv) the 1998 receipt of $27.5 million in settlement of
a gas contract.
"Net Cash Flows From Operating Activities" increased from $75.6 million in 1996
to $97.5 million in 1997, an increase of $21.9 million. This increase was
principally attributable to the same factors resulting in the reported increase
in earnings between these years.
Net Cash Flows From Investing Activities
"Net Cash Flows Used in Investing Activities" increased from $496.6 million in
1997 to $3.5 billion in 1998, an increase of approximately $3.0 billion,
principally due to (i) the $2.2 billion of net cash paid in 1998 and (ii) the
net use of cash for the purchases of approximately $1.1 billion of U.S.
government securities as collateral for the Substitute Note, in each case in
conjunction with the acquisition of MidCon. In addition, cash outflows for
26
27
acquisitions other than MidCon were approximately $104.5 million less in 1998
than in 1997 and proceeds from sales of facilities increased by approximately
$55.2 million in 1998.
"Net Cash Flows Used in Investing Activities" increased from $257.3 million in
1996 to $496.6 million in 1997, an increase of $239.3 million principally due to
(i) the 1997 completion of the Pony Express Pipeline and construction of
transmission laterals into the Kansas City metropolitan area, (ii) the
acquisition of the Bushton facilities in April 1997 and (iii) the acquisition of
an interest in the Red Cedar Gathering Company, also in December 1997.
Net Cash Flows From Financing Activities
"Net Cash Flows From Financing Activities" increased from $411.2 million in 1997
to approximately $3.4 billion in 1998, an increase of approximately $3.0
billion. This increase reflected reduced 1998 cash from short-term borrowings
and the 1998 receipt of (i) $2.75 billion from the public sale of debt
securities, (ii) $650 million from the public sale of common stock and (iii)
$175 million from the public sale of Capital Trust Securities (in each case
representing the refinancing of acquisition debt associated with the purchase of
MidCon), net of associated issuance costs of approximately $78.2 million (see
Note 7 to the accompanying consolidated financial statements). In addition, 1998
cash used for dividends and long-term debt retirement increased by $17.3 million
and $8.0 million, respectively.
In March 1998, K N issued 12.5 million shares (18.75 million shares after
adjustment for the December 1998 three-for-two stock split) of common stock in
an underwritten public offering, receiving net proceeds of approximately $624.6
million. Also in March 1998, K N issued $2.35 billion principal amount of debt
securities of varying maturities and interest rates in an underwritten public
offering, receiving net proceeds of approximately $2.34 billion. The net
proceeds from these two offerings were used to refinance borrowings under the
MidCon acquisition financing arrangements and to purchase U.S. government
securities to collateralize a portion of the Substitute Note. In April 1998, K N
sold $175 million of 7.63% Capital Securities due April 15, 2028, in an
underwritten offering, with the net proceeds of $173.1 million used to purchase
U.S. government securities to further collateralize the Substitute Note. In
November 1998, K N completed the concurrent underwritten public offerings of
$400 million of 3-year senior notes and $460 million principal amount of premium
equity participating security units ("PEPS"). The $397.4 million of net proceeds
from the senior notes offering were used to retire a portion of K N's
then-outstanding short-term borrowings. The proceeds from the PEPS offering was
used to purchase U.S. treasury securities on behalf of the PEPS owners, which
securities are the property of the PEPS owners and will be held as collateral to
fund the obligation of the PEPS holders to purchase K N common stock at the end
of a three-year period. For additional information on each of these financings,
including terms of the specific securities and the associated accounting
treatment, see Note 7 to the accompanying consolidated financial statements.
"Net Cash Flows From Financing Activities" increased from $177.8 million in 1996
to $411.2 million in 1997, an increase of approximately $233.4 million. This
increase was principally attributable to (i) additional long-term debt issued in
1997, (ii) the issuance of $100 million of Capital Trust Securities in April
1997 and (iii) net increases in short-term borrowing in 1997. These increases
were partially offset by decreased 1997 cash from the issuance of common stock.
On January 4, 1999, K N repaid the $1.4 billion Substitute Note payable to
Occidental Petroleum as part of the MidCon acquisition. The note was repaid
using the proceeds of approximately $1.1 billion from the sale of U.S.
government securities which had been held as collateral, with the balance of the
funds provided by an increase in short-term borrowings.
27
28
The Company's principal sources of short-term liquidity are its $1 billion
revolving bank facilities (see Note 7 to the accompanying consolidated financial
statements). At December 31, 1998, the Company had $297.0 million of commercial
paper issued and outstanding (which is backed by the bank facilities). At
February 17, 1999, short-term borrowings had increased to approximately $593
million, principally due to funds borrowed in conjunction with repayment of the
Substitute Note as described preceding. The bank facilities include covenants
which are common in such arrangements, including requirements that (i) the ratio
of the Company's total debt to total capitalization not exceed 74 percent
initially (upon issuance of common stock to the holders of the PEPS at the
maturity thereof, the ratio will be reduced to 67 percent) and (ii) the
Company's consolidated net worth (inclusive of trust preferred securities) be at
least equal to the sum of $1.236 billion plus 50 percent of consolidated net
income earned for each fiscal quarter ending after December 30, 1998.
Certain of the Company's operating lease arrangements provide that, in the event
that the rating of K N's senior debt is lowered below investment grade by both
of the two major rating agencies, the Company would be required to post letters
of credit in support of its remaining lease payments. Although the Company
currently has no information to indicate that such downgrades will occur, given
the Company's current level of borrowing and utilization of its letter of credit
facility, the posting of these additional letters of credit in support of lease
obligations would place the Company in default under the terms of its revolving
credit facility. The Company currently believes that, should such a default
occur, it could obtain a waiver of the applicable default provisions or
modification of such provisions to allow the facility to remain in place,
although the pricing would likely increase.
Capital Expenditures and Commitments
Capital expenditures decreased from $311.1 million in 1997 to $256.5 million in
1998. This decrease was due principally to the fact that 1997 capital
expenditures included the costs for completion of the Pony Express Pipeline and
associated transmission laterals. The 1999 capital expenditure budget totals
approximately $160 million. Approximately $44.3 million of this amount had been
committed for the purchase of plant and equipment at December 31, 1998.
Principal acquisitions or investments made during 1998 included the MidCon and
Thermo acquisitions and the pressure reduction program in the Hugoton basin.
Major asset sales during 1998 included the sale of the Company's Kansas natural
gas distribution properties, certain microwave towers and certain
under-performing natural gas gathering and processing facilities. See Note 2 to
the accompanying consolidated financial statements for more information on these
acquisitions, investments and sales.
COMMON STOCK SPLIT AND DIVIDEND ACTION
On November 9, 1998, the Board of Directors of K N Energy, Inc. approved a 7.1
percent increase in the quarterly dividend and a three-for-two split of the
Company's common stock. The regular quarterly dividend was declared at $0.30 per
common share, an increase from $0.28 per common share. Giving effect to the
stock split, the quarterly dividend is $0.20 per common share. The stock split
was distributed and the increase in dividend was paid concurrently on December
31, 1998, to shareholders of record at the close of business on December 15,
1998.
REGULATION
On January 23, 1998, K N Interstate Gas Transmission Co. ("KNI") filed a general
rate case with the Federal Energy Regulatory Commission ("FERC") requesting a
$30.2 million increase in annual revenues. As a result of FERC action, KNI was
allowed to place its rates into effect on August 1, 1998, subject to refund, and
KNI has recorded provisions
28
29
for refund based on its expectation of ultimate resolution. KNI is currently
following the procedural schedule established for the rate case and a hearing on
its proposed rates is currently scheduled to commence on July 20, 1999.
On December 29, 1998, Rocky Mountain Natural Gas Company ("RMNG"), a wholly
owned subsidiary of K N Energy, Inc., received a "show cause" order from the
Colorado Public Utilities Commission (the "Commission"). The Commission has
concluded that there is reason to believe that RMNG's rates may be excessive and
has ordered further investigation. A procedural schedule has been established
and a hearing is scheduled to commence on June 1, 1999.
RISK MANAGEMENT
To minimize the risk of price changes in the natural gas and NGLs markets, the
Company uses certain financial instruments for hedging purposes. These
instruments include energy products traded on the New York Mercantile Exchange,
the Kansas City Board of Trade and over-the-counter markets including, but not
limited to, futures and options contracts and fixed-price swaps. The Company is
exposed to credit-related losses in the event of nonperformance by
counterparties to these financial instruments, but does not expect any
counterparties to fail to meet their obligations given their existing credit
ratings.
Pursuant to a policy approved by its Board of Directors, the Company is to
engage in these activities only as a hedging mechanism against price volatility
associated with pre-existing or anticipated physical gas and condensate sales,
gas purchases, system use and storage in order to protect profit margins, and is
not to engage in speculative trading. Commodity-related activities of the risk
management group are monitored by the Company's Risk Management Committee, which
is charged with the review and enforcement of the Board of Directors' risk
management policy. The Risk Management Committee reviews the types of hedging
instruments used, contract limits and approval levels and may review the pricing
and hedging of any or all commodity transactions. All energy futures, swaps and
options are recorded at fair value. The fair value of these risk management
instruments reflects the estimated amounts that the Company 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 financial instruments used by the Company. Gains
and losses on hedging positions are deferred and recognized as gas purchases
expense in the periods in which the underlying physical transactions occur.
The Company measures the risk of price changes in the natural gas and NGLs
markets utilizing a Value-at-Risk ("VAR") model. VAR 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. The Company utilizes
a closed form model to evaluate risk on a daily basis. The VAR computations
utilize 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 mark-to-market
losses for a single day will not exceed the VAR number 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. VAR at
December 31, 1998, was $5.8 million and averaged $4.6 million for 1998.
The Company's calculated VAR exposure represents an estimate of the reasonably
possible net losses that would be recognized on the Company's 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 the Company's
portfolio of derivatives during the year.
29
30
The Company's Treasury Department manages the Company's interest rate exposure,
utilizing interest rate swaps, caps or similar derivatives within
Board-established policy. None of these interest rate derivatives is leveraged.
The Company currently is not hedging its interest rate exposure resulting from
its short-term borrowings. The market risk related to short-term borrowings from
a one percent change in interest rates would result in an approximate $5.9
million impact on pre-tax income, based on current short-term borrowing levels.
There are recently issued accounting pronouncements that change the accounting
and reporting requirements for certain risk management activities (see Note 9 to
the accompanying consolidated financial statements).
OUTLOOK/FORWARD-LOOKING INFORMATION
General
Certain information contained herein may include 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. Although the Company believes that these
statements are based upon reasonable assumptions, it can give no assurance that
its goals will be achieved. Important factors that could cause actual results to
differ materially from those in the forward-looking statements contained herein
include, among other factors, the pace of deregulation of retail natural gas and
electricity markets in the United States, federal, state and international
regulatory developments, the timing and extent of changes in commodity prices
for oil, natural gas, NGLs, electricity, certain agricultural products and
interest rates, the extent of success in acquiring natural gas facilities, the
timing and success of efforts to develop power, pipeline and other projects,
political developments in foreign countries, weather-related factors and
conditions of capital markets and equity markets during the periods covered by
the forward-looking statements. All of these factors are difficult to predict
and many are beyond the Company's control.
Readiness for Year 2000
The following is a discussion of the Year 2000 problem and its potential impact
on the Company. The Securities and Exchange Commission ("SEC") has issued
specific guidelines for public companies regarding their disclosure of the Year
2000 problem. The guidelines require more detailed disclosure of each company's
analysis of and approach to the Year 2000 problem. As a result, the Company is
providing the following disclosure; however, the length and detail contained in
this disclosure, relative to the other disclosures contained herein, is not an
indication of the Company's view of the relative risk of the Year 2000 problem
to the Company.
Some computers and programs, and some devices containing computer chips
("embedded chips") store or process dates containing the Year 2000 as "00." This
can result in inaccurate date-related calculations. It is expected that once the
Year 2000 arrives, computers, computer programs and devices with embedded chips
that have not been modified to correct this problem will not function normally.
The Company relies on a number of automated systems to conduct its operations
and to transact its business, as is common among large diversified energy
companies. In addition, certain of the Company's pipelines and processing
equipment and related systems contain electric controls or other devices
containing embedded chips. These controls may also be adversely affected by this
problem.
In 1997, the Audit Committee of the Company's Board of Directors (the "Audit
Committee") established a Year 2000 project to address the Year 2000 problem. In
that year, the Company established a Year 2000 Executive Steering Committee (the
"Year 2000 Committee") and a Year 2000 Project Management Office (the "Year 2000
Project Management Office"). The Year 2000 project is an ongoing effort
monitored by the Audit Committee.
30
31
The Audit Committee has adopted a Year 2000 Plan (the "Plan") and will oversee
its implementation by receiving periodic reports from the Year 2000 Committee
and directly from management. The Audit Committee is prepared to require
management to make additional efforts, including amending the Plan as necessary,
to fulfill the Audit Committee's goal of taking reasonable steps to minimize
injury to people, damage to property, disruption to the Company's delivery of
products and services, supporting systems and business operations, and other
risks associated with the Year 2000 problem.
The Year 2000 Committee is charged with directing the implementation of the Plan
in accordance with resolutions of the Audit Committee and under the direction of
the Company's designated senior executives. The Year 2000 Committee oversees the
Year 2000 Project Management Office, headed by the Year 2000 Project
Coordinator. The Year 2000 Committee keeps the Audit Committee informed of the
Company's progress in implementing the Plan and of significant updates that are
made to the Plan. The Year 2000 Committee communicates the Audit Committee's
directives concerning the Plan to management and executives, and oversees the
implementation of those directives.
The Year 2000 Project Management Office works closely with the Company's
Readiness Teams comprised of members of the Company's operating units. The teams
have been organized to further implement the Plan throughout the Company. The
Project Management Office, among other things, promotes exchange of information
about Year 2000 problems and solutions, assists in disseminating information
about the Company's policies governing communications concerning Year 2000
issues and serves as a conduit between the various Readiness Teams and the Year
2000 Committee.
The aim of the Plan is to take reasonable steps to prevent the Company's mission
critical functions from being impaired due to the Year 2000 problem. "Mission
critical" describes those systems, devices, functions and external entities that
are of material importance to maintaining the Company's capacity to deliver and
account for products and services without interruption, and to maintain the
Company's supporting business operations with no material disruption or
diminution in quality.
Each of the Company's operating units is in various stages of implementing the
Plan to address the Year 2000 problem. These efforts include:
o an assessment of potential problems;
o an inventory of systems and areas which may need to be corrected;
o remediation and implementation, with priority given to mission
critical items;
o the testing of such systems and devices; and
o developing contingency plans in case the Company cannot correct the
problem in time, or in the event certain facets of the Year 2000
problem go undetected or do not manifest themselves until after
January 1, 2000.
Specifically, the Company is in the process of correcting programmable code,
replacing non-Year 2000-ready embedded chips, installing Year 2000-ready
releases of certain vendor-supplied computer systems and, in some cases,
replacing existing systems with new internally or externally developed software
in advance of December 31, 1999.
The Company has completed an inventory of affected items in the non-information
technology area and is assessing the results. The Company has begun testing and
currently has found very few items that are likely to suffer adverse effects
from the Year 2000 problem. The Company expects testing and remediation of
mission critical items to be substantially completed by mid-1999.
31
32
For the Company's Plan to be successful, the Company must rely for some purposes
on outside contractors. There is a risk that those contractors will not complete
their work prior to the Year 2000. The Company is developing alternative ways to
conduct its business if such deadlines are not met. However, any alternative may
involve additional expense and may not be implemented in time to avoid the Year
2000 problem. Ultimately, these alternatives may not be successful.
The Company also relies on suppliers, business partners and other external
entities which may or may not be addressing their own problems associated with
the Year 2000 problem. The Company has sent out questionnaires to external
entities to determine what steps they have taken to correct any Year 2000
problems they may have. The Company has no control over such external entities'
efforts, so the Company has developed contingency plans in case such external
entities do not complete their efforts before the Year 2000.
The Company estimates that the direct costs the Company has incurred or will
incur in 1998, 1999 and 2000 associated with assessing, inventorying,
remediating and testing internally developed computer applications, hardware and
equipment, including embedded chip systems and third-party developed software,
to be between $5 million and $7 million. In addition, as part of the integration
of the Company's systems with the systems of MidCon, the Company has begun
modifying certain of its computer systems for the combined company or purchasing
computer systems from third parties. These computer systems will address the
Year 2000 problem and are expected to be operational prior to December 31, 1999.
The costs for these computer systems are expected to be between $23 million and
$25 million, the majority of which will be capitalized.
The SEC's guidelines also require the Company to address the most reasonably
likely worst case scenarios resulting from the Year 2000 problem. As a result of
the Year 2000 problem, the Company may be faced with: failure of electrical, gas
and similar services and supplies from utilities, disruption of
telecommunications facilities, interruptions in the nation's transportation
systems and failure of a substantial number of the Company's mission critical
hardware and software systems. In addition, the Company's key suppliers or
customers may experience their own Year 2000 problems in a way that materially
adversely affects the Company's ability to do business without interruption or
disruption. As a result of the cumulative impact of these events, the Company's
business may be materially adversely affected. The adverse impact of these
events occurring can not be quantified at this time.
The Company is in the process of developing contingency plans to address issues
associated with the reasonably likely worst case scenarios. The Company expects
to have such contingency plans substantially completed by the end of June 1999.
The Company will then refine and update its contingency plans for the remainder
of 1999.
The Company does not believe that the direct costs associated with the Year 2000
problem will be material to its business, financial position or results of
operations.
Litigation and Environmental
The Company's anticipated environmental capital costs and expenses for 1999,
including expected costs for voluntary remediation efforts, are approximately
$8.4 million. A substantial portion of the Company's environmental costs are
either recoverable through insurance and indemnification provisions or have
previously recorded liabilities associated with them.
Refer to Notes 4(A) and 4(B) to the accompanying consolidated financial
statements for additional information on the Company's pending litigation and
environmental matters. The Company believes it has established adequate reserves
such that the resolution of pending litigation and environmental matters will
not have a material adverse impact on the Company's business, financial position
or results of operations.
32
33
New Business Venture
With its 1998 Thermo acquisition (see Note 2 (B) to the accompanying
consolidated financial statements), the Company obtained its first electric
generation assets. In addition, the Company has announced plans to participate
in the investment of $2.5 billion over the next three to five years to build
gas-fired electric generation plants. The Company plans to obtain a significant
amount of non-recourse financing and partner with electricity companies to build
plants totaling 5,000 megawatts of electric generation capacity along its
current natural gas pipeline systems.
Significant Operating Variables
The Company's principal exposure to price variability is with NGLs processing
margins. The Company attempts to mitigate this exposure by an appropriate mix of
"percent of proceeds," "keep whole" and "fee based" processing agreements and by
the use of financial hedging instruments (see "Risk Management," elsewhere
herein). Under current agreements with producers, a one cent change in average
processing margins affects pre-tax operating income by approximately $5.5
million.
The Company also has exposure to variation in natural gas prices and basis
differentials, which can affect gross margins in its Midstream sales,
transportation and storage and Downstream retail and marketing businesses. 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 December 1998, the Northern Border
Pipeline began operations on its 700 million cubic feet per day ("cfd")
expansion project from Canadian supply areas into the Chicago market area, which
is the terminus of NGPL's main pipeline system. In addition, the Alliance
Pipeline, a joint venture of several energy companies, is currently planning a
1.3 billion cfd pipeline to transport natural gas from Canada into the Chicago
market area. The in-service date for the Alliance pipeline is uncertain but may
be between late 2000 and 2002. In addition, various pipelines have proposed
projects to take gas out of the Chicago area to market areas in the Northeast
United States. It is currently unknown what impact, if any, this additional
pipeline capacity will have on gas prices and basis differentials for delivery
points in the upper Midwest.
33
34
ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To K N Energy, Inc.:
We have audited the accompanying consolidated balance sheets of K N Energy, Inc.
(a Kansas corporation) and subsidiaries as of December 31, 1998 and 1997, and
the related consolidated statements of income, comprehensive income, common
stockholders' equity and cash flows for each of the three years in the period
ended December 31, 1998. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of K N Energy, Inc. and
subsidiaries as of December 31, 1998 and 1997, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1998, in conformity with generally accepted accounting principles.
Our audit was made for the purpose of forming an opinion on the basic financial
statements taken as a whole. The schedule listed in the index of financial
statements is presented for purposes of complying with the Securities and
Exchange Commission's rules and is not part of the basic financial statements.
This schedule has been subjected to the auditing procedures applied in the audit
of the basic financial statements and, in our opinion, fairly states in all
material respects the financial data required to be set forth therein in
relation to the basic financial statements taken as a whole.
/s/ Arthur Andersen LLP
Denver, Colorado
February 2, 1999
34
35
CONSOLIDATED STATEMENTS OF INCOME
K N ENERGY, INC. AND SUBSIDIARIES
YEARS ENDED DECEMBER 31
---------------------------------------------
1998 1997 1996
----------- ----------- -----------
(In Thousands Except Per Share Amounts)
OPERATING REVENUES:
Upstream Gathering and Processing $ 604,830 $ 553,932 $ 357,533
Midstream Sales, Transportation and Storage 1,504,644 231,108 266,737
Downstream Retail and Marketing 2,801,335 1,669,945 1,164,512
Intersegment Eliminations (522,966) (306,004) (348,300)
----------- ----------- -----------
Total Operating Revenues 4,387,843 2,148,981 1,440,482
----------- ----------- -----------
OPERATING COSTS AND EXPENSES:
Gas Purchases and Other Costs of Sales 3,400,044 1,727,902 1,061,748
Operations and Maintenance 390,883 195,043 173,400
Depreciation and Amortization 195,916 55,994 51,212
Taxes, Other Than Income Taxes 50,686 23,930 19,321
Merger-related Costs 5,763 -- --
----------- ----------- -----------
Total Operating Costs and Expenses 4,043,292 2,002,869 1,305,681
----------- ----------- -----------
OPERATING INCOME 344,551 146,112 134,801
----------- ----------- -----------
OTHER INCOME AND (DEDUCTIONS):
Interest Expense, Net (247,180) (43,495) (35,933)
Minority Interests (16,167) (8,706) (2,946)
Other, Net 17,057 19,247 3,794
----------- ----------- -----------
Total Other Income and (Deductions) (246,290) (32,954) (35,085)
----------- ----------- -----------
INCOME BEFORE INCOME TAXES 98,261 113,158 99,716
Income Taxes 38,272 35,661 35,897
----------- ----------- -----------
NET INCOME 59,989 77,497 63,819
Less - Preferred Stock Dividends 350 350 398
----------- ----------- -----------
EARNINGS AVAILABLE FOR COMMON STOCK $ 59,639 $ 77,147 $ 63,421
=========== =========== ===========
BASIC EARNINGS PER COMMON SHARE $ 0.93 $ 1.66 $ 1.45
=========== =========== ===========
DILUTED EARNINGS PER COMMON SHARE $ 0.92 $ 1.63 $ 1.43
=========== =========== ===========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
YEARS ENDED DECEMBER 31
--------------------------------------------------------------
1998 1997 1996
---------- ---------- ----------
(In Thousands)
NET INCOME $ 59,989 $ 77,497 $ 63,819
Unrealized (Loss) Gain on Equity Securities, Net of Tax (6,697) (1,492) 5,735
---------- ---------- ----------
COMPREHENSIVE INCOME $ 53,292 $ 76,005 $ 69,554
========== ========== ==========
The accompanying notes are an integral part of these statements.
35
36
CONSOLIDATED BALANCE SHEETS
K N ENERGY, INC. AND SUBSIDIARIES
DECEMBER 31
------------------------------------
1998 1997
---------- ----------
(Dollars In Thousands)
ASSETS
CURRENT ASSETS:
Cash and Cash Equivalents $ 21,955 $ 22,471
Restricted Deposits 9,096 11,339
U.S. Government Securities 1,092,415 -
Accounts Receivable 693,044 409,937
Inventories 144,831 47,034
Gas Imbalances 85,349 16,687
Other 46,812 69,062
---------- ----------
2,093,502 576,530
---------- ----------
INVESTMENTS 252,543 149,869
---------- ----------
PROPERTY, PLANT AND EQUIPMENT, NET 7,023,176 1,420,975
---------- ----------
DEFERRED CHARGES AND OTHER ASSETS 242,991 158,431
---------- ----------
TOTAL ASSETS $9,612,212 $2,305,805
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Current Maturities of Long-Term Debt $ 10,167 $ 30,751
Notes Payable 297,000 329,200
Substitute Note 1,394,846 -
Accounts Payable 489,414 334,418
Accrued Taxes 18,914 7,445
Gas Imbalances 74,857 57,733
Payable for Purchase of Thermo Companies 86,799 -
Other 247,465 37,264
---------- ----------
2,619,462 796,811
---------- ----------
OTHER LIABILITIES AND DEFERRED CREDITS:
Deferred Income Taxes 1,699,072 168,583
Other 431,565 26,160
---------- ----------
2,130,637 194,743
---------- ----------
LONG-TERM DEBT 3,300,025 553,816
---------- ----------
K N-OBLIGATED MANDATORILY REDEEMABLE PREFERRED CAPITAL TRUST SECURITIES OF
SUBSIDIARY TRUST HOLDING SOLELY DEBENTURES OF K N 275,000 100,000
---------- ----------
MINORITY INTERESTS IN EQUITY OF SUBSIDIARIES 63,267 47,303
---------- ----------
COMMITMENTS AND CONTINGENT LIABILITIES (NOTES 2, 4 AND 12)
STOCKHOLDERS' EQUITY:
Preferred Stock 7,000 7,000
---------- ----------
Common Stock-
Authorized - 150,000,000 Shares, Par Value $5 Per Share
Outstanding - 68,597,308 and 31,996,075 Shares,
After Deducting 48,598 and 28,482 Shares Held in Treasury 343,230 160,123
Additional Paid-in Capital 694,223 266,435
Retained Earnings 193,925 185,658
Other (14,557) (6,084)
---------- ----------
Total Common Stockholders' Equity 1,216,821 606,132
---------- ----------
Total Stockholders' Equity 1,223,821 613,132
---------- ----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $9,612,212 $2,305,805
========== ==========
The accompanying notes are an integral part of these statements.
36
37
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
K N ENERGY, INC. AND SUBSIDIARIES
YEARS ENDED DECEMBER 31
---------------------------------------------------------------------------------------
1998 1997 1996
---- ---- ----
SHARES AMOUNT SHARES AMOUNT SHARES AMOUNT
------ ------ ------ ------ ------ ------
(Dollars In Thousands)
COMMON STOCK:
Beginning Balance 32,024,557 $ 160,123 30,295,792 $ 151,479 28,097,749 $ 140,489
Sales of Common Stock 12,500,000 62,500 - - 1,715,000 8,575
Exercise of Common Stock Warrants - - 642,232 3,211 - -
Acquisition of Businesses 689,810 3,449 544,604 2,723 - -
Employee and Executive Benefit Plans 549,570 2,758 541,929 2,710 483,043 2,415
Common Stock Split 22,881,969 114,400 - - - -
----------- ----------- ----------- ----------- ----------- -----------
Ending Balance 68,645,906 343,230 32,024,557 160,123 30,295,792 151,479
----------- ----------- ----------- ----------- ----------- -----------
ADDITIONAL PAID-IN CAPITAL:
Beginning Balance 266,435 223,167 176,910
Sale of Common Stock, Net 558,053 - 44,591
Costs Related to PEPS Offering (62,150) - -
Exercise of Common Stock Warrants - 8,060 -
Redemption and Cancellation of Common
Stock Warrants - - (7,420)
Acquisition of Businesses 30,985 21,411 1,648
Employee and Executive Benefit Plans 15,371 13,797 7,438
Common Stock Split (114,471) - -
----------- ----------- -----------
Ending Balance 694,223 266,435 223,167
----------- ----------- -----------
RETAINED EARNINGS:
Beginning Balance 185,658 142,578 109,895
Net Income 59,989 77,497 63,819
Cash Dividends:
Common (51,372) (34,067) (30,738)
Preferred (350) (350) (398)
----------- ----------- -----------
Ending Balance 193,925 185,658 142,578
----------- ----------- -----------
OTHER:
DEFERRED COMPENSATION:
Beginning Balance (9,203) (2,908) (222)
Executive Benefit Plans (1,483) (6,295) (2,686)
----------- ----------- -----------
Ending Balance (10,686) (9,203) (2,908)
----------- ----------- -----------
TREASURY STOCK:
Beginning Balance (28,482) (1,124) (7,216) (257) (10,739) (312)
Treasury Stock Acquired (60,994) (2,834) (53,190) (2,096) (220,178) (7,069)
Acquisition of Businesses 39,970 1,801 - - 34,282 1,183
Dividend Reinvestment Plan 17,135 740 31,924 1,229 189,419 5,941
Common Stock Split (16,227) - - - - -
----------- ----------- ----------- ----------- ----------- -----------
Ending Balance (48,598) (1,417) (28,482) (1,124) (7,216) (257)
----------- ----------- ----------- ----------- ----------- -----------
ACCUMULATED OTHER COMPREHENSIVE
INCOME (NET OF TAX):
Beginning Balance 4,243 5,735 -
Unrealized (Loss) Gain on
Equity Securities (6,697) (1,492) 5,735
----------- ----------- -----------
Ending Balance (2,454) 4,243 5,735
----------- ----------- -----------
TOTAL OTHER (48,598) (14,557) (28,482) (6,084) (7,216) 2,570
----------- ----------- ----------- ----------- ----------- -----------
TOTAL COMMON STOCKHOLDERS'
EQUITY 68,597,308 $ 1,216,821 31,996,075 $ 606,132 30,288,576 $ 519,794
=========== =========== =========== =========== =========== ===========
The accompanying notes are an integral part of these statements.
37
38
CONSOLIDATED STATEMENTS OF CASH FLOWS
K N ENERGY, INC. AND SUBSIDIARIES
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
YEARS ENDED DECEMBER 31
-------------------------------------------------------
1998 1997 1996
----------- ----------- -----------
(In Thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income $ 59,989 $ 77,497 $ 63,819
Adjustments to Reconcile Net Income to
Net Cash Flows From Operating Activities:
Depreciation and Amortization, Excluding Amortization
of Gas Plant Acquisition Adjustment 97,999 55,994 51,212
Deferred Income Taxes 21,255 17,155 16,443
Deferred Purchased Gas Costs 468 (17,146) (8,109)
(Gain) Loss on Sale of Facilities (17,667) (4,860) 491
Proceeds from Buyout of Contractual Gas Obligations 27,500 - -
Changes in Gas in Underground Storage (56,126) (3,167) (22,056)
Changes in Other Working Capital Items (81,400) (15,902) (2,496)
Changes in Deferred Revenues 36,026 (5,736) (13,883)
Other, Net 7,225 (6,332) (9,811)
----------- ----------- -----------
NET CASH FLOWS FROM OPERATING ACTIVITIES 95,269 97,503 75,610
----------- ----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital Expenditures (256,514) (311,093) (119,987)
Cash Paid for Acquisition of MidCon, Net of Cash Acquired (2,198,263) - -
Other Acquisitions (14,047) (118,590) (147,137)
Investments (9,755) (89,307) (2,136)
Sale of U.S. Government Securities 1,062,453 - -
Purchase of U.S. Government Securities (2,154,868) - -
Proceeds from Sales of Assets 77,584 22,433 11,922
----------- ----------- -----------
NET CASH FLOWS USED IN INVESTING ACTIVITIES (3,493,410) (496,557) (257,338)
----------- ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-Term Debt, Net (32,687) 199,900 41,300
Long-Term Debt, Issued 2,750,000 150,000 125,000
Long-Term Debt, Retired (35,787) (27,832) (18,170)
Common Stock Issued in Public Offering 650,000 - 55,309
Mandatorily Redeemable Trust Securities Issued 175,000 100,000 -
Preferred Stock Redemption - - (572)
Other Common Stock Issued 13,437 19,091 6,359
Redemption and Cancellation of Common Stock Warrants - - (7,420)
Treasury Stock, Issued 740 1,229 5,941
Treasury Stock, Acquired (2,834) (2,096) (7,069)
Cash Dividends, Common (51,372) (34,067) (30,738)
Cash Dividends, Preferred (350) (350) (398)
Minority Interests, Contributions 10,872 7,823 13,586
Minority Interests, Distributions (1,175) (212) (2,182)
Securities Issuance Costs (78,219) (2,300) (3,133)
----------- ----------- -----------
NET CASH FLOWS FROM FINANCING ACTIVITIES 3,397,625 411,186 177,813
----------- ----------- -----------
Net Increase (Decrease) in Cash and Cash Equivalents (516) 12,132 (3,915)
Cash and Cash Equivalents at Beginning of Year 22,471 10,339 14,254
----------- ----------- -----------
Cash and Cash Equivalents at End of Year $ 21,955 $ 22,471 $ 10,339
=========== =========== ===========
The accompanying notes are an integral part of these statements.
38
39
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Event Subsequent to Date of Auditors' Report (Unaudited)
On February 22, 1999, Sempra Energy ("Sempra") and the Company announced that
their respective boards of directors had unanimously approved a definitive
agreement (the "Agreement") under which Sempra and the Company would combine in
a stock-and-cash transaction valued in the aggregate at $6.0 billion. Sempra is
an energy services holding company based in San Diego, California, serving 21
million customers through natural gas and electric distribution, as well as a
broad range of energy-related products and services throughout the United
States, Canada, Mexico and other countries in Latin America. Under the terms of
the Agreement, Sempra will acquire all of the Company's outstanding common
shares (the "K N Shares") for a combination of shares of Sempra common stock
(the "Sempra Shares") and cash as described following. The Company's
shareholders will have the option to elect to receive for each of their K N
Shares either (i) .7805 Sempra Shares plus $7.50, (ii) 1.115 Sempra Shares or
(iii) $25.00, subject to pro-ration, such that 70 percent of the K N Shares will
be converted into Sempra Shares and 30 percent of the K N Shares will be
converted into cash. This merger is conditioned, among other things, upon the
approvals of shareholders of both companies, the Federal Energy Regulatory
Commission and the state commissions of Colorado and Wyoming and clearance under
the Hart-Scott-Rodino Antitrust Improvements Act of 1976. Closing is currently
expected in six to eight months.
(A) Nature of Operations
K N Energy, Inc., referred to herein together with its consolidated subsidiaries
as "K N" or the "Company," is an energy services provider and has operations in
16 states in the Rocky Mountain and Mid-Continent regions, with principal
operations in Arkansas, Colorado, Illinois, Iowa, Kansas, Nebraska, Oklahoma,
Texas and Wyoming. The Company also owns a natural gas distribution system in
the Mexican state of Sonora. During 1998, the Company made significant
acquisitions (see Note 2). Energy services include: gathering, processing,
storing, transporting and marketing natural gas, providing retail natural gas
distribution services, providing field services to natural gas producers,
marketing natural gas liquids ("NGLs"), and generating and selling electricity.
The Company has both regulated and nonregulated operations.
(B) Basis of Presentation
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions.
These estimates and assumptions affect the reported amounts of assets and
liabilities, the disclosure of contingent assets and liabilities, and the
reported amounts of revenues and expenses. Actual results could differ from
these estimates.
The consolidated financial statements include the accounts of K N Energy, Inc.
and its majority-owned subsidiaries. Investments in jointly owned operations in
which the Company has 20 to 50 percent ownership are accounted for under the
equity method. All material intercompany transactions and balances have been
eliminated. Certain prior year amounts have been reclassified to conform to the
current presentation.
(C) Accounting for Regulatory Activities
The Company's regulated public 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
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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
to the Company associated with certain charges and credits which will be
recovered from or refunded to customers through the ratemaking process. The
following regulatory assets and liabilities are reflected in the accompanying
Consolidated Balance Sheets:
DECEMBER 31
---------------------------------
1998 1997
------- -------
(In Thousands)
REGULATORY ASSETS:
Employee Benefit Costs $ 2,956 $ 1,348
Debt Refinancing Costs 2,337 2,682
Deferred Income Taxes 19,176 754
Purchased Gas Costs 30,021 53,790
Pony Express Electrical Costs 3,820 -
Plant Acquisition Adjustments 454 454
Rate Regulation and Application Costs 3,554 601
------- -------
Total Regulatory Assets 62,318 59,629
------- -------
REGULATORY LIABILITIES:
Employee Benefit Costs 2,958 -
Deferred Income Taxes 33,983 3,718
Purchased Gas Costs 23,110 5,195
------- -------
Total Regulatory Liabilities 60,051 8,913
------- -------
NET REGULATORY ASSETS $ 2,267 $50,716
======= =======
As of December 31, 1998, $48.6 million of the Company's regulatory assets and
$56.1 million of the Company's regulatory liabilities were being recovered from
or refunded to customers through rates over periods ranging from 1 to 15 years.
Approximately $7.4 million of the regulatory assets at December 31, 1998, have
been included in rates subject to refund, pending the outcome of a current rate
case. Approximately $3.0 million of the Company's regulatory assets at December
31, 1998, are included in rate base and are earning a return on investment.
(D) Revenue Recognition Policies
In general, the Company recognizes revenues as services are rendered or goods
are delivered. The Company's 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 for gas delivered but unbilled at the
end of each accounting period.
(E) Earnings Per Share
Basic earnings per share is computed based on the monthly weighted-average
number of common shares outstanding during each period. The weighted-average
number of common shares used in computing basic earnings per share was
64,021,000 for 1998, 46,588,500 for 1997 and 43,653,000 for 1996. Diluted
earnings per share is computed based on the monthly weighted-average number of
common shares outstanding during the periods and the assumed exercise or
conversion of securities convertible into common stock for which the effect of
conversion or exercise would be dilutive (stock options and warrants) using the
treasury stock method. Dilutive securities assumed to have been converted or
exercised totaled 614,500 for 1998, 718,500 for 1997 and 783,000 for 1996.
Weighted-average shares outstanding and all per share amounts in the
accompanying consolidated financial statements and these notes have been
restated to reflect a three-for-two split of the Company's common stock (see
Note 7 (D)).
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(F) Restricted Deposits
The Company uses energy financial instruments to reduce its exposure to price
risk related to natural gas and NGLs. Restricted Deposits consist of monies on
deposit with brokers that are restricted to meet exchange trading requirements
(see Note 9).
(G) Inventories
DECEMBER 31
------------------------------------
1998 1997
--------- ---------
(In Thousands)
Gas in Underground Storage (Current) $ 106,971 $ 33,558
Natural Gas Liquids 11,226 900
Materials and Supplies 26,634 12,576
--------- ---------
$ 144,831 $ 47,034
========= =========
Inventories are accounted for using the following methods, with the percent of
the total dollars at December 31, 1998, shown in parentheses: average cost
(91.1%), last-in, first-out (8.3%) and first-in, first-out (0.6%). All
non-utility inventories held for resale are valued at the lower of cost or
market.
The Company also maintains gas in its underground storage facilities on behalf
of certain third parties. The Company receives a fee for its storage services
but does not reflect the value of gas stored for third parties in the
accompanying consolidated financial statements.
(H) Investments
Investments consist primarily of equity method investments in unconsolidated
subsidiaries and joint ventures, and include ownership interests in net profits
and net cash flows. In addition, the Company has an investment in Tom Brown,
Inc. ("TBI") common and convertible preferred stock. Equity in earnings of
investments accounted for under the equity method totaling $21.7 million and
$3.9 million for 1998 and 1997, respectively, are included in operating revenues
(within the appropriate business segment) in the accompanying Consolidated
Statements of Income.
(I) 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 deducted from 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, the Company
reviews the carrying values of its 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
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recorded. However, currently unforeseen events and changes in circumstances
could require the recognition of impairment losses at some future date.
(J) Depreciation and Amortization
Depreciation is computed based on the straight-line method over the estimated
useful lives of assets, ranging from 3 to 40 years for each of the Upstream,
Midstream and Downstream segments.
(K) Interest Expense, Net
"Interest Expense, Net" as presented in the accompanying Consolidated Statements
of Income is net of (i) the debt component of the allowance for funds used
during construction ("AFUDC - Interest") and (ii) interest income related to
government securities (collectively, "Interest Income"), as shown in the
following table:
1998 1997 1996
---- ---- ----
(In Millions)
AFUDC - Interest $ 5.4 $ 7.8 $ 1.8
Interest Income $46.4 $ - $ -
As discussed in Note 2, in conjunction with the January 30, 1998, acquisition of
MidCon Corp., the Company was required by the definitive stock purchase
agreement to assume the Substitute Note for $1.4 billion and to collateralize
the Substitute Note with bank letters of credit, a portfolio of government
securities or a combination of the two. As a result, the Company has a
significant amount of interest income ($27.4 million representing cash received
during 1998) associated with the issuance of the Substitute Note, which has been
reported together with the related interest expense as described preceding.
(L) Cash Flow Information
The Company considers 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, the
amortization of the gas plant acquisition adjustment recorded in conjunction
with the acquisition of MidCon, undistributed equity in earnings of
unconsolidated subsidiaries and joint ventures and other non-cash charges and
credits to income.
CHANGES IN OTHER WORKING CAPITAL ITEMS
(NET OF ACQUISITION AND DISPOSITION EFFECTS)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
1998 1997 1996
---- ---- ----
(In Thousands)
Accounts Receivable $ 85,241 $ (80,609) $ (89,466)
Non-gas Inventories (13,733) (1,777) 4,761
Other Current Assets 21,288 (7,656) (43,847)
Accounts Payable (187,303) 82,504 83,934
Other Current Liabilities 13,107 (8,364) 42,122
--------- --------- ---------
$ (81,400) $ (15,902) $ (2,496)
========= ========= =========
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SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
1998 1997 1996
---- ---- ----
(In Thousands)
CASH PAID DURING THE YEAR FOR:
Interest (Net of Amount Capitalized/Received)* $189,929 $ 41,986 $ 31,748
======== ======== ========
Distributions on Preferred Capital Trust Securities $ 14,754 $ 4,066 $ -
======== ======== ========
Income Taxes $ 39,756 $ 15,823 $ 14,156
======== ======== ========
* See Note 1 (K).
During 1998, the Company acquired MidCon Corp. and interests in assets from the
Thermo Companies in transactions that included both cash and non-cash
components. In December 1997, the Company acquired Interenergy Corporation in a
largely non-cash transaction. For additional information on these transactions,
see Note 2.
(M) Accounts Receivable
The caption "Accounts Receivable" in the accompanying Consolidated Balance
Sheets is presented net of allowances for doubtful accounts of $10.8 million and
$1.7 million at December 31, 1998 and 1997, respectively.
2. ACQUISITIONS, INVESTMENTS AND SALES
(A) Sale of Microwave Facilities
In September 1998, the Company sold certain of its microwave towers and
associated land and equipment to Boston-based American Tower Corp. for $14.6
million. The sale resulted in a pre-tax gain of $10.9 million ($6.7 million
after tax or $0.10 per diluted share) included in the accompanying Consolidated
Statements of Income under the caption "Other, Net."
(B) Thermo Companies
During the third quarter of 1998, the Company completed its acquisition of
interests in four independent power plants in Colorado from the Denver-based
Thermo Companies ("Thermo"), representing approximately 380 megawatts of
electric generation capacity and access to approximately 130 Bcf of natural gas
reserves. These generating facilities are located in Ft. Lupton, Colorado (272
megawatts) and Greeley, Colorado (108 megawatts) and sell their power output to
Public Service Company of Colorado under long-term agreements. Payment for these
interests will be made over a two-year period, with the initial payment of
689,810 shares (not adjusted for the December 1998 three-for-two stock split) of
K N common stock having been made on October 21, 1998. The second installment
payment was made on January 4, 1999, consisting of 833,623 shares of K N common
stock and $15 million in cash. The remaining payments (in 1999 and 2000) will be
made in a combination of cash and common stock as agreed to by the Company and
Thermo, with the default mix being 50 percent stock and 50 percent cash. In
conjunction with this transaction accounted for as a purchase, at December 31,
1998, K N had recorded a current liability of $86.8 million (shown in the
accompanying Consolidated Balance Sheets as "Payable for Purchase of Thermo
Companies") and a long-term liability of $31.4 million (included in the
accompanying Consolidated Balance Sheets within the caption "Other" under the
heading "Other Liabilities and Deferred Credits") representing the remaining
purchase obligation. The Company's investment in Thermo is shown in the
accompanying Consolidated Balance Sheets at December 31, 1998, under
"Investments" ($67.3 million) and "Deferred Charges and Other Assets" ($79.9
million), with the majority of the remaining balance shown as additions to
"Property, Plant and Equipment," and lesser amounts included with other asset
and liability accounts.
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(C) Sale of Kansas Distribution Properties
In March 1998, the Company completed the sale of its Kansas retail natural gas
distribution properties, located in 58 Kansas communities and serving
approximately 30,000 residential, commercial and industrial customers, to
Midwest Energy, Inc., a customer-owned cooperative based in Hays, Kansas. The
Company received approximately $24 million in cash in conjunction with the sale
and recorded a pre-tax gain of approximately $8.5 million (approximately $5.2
million after tax or $0.08 per diluted share). Concurrently with the sale, the
Company received $27.5 million in cash in exchange for the release of the
purchaser from certain contractual gas purchase obligations, which amount will
be amortized as an offset to expense over a period of years as the associated
volumes are sold.
(D) MidCon Corp.
On January 30, 1998, pursuant to a definitive stock purchase agreement (the
"Agreement"), the Company acquired all of the outstanding shares of capital
stock of MidCon Corp. ("MidCon") from Occidental Petroleum Corporation
("Occidental") for $2.1 billion in cash and the assumption of a $1.4 billion
note (the "Substitute Note"), at which time MidCon became a wholly owned
subsidiary of K N Energy, Inc. (the "Acquisition"). The Substitute Note bore
interest at 5.798 percent, was repaid January 4, 1999, and was required to be
collateralized by U.S. government securities, letters of credit or a combination
of the two. In conjunction with the Acquisition, the Company also assumed
MidCon's obligation to lease the MidCon Texas intrastate pipeline system under a
30-year operating lease, requiring average annual lease payments of
approximately $30 million. The Acquisition was initially financed through a
combination of credit agreements (see Note 7).
MidCon is engaged in the purchase, gathering, processing, transmission, storage
and sale of natural gas to utilities, municipalities, and industrial and
commercial users. MidCon's pipeline system includes over 13,000 miles of natural
gas pipelines located in the center of the North American pipeline grid, with
access to major supply and market areas. MidCon is also one of the nation's
largest natural gas storage operators and owns and operates several natural gas
gathering and natural gas processing facilities.
The Acquisition was accounted for as a purchase for accounting purposes and,
accordingly, the MidCon assets acquired and liabilities assumed have been
preliminarily recorded at their respective estimated fair market values as of
the acquisition date. The final fair market values will be assigned after
completion of the review of the relevant assets, liabilities and issues
identified as of the acquisition date. The preliminary allocation of purchase
price has resulted in the recognition of a gas plant acquisition adjustment of
approximately $3.9 billion, principally representing the excess of the assigned
fair market value of the assets of Natural Gas Pipeline Company of America
("NGPL"), a wholly owned subsidiary of MidCon, over the historical cost for
ratemaking purposes. This gas plant acquisition adjustment, none of which is
currently being recognized for ratemaking purposes, is being amortized over 36
years, approximately the estimated remaining useful life of NGPL's interstate
pipeline system. For the year ended December 31, 1998, approximately $97.9
million of such amortization was charged to expense. The assets, liabilities and
results of operations of MidCon are included with those of the Company beginning
with the January 30, 1998, acquisition date. Historical information for periods
prior to January 30, 1998, does not reflect any impact associated with the
MidCon acquisition.
The following pro forma information gives effect to the acquisition of MidCon as
if the business combination had occurred at the beginning of each period
presented. The pro forma adjustments which have been made are based on a
preliminary allocation of the purchase price to assets acquired and liabilities
assumed. In addition, no pro forma adjustments to prior periods have been made
for the post-acquisition refinancings completed by K N. This unaudited pro forma
information should be read in conjunction with the accompanying consolidated
financial statements, Management's Discussion and Analysis of Financial
Condition and Results of Operations and with
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the unaudited pro forma consolidated financial statements and related notes
previously filed with the Securities and Exchange Commission. This pro forma
information is not necessarily indicative of the financial results which would
have occurred had the Acquisition taken place on the dates indicated, nor is it
necessarily indicative of future financial results.
DECEMBER 31
UNAUDITED PRO FORMA FINANCIAL INFORMATION 1998 1997
- ----------------------------------------- ---- ----
(Dollars In Millions Except Per Share Amounts)
Operating Revenues $4,655.9 $5,194.1
Net Income $ 65.6 $ 78.8
Diluted Earnings Per Common Share $ 1.01 $ 1.67
Number of Shares Used in Computing Diluted Earnings
Per Common Share (In Thousands) 64,636 47,307
(E) Red Cedar
In December 1997, the Company purchased an equity interest in Red Cedar
Gathering Company ("Red Cedar"), a gathering system located in the northern San
Juan Basin on the Southern Ute Indian Reservation in La Plata County, Colorado.
K N owns a 49 percent interest, which is accounted for under the equity method.
Red Cedar is jointly owned with the Southern Ute Indian Tribe. See Note 12 for
information related to K N's corporate guarantee of Red Cedar debt.
(F) Interenergy
In December 1997, the Company acquired Interenergy Corporation ("Interenergy"),
a diversified energy company providing natural gas gathering, processing and
marketing services in the Rocky Mountain and Mid-Continent regions. In a
transaction accounted for as a purchase, the Company exchanged 544,604 shares
(not adjusted for the December 1998 three-for-two stock split) of K N common
stock for all of the outstanding shares of Interenergy.
(G) Bushton
In March 1997, the Company completed its purchase of several Enron Corporation
subsidiaries that owned or operated the Bushton natural gas processing facility
located in Ellsworth County, Kansas, and other Hugoton Basin gathering assets
located in Kansas and Oklahoma. The Company assumed operation of these
facilities effective April 1, 1997, and has accounted for this transaction as a
purchase. The processing facilities at Bushton are subject to operating leases
(which expire in 2012) requiring semi-annual payments averaging $23.1 million
per year for the remaining term of the leases. Under certain conditions, the
terms of these leases would require the posting of letters of credit (see Note
12).
(H) TransColorado Pipeline Project
After receiving required regulatory approvals, the TransColorado Gas
Transmission Company ("TransColorado"), an enterprise jointly owned by K N and
Questar Corp., began construction in July 1998 of a 280-mile-long natural gas
pipeline project which includes two compressor stations and extends from near
Rangely, Colorado, to its southern terminus at the Blanco Hub near Aztec, New
Mexico. The pipeline is
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expected to be completed and placed in service in early 1999 at a cost of
approximately $280 million and have transmission capacity of approximately 300
million cubic feet of natural gas per day. On October 14, 1998, TransColorado
entered into a $200 million revolving credit agreement with a group of
commercial banks. See Note 12 for information related to K N's corporate
guarantee of TransColorado debt.
3. REGULATORY MATTERS
(A) Rate Matters
On January 23, 1998, K N Interstate Gas Transmission Co. ("KNI") filed a general
rate case with the Federal Energy Regulatory Commission ("FERC") requesting a
$30.2 million increase in annual revenues. As a result of the FERC action, KNI
was allowed to place its rates into effect on August 1, 1998, subject to refund,
and provisions for refund have been recorded based on its expectation of
ultimate resolution. KNI is currently following the procedural schedule
established for the rate case, and a hearing on its proposed rates is currently
scheduled to commence on July 20, 1999.
On December 29, 1998, Rocky Mountain Natural Gas Company ("RMNG"), a wholly
owned subsidiary of K N Energy, Inc. received a "show cause" order from the
Colorado Public Utilities Commission (the "Commission"). The Commission has
concluded that there is reason to believe that RMNG's rates may be excessive and
may require further investigation. A procedural schedule has been established
and a hearing is scheduled to commence on June 1, 1999.
(B) Retail Unbundling
In November 1997, the Company announced a 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. This
program separates, or "unbundles," the natural gas purchases from other utility
services. As of December 31, 1998, the plan had been approved by 176
communities, representing approximately 95,000 customers served by the Company
in Nebraska. In June 1996, after receiving Wyoming Public Service Commission
approval for a pilot program, the Company implemented a similar plan for
approximately 10,500 residential and commercial customers in 10 Wyoming
communities.
4. ENVIRONMENTAL AND LEGAL MATTERS
(A) Environmental Matters
The U.S. Environmental Protection Agency (the "EPA") recently published a final
rule addressing transport of ground level ozone. The rule affects 22 Eastern and
Midwestern states, including Illinois and Missouri in which the Company operates
gas compression facilities. The rule requires reductions in emissions of
nitrogen oxide, a precursor to ozone formation, from various emission sources,
including utility and non-utility sources. The rule requires that the affected
states prepare and submit State Implementation Plans to the EPA by September
1999, reflecting how the required emissions reductions will be achieved.
Emission controls are required to be installed by May 1, 2003. This rule will
likely result in the Company, as well as its competitors, being required to
install some form of new emissions control technology on certain equipment it
operates. Another impact from the rule is that it may result in broad increased
use of natural gas, as other sources of nitrogen oxide air emissions, including
utilities, seek to achieve the reductions required under the rule. The State
Implementation Plans which will effectuate this rule have yet to be proposed or
promulgated, and will require detailed analysis before their final economic
impact can be ascertained. While additional capital costs are likely to result
from this rule, based on currently available information, the Company does not
believe that these costs will have a material adverse effect on its business,
financial position or results of operations.
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On February 6, 1998, the EPA published in the Federal Register a proposed
standard to limit emissions of hazardous air pollutants ("HAPs") from oil and
natural gas production as well as from natural gas transmission and storage
facilities. This is a Maximum Achievable Control Technology ("MACT") standard,
and is mandated under section 112 of the 1990 Amendments to the Clean Air Act.
The proposed MACT standard requires that the affected facilities reduce
emissions of HAPs by 95 percent. This new standard will require the Company to
achieve this reduction either by process modifications or by installing new
emissions control technology. The MACT standard will affect the Company and its
competitors in a like manner. The EPA has stated that the standard will be
promulgated in its final form by May 15, 1999. The rule will allow most affected
sources three years to come into compliance. The rule in its final form will
require detailed analysis to determine its overall effect on the Company. While
additional capital costs are likely to result from this rule, the Company
believes that the rule will not have a material adverse effect on the Company's
business, financial position or results of operations.
In connection with the Company's acquisition of MidCon in January 1998,
Occidental indemnified the Company against certain liabilities, including
litigation and the failure of MidCon to be in compliance with applicable laws,
which, in each case, would have a material adverse effect on MidCon, for one
year following the closing date. To the extent that an environmental liability
of MidCon is not covered by Occidental's indemnity obligation or, to the extent
that matters arise following the termination of Occidental's indemnification
obligation, the Company will be responsible for MidCon's environmental
liabilities. The Company does not expect that such costs will have a material
adverse effect on its business, financial position or results of operations.
Pursuant to certain acquisition agreements involving Cabot Corporation
("Cabot"), Cabot indemnified the Company for certain environmental liabilities
associated with assets in Texas, Oklahoma and New Mexico acquired from American
Oil and Gas Corporation. Issues arose concerning Cabot's indemnification
obligations, and the Company and Cabot entered into binding arbitration to
resolve all issues in dispute. The binding decision of the arbitrators resulted
in the requirement that Cabot pay the Company for a substantial portion of past
and future environmental related costs associated with the properties. In
December 1998, the Company recorded a charge of approximately $7.2 million
representing both previously incurred costs which were not awarded in the
arbitration and the recognition of a liability for the Company's share of
estimated future costs. As a result of this settlement, the Company will have no
future expense associated with this matter. The Company does not expect its
potential exposure for the remaining liabilities to have a material adverse
effect on the Company's business, financial position or results of operations.
Based on current information and taking into account reserves established for
environmental matters, the Company does not believe that compliance with
federal, state and local environmental laws and regulations will have a material
adverse effect on the Company's business, financial position or results of
operations. In addition, the clean-up programs in which the Company is engaged
are not expected to interrupt or diminish the Company's operational ability to
gather or transport natural gas. 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 the Company to incur
significant costs.
(B) Litigation Matters
On October 9, 1992, Jack J. Grynberg filed suit in the United States District
Court for the District of Colorado against the Company, RMNG and GASCO, Inc.
(the "K N Entities") alleging that 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 defendant companies have engaged in
an illegal exercise of monopoly power, have illegally denied him economically
feasible access to essential facilities to transport and distribute gas produced
from fewer than 20 wells located in northwest Colorado, and have illegally
attempted to monopolize or to
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enhance or maintain an existing monopoly. Grynberg also asserts certain causes
of action relating to a gas purchase contract. In February 1999, the Federal
District Court granted summary judgment regarding some of Grynberg's antitrust
and state law claims, while allowing other claims to proceed to trial. The
Company's potential liability and the amount of such damages, if any, are
subject to dispute between the parties; however, the Company believes it has a
meritorious position in these matters and does not expect this lawsuit to have a
material adverse effect on the Company's business, financial position or results
of operations. In July 1996, the U.S. District Court, District of Colorado
lifted its stay and allowed discovery for a period of time. Currently, this case
is still pending. Discovery is now complete, but no trial date has yet been set.
On July 26, 1996, the Company and RMNG, along with over 70 other natural gas
companies, were served by Jack J. Grynberg, acting on behalf of the Government
of the United States, with a Civil False Claims Act lawsuit alleging
mismeasurement of the heating content and volume of natural gas resulting in
underpayment of royalties to the federal government. The Company and the other
named companies filed a motion to dismiss the lawsuit on grounds of improper
joinder and lack of jurisdiction. The motion was granted in 1997, but the court
gave Mr. Grynberg leave to refile this action in a court with proper
jurisdiction. Mr. Grynberg appealed the dismissal of the action based on
improper joinder, and the D.C. Court of Appeals affirmed the joinder decision in
October 1998. Mr. Grynberg has filed a new case, modified somewhat from his
original action, in Federal District Court, District of Colorado. The Company
has not yet been served in this new action, which is under seal pending federal
governmental reviews of the merits. The Department of Justice has not yet made a
decision regarding whether to intervene in this new case. The Company has
engaged in both formal and informal discussions with the Government regarding
this case. The Company believes it has a meritorious position in this matter,
and does not expect this lawsuit to have a material adverse effect on the
Company's business, financial position or results of operations.
The Company believes it has meritorious defenses to all lawsuits and legal
proceedings in which it is a defendant and will vigorously defend against them.
Based on its evaluation of the above matters, and after consideration of
reserves established, the Company believes that the resolution of such matters
will not have a material adverse effect on the Company's business, financial
position or results of operations.
5. PROPERTY, PLANT AND EQUIPMENT
Investments in property, plant and equipment, at cost, and accumulated
depreciation and amortization ("Accumulated D&A"), detailed by business segment,
are as follows:
DECEMBER 31, 1998
------------------------------------------------------------------
PROPERTY, PLANT ACCUMULATED
AND EQUIPMENT D&A NET
--------------- ----------- -----------
(In Thousands)
Upstream Gathering and Processing $ 643,840 $ 148,814 $ 495,026
Midstream Sales, Transportation and Storage 6,657,285* 490,503 6,166,782*
Downstream Retail and Marketing 466,207 104,839 361,368
----------- --------- -----------
$ 7,767,332* $ 744,156 $ 7,023,176*
=========== ========= ===========
*The increase in property, plant and equipment from December 31, 1997, to
December 31, 1998, is largely due to the January 30, 1998, acquisition of
MidCon and includes a gas plant acquisition adjustment (see Note 2).
DECEMBER 31, 1997
------------------------------------------------------------------
PROPERTY, PLANT ACCUMULATED
AND EQUIPMENT D&A NET
--------------- ----------- -----------
(In Thousands)
Upstream Gathering and Processing $ 555,596 $ 135,859 $ 419,737
Midstream Sales, Transportation and Storage 1,115,971 307,455 808,516
Downstream Retail and Marketing 300,034 107,312 192,722
----------- --------- -----------
$ 1,971,601 $ 550,626 $ 1,420,975
=========== ========= ===========
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6. 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
that is not expected to be realized.
Components of the income tax provision applicable to federal and state income
taxes are as follows:
1998 1997 1996
-------- -------- --------
(Dollars In Thousands)
TAXES CURRENTLY PAYABLE:
Federal $ 12,645 $ 15,932 $ 17,685
State 4,372 2,574 1,769
-------- -------- --------
Total 17,017 18,506 19,454
-------- -------- --------
TAXES DEFERRED:
Federal 19,657 16,497 15,601
State 1,598 658 842
-------- -------- --------
Total 21,255 17,155 16,443
-------- -------- --------
TOTAL TAX PROVISION $ 38,272 $ 35,661 $ 35,897
======== ======== ========
EFFECTIVE TAX RATE 38.9% 31.5% 36.0%
======== ======== ========
The difference between the statutory federal income tax rate and the Company's
effective income tax rate is summarized as follows:
1998 1997 1996
------ ------ ------
FEDERAL INCOME TAX RATE 35.0% 35.0% 35.0%
INCREASE (DECREASE) AS A RESULT OF:
State Income Tax, Net of Federal Benefit 3.9% 1.9% 1.7%
Adjustments to Prior Year Accruals* - (5.1%) -
Other - (0.3%) (0.7%)
------ ------ ------
EFFECTIVE TAX RATE 38.9% 31.5% 36.0%
====== ====== ======
*Adjustments relate to the successful resolution of certain issues from prior
years' income tax filings.
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Deferred tax assets and liabilities result from the following:
DECEMBER 31
1998 1997
---------- ---------
(Dollars In Thousands)
DEFERRED TAX ASSETS:
Postretirement Benefits $ 44,506 $ 2,294
Gas Supply Realignment Deferred Receipts 36,478 -
Vacation Accrual 4,930 2,008
State Taxes 68,332 5,722
Contract Impairments 11,075 -
Operating and Misc. Reserves 7,583 2,281
Alternative Minimum Tax Credits 16,620 6,780
Other 26,501 701
---------- ---------
TOTAL DEFERRED TAX ASSETS 216,025 19,786
---------- ---------
DEFERRED TAX LIABILITIES:
Property, Plant and Equipment 1,904,706 168,707
Rate Matters 550 8,420
Prepaid Pension 3,560 2,814
Stock Investments 1,809 3,556
Other 4,472 4,872
---------- ---------
TOTAL DEFERRED TAX LIABILITIES 1,915,097 188,369
---------- ---------
NET DEFERRED TAX LIABILITIES $1,699,072 $ 168,583
========== =========
7. FINANCING
(A) Notes Payable
On March 7, 1997, the Company's existing revolving credit agreement with seven
commercial banks was amended to include a total of 11 banks and to increase the
amount to $350 million (the "Pre-Acquisition Facility"). Effective with the
acquisition of MidCon on January 30, 1998, the Pre-Acquisition Facility was
replaced with a $4.5 billion credit facility (the "Bank Facility") consisting of
(i) a $1.4 billion 364-day credit facility (the "L/C Facility") to support the
note issued to Occidental in conjunction with the purchase of MidCon, (ii) a
$2.1 billion, 364-day revolving facility (the "Acquisition Facility"), (iii) a
$400 million five-year revolving credit facility (the "$400 million Facility")
providing for loans and letters of credit, of which the letter of credit usage
may not exceed $100 million and (iv) a 364-day $600 million revolving credit
facility (the "$600 million Facility"). The L/C Facility and the Acquisition
Facility could be used only in conjunction with the acquisition of MidCon. In
addition to the working capital and acquisition components of the Bank Facility,
K N assumed a short-term note for $1.4 billion payable to Occidental (the
"Substitute Note"), which, pursuant to the Agreement, was initially
collateralized by letters of credit issued under a commitment for that purpose
within the Bank Facility.
The $2.1 billion Acquisition Facility was repaid in its entirety and cancelled
on March 10, 1998. The Substitute Note was repaid on January 4, 1999. On January
5, 1999, K N cancelled the remaining letters of credit used to collateralize the
Substitute Note. On January 8, 1999, the $600 million Facility was replaced with
a new 364-day facility which is essentially the same as the previous agreement.
The bank facilities include covenants which are common in such arrangements,
including requirements that (i) the ratio of the Company's total debt to total
capitalization not exceed 74 percent initially (upon issuance of common stock to
the holders of the premium equity participating security units ("PEPS") at the
maturity thereof, the ratio will be reduced to 67 percent) and (ii) the
Company's consolidated net worth (inclusive of trust preferred securities) be at
least equal to the sum of $1.236 billion plus 50 percent of consolidated net
income earned for each fiscal quarter ending after December 30, 1998.
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51
Under the credit agreements described preceding, K N agreed to pay a facility
fee based on the total commitment, at a rate which varies based on K N's senior
debt rating. Facility fees paid in 1998 and 1997 were $1.7 million and $0.3
million, respectively. At December 31, 1998, there were no amounts outstanding
under the Bank Facility as amended, compared with $100 million at December 31,
1997, under the Pre-Acquisition Facility.
Commercial paper issued by K N and supported by short-term credit facilities are
unsecured short-term notes with maturities not to exceed 270 days from the date
of issue. During 1998, all commercial paper was redeemed within 180 days, with
interest rates ranging from 4.95 to 6.75 percent. Commercial paper outstanding
at December 31, 1998 and 1997, respectively, was $297.0 million and $229.2
million. The weighted-average interest rates on short-term borrowings
outstanding at December 31, 1998 and 1997, respectively, were 5.70 percent and
6.87 percent. Average short-term borrowings outstanding during 1998 and 1997
were $732.9 million and $212.6 million, respectively. During 1998 and 1997, the
weighted-average interest rates on short-term borrowings outstanding were 5.91
percent (excluding the Substitute Note) and 5.74 percent, respectively.
(B) Long-Term Debt
DECEMBER 31
------------------------------
1998 1997
----------- ----------
(In Thousands)
DEBENTURES:
6.50% Series, Due 2013 $ 50,000 $ 50,000
7.85% Series, Due 2022 26,631 26,684
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 500,000 -
7.45% Series, Due 2098 150,000 -
SINKING FUND DEBENTURES:
9.95% Series, Due 2020 20,000 20,000
9.625% Series, Due 2021 45,000 45,000
8.35% Series, Due 2022 35,000 35,000
SENIOR NOTES:
7.27%, Due 1999-2002 20,000 25,000
11.846% (AOG) - 11,875
6.45%, Due 2001 400,000 -
6.45%, Due 2003 500,000 -
6.65%, Due 2005 500,000 -
6.80%, Due 2008 300,000 -
Reset Put Securities, 6.30%, Due 2021 400,000 -
Medium-Term Notes, 9.98%, Due 1999 3,000 7,000
Other 16,318 14,965
Unamortized Debt Discount (5,757) (957)
Current Maturities of Long-Term Debt (10,167) (30,751)
----------- ----------
Total Long-Term Debt $ 3,300,025 $ 553,816
=========== ==========
Maturities of long-term debt for the five years ending December 31, 2003, are as
follows:
YEAR AMOUNT
- ---- ------
(In Thousands)
1999 $ 10,167
2000 7,167
2001 408,167
2002 10,417
2003 507,167
In November 1998, the Company completed an underwritten public offering of $400
million of three-year senior notes (the "Senior Notes") bearing an interest rate
of 6.45 percent. The net proceeds of approximately $397.4 million were used to
retire a portion of K N's then-outstanding short-term borrowings. Concurrently
with the
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Senior Notes offering, the Company sold $460 million principal amount of PEPS in
an underwritten public offering. The PEPS essentially are contracts (i)
requiring the holders to purchase K N common stock at the end of a three-year
period coinciding with the maturity of the Senior Notes and (ii) providing for
payment of a contract fee of 2.375 percent to the PEPS holders by the Company
during the three-year period. Payment of all or any part of the contract fees
may be deferred by the Company until no later than the end of the three-year
period and any portion so deferred will accrue interest at the annual rate of
8.25 percent until paid. The net cash proceeds from the sale of the PEPS,
together with additional funds provided by the Company, were used to purchase
U.S. treasury securities (the "Collateral") on behalf of the PEPS owners. The
Collateral is the property of the PEPS holders and is pledged to the collateral
agent, for the benefit of the Company, in support of the obligation of the PEPS
holders to purchase K N common stock.
The face value of the PEPS is not recorded in the accompanying Consolidated
Balance Sheets. The $29.4 million present value of the contract fee payable to
the PEPS holders has been recorded as a liability and as a reduction to paid-in
capital. During the period in which the contract fees are payable, accretion of
the $3.4 million of discount initially recorded will increase the liability and
further decrease paid-in capital. In addition, paid-in capital has been reduced
for the issuance costs associated with the PEPS and the premium paid upon
purchase of the Collateral, which amounts total approximately $32.8 million.
In March 1998, the Company received net proceeds of approximately $2.34 billion
from the public offerings of senior debt securities of varying maturities with
principal totaling $2.35 billion. The net proceeds from these offerings were
used to refinance borrowings under the Bank Facility and to purchase U.S.
government securities to replace a portion of the letters of credit that
collateralized the Substitute Note.
Following are the principal amounts, maturity dates and coupon rates for the
senior debt securities issued:
$500 million - 6.45% Senior Notes due March 1, 2003
$500 million - 6.65% Senior Notes due March 1, 2005
$300 million - 6.80% Senior Notes due March 1, 2008
$500 million - 7.25% Senior Debentures due March 1, 2028
$150 million - 7.45% Senior Debentures due March 1, 2098
$400 million - 6.30% Reset Put Securities due March 1, 2021
The 2003 Senior Notes and the 2005 Senior Notes are not redeemable prior to
maturity. The 2008 Senior Notes, 2028 Senior Debentures and 2098 Senior
Debentures are redeemable in whole or in part, at the option of the Company at
any time, at redemption prices defined in the associated prospectus supplement.
The Reset Put Securities due March 1, 2021 (the "2021 REPS") are subject to
mandatory redemption from the then-existing holders on March 1, 2001, either (i)
through the exercise of a call option by Morgan Stanley & Co. International
Limited (the "Callholder") or (ii) in the event the Callholder does not exercise
the call option, the automatic exercise of a mandatory put by First Trust
National Association on behalf of the holders. The $12 million of proceeds
received by K N from the Callholder as consideration for the call option are
being amortized as an adjustment to the effective interest rate on the 2021
REPS. If the Callholder elects to exercise the call option, the interest rate
will be reset at that time.
On October 27, 1997, the Company sold $150 million of 6.67% debentures maturing
on November 1, 2027, in an underwritten public offering. These debentures are
callable by the Company any time after November 1, 2004, and are redeemable at
the option of the registered holders on November 1, 2004. The Company used the
net proceeds from the sale to reduce outstanding short-term indebtedness.
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53
At December 31, 1998 and 1997, the carrying amount of the Company's long-term
debt was $3.3 billion and $585.5 million, respectively. The estimated fair
values of the Company's long-term debt December 31, 1998 and 1997 are shown in
Note 13.
(C) Capital Securities
In April 1998, the Company sold $175 million of 7.63% Capital Trust Securities
maturing on April 15, 2028, in an underwritten public offering. The sale was
effected through a wholly owned business trust, K N Capital Trust III. The
Company used the net proceeds from the offering to purchase U.S. government
securities to replace a portion of the letters of credit that collateralized the
Substitute Note.
In April 1997, the Company sold $100 million of 8.56% Capital Trust Securities
maturing on April 15, 2027, in an underwritten public offering. The sale was
effected through a wholly owned business trust, K N Capital Trust I. The Company
used the net proceeds from the sale to reduce outstanding short-term
indebtedness.
The transactions and balances of K N Capital Trust I and K N Capital Trust III
are included in the Company's consolidated financial statements, with the
Capital Securities treated as a minority interest, shown in the Company's
Consolidated Balance Sheets under the caption "K N-Obligated Mandatorily
Redeemable Preferred Capital Trust Securities of Subsidiary Trust Holding Solely
Debentures of K N." See Note 13 for the fair value of these securities.
(D) Common Stock
On November 9, 1998, the Board of Directors of K N Energy, Inc. approved a 7.1
percent increase in the quarterly dividend and a three-for-two split of the
Company's common stock. The quarterly dividend was declared at $0.30 per common
share, an increase from $0.28 per common share. Giving effect to the stock
split, the quarterly dividend is $0.20 per common share. The stock split was
distributed and the increase in dividend was paid concurrently on December 31,
1998, to shareholders of record at the close of business on December 15, 1998.
The par value of the stock did not change. Weighted-average shares outstanding
and all per share amounts in the accompanying consolidated financial statements
and these notes have been restated to reflect the stock split.
In March 1998, the Company received net proceeds of approximately $624.6 million
from a public offering of 12.5 million shares (18.75 million shares after
adjustment for the December 1998 three-for-two stock split) of its common stock.
The net proceeds from this offering were used to refinance borrowings under the
Bank Facility and to purchase U.S. government securities to replace a portion of
the letters of credit that collateralized the Substitute Note.
On June 11, 1997, Cabot exercised the remaining warrants held by it and
purchased, in an unregistered offering, 642,232 shares (not adjusted for the
December 1998 three-for-two stock split) of K N's common stock, which were
issued to Cabot Specialty Chemicals, Inc., in exchange for Cabot's payment of
$11.3 million.
8. PREFERRED STOCK
The Company has authorized 200,000 shares of Class A and 2,000,000 shares of
Class B preferred stock, all without par value.
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(A) Class A $5.00 Preferred Stock
At both December 31, 1998 and 1997, 70,000 shares of the Company's Class A $5.00
Cumulative Series preferred stock were outstanding. The Class A $5.00 Preferred
Stock is redeemable, in whole or in part, at the option of the Company at any
time on 30 days' notice at $105 per share plus accrued dividends and has no
sinking fund requirements.
(B) Class B Preferred Stock
The Company did not have any outstanding shares of Class B Preferred Stock at
December 31, 1998 or 1997. The remaining 5,720 shares of K N Class B $8.30
Preferred Stock subject to mandatory redemption were redeemed by the Company in
1996.
(C) Rights of Preferred Shareholders
All outstanding series of preferred stock have voting rights. If, for any class
of preferred stock, the Company (i) is in arrears on dividends, (ii) has failed
to pay or set aside any amounts required to be paid or set aside for all sinking
funds or (iii) is in default on any of its redemption obligations, then no
dividends shall be paid or declared on any class of stock junior to the
preferred stock nor shall any of such stock be purchased or redeemed by the
Company. Also, if dividends on any class of preferred stock are sufficiently in
arrears, the holders of that stock may elect one-third of the Company's Board of
Directors.
9. RISK MANAGEMENT
The Company uses two types of risk management instruments - energy financial
instruments and interest rate swaps - as discussed following. The Company is
exposed to credit-related losses in the event of nonperformance by
counterparties to these financial instruments, but does not expect any
counterparties to fail to meet their obligations given their existing credit
ratings.
The fair value of these risk management instruments reflects the estimated
amounts that the Company 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
financial instruments used by the Company.
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
Accounting for Derivative Instruments and Hedging Activities (the "Statement").
The Statement establishes accounting and reporting standards requiring that
every derivative 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 Statement requires that changes in the
derivatives fair value be recognized currently in earnings unless specific hedge
accounting criteria are met. If the derivatives meet these criteria, the
Statement 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.
The Statement is effective for fiscal years beginning after June 15, 1999. A
company may also implement the Statement as of the beginning of any fiscal
quarter after issuance (that is, fiscal quarters beginning June 16, 1998 and
thereafter). The Statement cannot be applied retroactively. The Statement must
be applied to (i) derivative instruments and (ii) certain derivative instruments
embedded in hybrid contracts that were issued, acquired, or substantively
modified after December 31, 1997, (and, at the company's election, before
January 1, 1998). K N
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has not yet quantified the impacts of adopting the Statement on its financial
position or results of operations and has not determined the timing of or method
of adoption of the Statement.
In December 1998, the Emerging Issues Task Force ("EITF") issued EITF 98-10,
Accounting for Energy Trading and Risk Management Activities. This consensus
establishes accounting for energy trading activities prior to the adoption of
the Statement. EITF 98-10 requires that energy contracts associated with trading
activities be recorded at fair value on the balance sheet, with the changes in
fair value included in earnings. The effects of initial application of EITF
98-10 are required to be reported as a cumulative effect of a change in
accounting principle. Financial statements for periods prior to initial adoption
of EITF 98-10 may not be restated. EITF 98-10 is effective for fiscal years
beginning after December 15, 1998. Given the Company's restrictive policy with
respect to the use of energy derivatives as discussed following, the Company
does not expect any material impact from the application of EITF 98-10 to its
operations.
(A) Energy Financial Instruments
The Company uses energy financial instruments to reduce its risk of price
changes in the spot and fixed price natural gas and NGLs markets. Energy risk
management products include commodity futures and options contracts, fixed-price
swaps and basis swaps. Pursuant to its Board of Directors' approved policy, the
Company is to engage in these activities only as a hedging mechanism against
price volatility associated with pre-existing or anticipated physical gas and
condensate sales, gas purchases, system use and storage in order to protect
profit margins, and is prohibited from engaging in speculative trading.
Commodity-related activities of the risk management group are monitored by the
Company's Risk Management Committee, which is charged with the review and
enforcement of the Board of Directors' risk management policy. Changes in fair
value for trading activities are recognized currently in earnings within the
caption "Other, Net" under the heading "Other Income and (Deductions)" in the
Consolidated Statements of Income. All energy futures, swaps and options are
recorded at fair value. Gains and losses on hedging positions are deferred and
recognized as gas purchases expense in the periods which the underlying physical
transactions occur.
Purchases of commodity contracts and over-the-counter swaps and options require
75 percent of the contract amount to be placed in margin accounts. At December
31, 1998, the Company had $9.1 million in such margin accounts, which amounts
are shown as "Restricted Deposits" in the accompanying Consolidated Balance
Sheets.
The differences between the current market value and the original physical
contracts' value, associated with hedging activities, are reflected, depending
on maturity, as deferred charges or credits and other current assets or
liabilities in the accompanying Consolidated Balance Sheets. These deferrals are
offset by the corresponding value of the underlying physical transactions. In
the event energy financial instruments do not meet the criteria for hedge
accounting, the deferred gains or losses associated with the corresponding
financial instruments would be included in the results of operations in the
current period. In the event energy financial instruments are terminated prior
to the period of physical delivery of the items being hedged, the gains or
losses on the energy financial instruments at the time of termination remain
deferred until the period of physical delivery unless both the energy financial
instruments and the items being hedged result in a loss. If this occurs, the
loss is recorded immediately.
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Following is selected information concerning the Company's risk management
activities:
DECEMBER 31, 1998
-----------------
COMMODITY OVER-THE-COUNTER
CONTRACTS SWAPS AND OPTIONS TOTAL
--------- ----------------- -----
(In Thousands)
Deferred Net (Loss) / Gain $ (4,643) $ 1,457 $ (3,186)
Contract Amounts $ 38,070 $ (39,344) $ (1,274)
Credit Exposure of Loss $ - $ 10,833 $ 10,833
(Billions of Cubic Feet)
Notional Volumetric Positions: Long 30.2 159.9 190.1
Notional Volumetric Positions: Short 28.8 146.8 175.6
Net Notional Totals to Occur in 1999 1.0 12.3 13.3
Net Notional Totals to Occur in 2000 & Beyond 0.4 0.8 1.2
Deferred net losses are reflected in "Deferred Charges and Other Assets" in the
accompanying Consolidated Balance Sheets and will be matched with the
corresponding underlying physical transactions.
(B) Interest Rate Swaps
From time to time, the Company has entered into various interest rate swap and
cap agreements for the purpose of managing interest rate exposure, none of which
agreements is leveraged. Settlement amounts payable or receivable under these
agreements is recorded as interest expense or income in the accounting period
they are incurred. The notional principal covered under such arrangements for
the periods presented are not material to the consolidated financial statements.
10. EMPLOYEE BENEFITS
(A) Retirement Plans
The Company has defined benefit pension plans covering substantially all
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. The
Company's funding policy is to contribute annually the recommended contribution
using the actuarial cost method and assumptions used for determining annual
funding requirements.
In February 1998, the Financial Accounting Standards Board issued SFAS No. 132,
Employers' Disclosures about Pensions and Other Postretirement Benefits. This
statement revises employers' disclosures about pension and other postretirement
benefit plans and requires additional information on changes in the benefit
obligations and fair values of plan assets. Restatement of disclosures for
earlier periods provided for comparative purposes is required.
Plan assets consist primarily of pooled fixed income, equity, bond and money
market funds. Plan assets include securities of the Company valued at $5.0
million as of December 31, 1998.
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Net periodic pension cost includes the following components:
1998 1997 1996
-------- -------- --------
(In Thousands)
Service Cost $ 4,859 $ 3,462 $ 3,289
Interest Cost 7,537 7,155 6,756
Expected Return on Assets (11,812) (10,276) (9,217)
Net Amortization and Deferral (864) (311) (130)
-------- -------- --------
Net Periodic Pension (Benefit) Cost $ (280) $ 30 $ 698
======== ======== ========
The following table sets forth the reconciliation of the beginning and ending
balances of the pension benefit obligation:
1998 1997
--------- ---------
(In Thousands)
Benefit Obligation at Beginning of Year $(106,383) $ (97,182)
Service Cost (4,859) (3,462)
Interest Cost (7,537) (7,155)
Actuarial Loss (8,477) (4,573)
Benefits Paid 6,180 5,989
--------- ---------
Benefit Obligation at End of Year $(121,076) $(106,383)
========= =========
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
amounts recognized under the caption "Other Current Assets" in the Company's
Consolidated Balance Sheets:
DECEMBER 31
---------------------------
1998 1997
--------- ---------
(In Thousands)
Fair Value of Plan Assets at Beginning of Year $ 141,423 $ 123,749
Actual Return on Plan Assets During the Year 8,740 23,663
Benefits Paid During the Year (6,180) (5,989)
--------- ---------
Fair Value of Plan Assets at End of Year 143,983 141,423
Benefit Obligation at End of Year (121,076) (106,383)
--------- ---------
Plan Assets in Excess of Projected Benefit
Obligation 22,907 35,040
Unrecognized Net Gain (12,619) (24,669)
Prior Service Cost Not Yet Recognized in Net Periodic
Pension Costs 218 138
Unrecognized Net Asset (989) (1,136)
--------- ---------
Prepaid Pension Cost $ 9,517 $ 9,373
========= =========
The rate of increase in future compensation and the expected long-term rate of
return on plan assets were 3.5 percent and 8.5 percent, respectively, for both
1998 and 1997. The weighted-average discount rate used in determining the
actuarial present value of the projected benefit obligation was 6.75 percent and
7.25 percent for 1998 and 1997, respectively.
The Company makes discretionary annual contributions to the K N Energy, Inc.
Profit Sharing and Savings Plan (the "Profit Sharing Plan"), a defined
contribution plan. Contributions are made in the year following the year for
which the contribution amount is calculated. The Company's contribution amount
is determined by comparing actual results for that year to a predetermined
graduated scale of annual operating goals. No contribution was made to the
Profit Sharing Plan for 1998. For 1997 and 1996, the Company contributed amounts
equal to seven percent and the ten percent maximum of eligible employee
compensation, respectively. The 1997 and 1996 contributions were $5.3 million
and $6.6 million, respectively, 50 percent of which was in the form of Company
stock.
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In January 1998, the Company acquired the MidCon Retirement Plan ("MRA") as part
of its acquisition of MidCon (see Note 2 (D)). The MRA is a defined contribution
plan. Contributions to the plan are based on age and earnings. Effective January
1, 1999, the MRA was merged into the Profit Sharing Plan, at which time eligible
MidCon employees joined the Company's defined benefit pension plans. In 1998,
the Company contributed $4.6 million to the MRA.
(B) Other Postretirement Employee Benefits
The Company has 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 (see note 2 (D)). The Company
acquired the postretirement medical and life insurance plans of already retired
employees of MidCon as a result of the acquisition of MidCon. These plans were
"grandfathered" in by the Company as of the acquisition date and no new
employees have or will be added to these plans subsequent to the acquisition
date. The Company funds the future expected postretirement benefit cost under
the plan by making payments to Voluntary Employee Benefit Association trusts.
The Company's funding policy is to contribute amounts within the deductibility
limits imposed on Internal Revenue Code Sec. 501(c)(9) trusts. Plan assets
consist primarily of pooled fixed income funds.
Net periodic postretirement benefit cost includes the following components:
1998 1997 1996
------- ------ ------
(In Thousands)
Service Cost $ 592 $ 205 $ 324
Interest Cost 6,425 1,394 1,392
Expected Return on Assets (2,854) (159) (114)
Net Amortization and Deferral 919 811 894
Curtailment Gain (1,569) - -
------ ------ ------
Net Periodic Postretirement Benefit Cost $3,513 $2,251 $2,496
====== ====== ======
The following table sets forth the reconciliation of the beginning and ending
balances of the accumulated postretirement benefit obligation ("APBO"):
1998 1997
--------- ---------
(In Thousands)
Benefit Obligation at Beginning of Year $ (19,768) $ (19,421)
Service Cost (592) (205)
Interest Cost (6,425) (1,394)
Actuarial Gain/(Loss) (7,663) 99
Benefits Paid 11,812 1,761
Retiree Contributions (2,060) (608)
Transfer from MidCon Plan (78,861) -
Curtailment 1,569 -
--------- ---------
Benefit Obligation at End of Year $(101,988) $ (19,768)
========= =========
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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 the Company's Consolidated Balance Sheets:
DECEMBER 31
---------------------------
1998 1997
--------- ---------
(In Thousands)
Fair Value of Plan Assets at Beginning of Year $ 3,569 $ 3,192
Actual Return on Plan Assets* 4,850 159
Contributions by Employer * 2,368 720
Retiree Contributions* 1,207 -
Benefits Paid* (883) (502)
Transfer from MidCon Plan* 34,253 -
--------- ---------
Fair Value of Plan Assets at End of Year 45,364 3,569
Benefit Obligation at End of Year (101,988) (19,768)
--------- ---------
Excess of Projected Benefit Obligation Over
Plan Assets (56,624) (16,199)
Unrecognized Net (Gain)/Loss 3,790 (681)
Unrecognized Net Obligations at Transition 13,007 13,936
--------- ---------
Accrued Expense $ (39,827) $ (2,944)
========= =========
* Represents activity during the year indicated.
The weighted-average discount rate used in determining the actuarial present
value of the APBO was 6.75 percent in 1998 and 7.25 percent in 1997. The assumed
health care cost trend rate was 7 percent for 1998 and beyond. 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 1998 net periodic postretirement
benefit cost by approximately $24,000 ($26,000) and would have increased
(decreased) the APBO as of December 31, 1998, by approximately $249,000
($251,000).
11. COMMON STOCK OPTION AND PURCHASE PLANS
The Company has the following stock option plans: The 1982 Incentive Stock
Option Plan (the "1982 Plan"), the 1982 Stock Option Plan for Non-Employee
Directors (the "1982 Directors' Plan"), the 1986 Incentive Stock Option Plan
(the "1986 Plan"), the 1988 Incentive Stock Option Plan (the "1988 Plan"), the
1992 Stock Option Plan for Non-Employee Directors (the "1992 Directors' Plan"),
the 1994 K N Energy, Inc. Long-Term Incentive Plan (the "LTIP Plan") and the
American Oil and Gas Corporation Stock Incentive Plan (the "AOG Plan"). The
Company also has an employee stock purchase plan (the "ESP Plan"). All per share
amounts and shares outstanding or exercisable presented in this note have been
restated to reflect the impact of the December 31, 1998, three-for-two common
stock split as discussed in Note 7 (D).
The Company accounts for its plans under Accounting Principles Board Opinion No.
25, Accounting for Stock Issued to Employees. The Company recorded compensation
expense totaling $3.1 million, $2.4 million and $0.8 million for 1998, 1997 and
1996, respectively, relating to restricted stock grants awarded under the plans.
59
60
Had compensation cost for these plans been determined consistent with SFAS
No. 123, Accounting for Stock-Based Compensation ("SFAS 123"), the Company's net
income and diluted earnings per share would have been reduced to the following
pro forma amounts:
1998 1997 1996
------- ------- -------
(In Thousands Except Per Share Amounts)
NET INCOME:
As Reported $59,989 $77,497 $63,819
======= ======= =======
Pro Forma $55,887 $73,028 $62,497
======= ======= =======
EARNINGS PER DILUTED SHARE:
As Reported $ 0.92 $ 1.63 $ 1.43
======= ======= =======
Pro Forma $ 0.86 $ 1.53 $ 1.40
======= ======= =======
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 $0.6 million, $0.4 million and $0.4 million related to
the purchase discount offered under the ESP Plan for 1998, 1997 and 1996,
respectively.
The Company may sell up to 2,400,000 shares of stock to its eligible employees
under the ESP Plan. Employees purchased 163,799 shares, 132,202 shares and
131,422 shares for plan years 1998, 1997 and 1996, respectively, and have
purchased 1,022,900 shares from inception through the 1998 plan year. Shares are
issued in the month following the end of each plan year. Employees purchase
shares through voluntary payroll deductions at a 15 percent discount from the
market value of the common stock, as defined in the plan. The weighted-average
fair value per share of purchase rights granted in 1998, 1997 and 1996 was
$5.94, $6.48 and $4.30, respectively.
OPTION SHARES
GRANTED
SHARES SUBJECT THROUGH EXPIRATION
PLAN NAME TO THE PLAN 12/31/98 VESTING PERIOD PERIOD
--------- -------------- ------------- -------------- ----------
1982 Plan 1,332,788 1,332,788 Immediate 10 years
1982 Directors' Plan 186,590 186,590 Three years 10 years
1986 Plan 618,750 618,750 Immediate 10 years
1988 Plan 618,750 618,750 Immediate 10 years
1992 Directors' Plan 525,000 241,875 Immediate 10 years
LTIP Plan 5,700,000 4,715,662 0 - 5 years 5 - 10 years
AOG Plan 775,500 775,500 Three years 10 years
Under all plans, except the LTIP 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 LTIP Plan options may be granted at less than 100 percent of the
market value of the stock at the date of grant. Certain restricted stock awards
include provisions accelerating the lapsing of restrictions in the event certain
operating goals are met.
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At December 31, 1998, 236 employees, officers and directors of the Company held
options under the plans. A summary of the status of the Company's stock option
plans at December 31, 1998, 1997 and 1996, and changes during the years then
ended is presented in the table and narrative below:
1998 1997 1996
---- ---- ----
WTD AVG WTD AVG WTD AVG
EXERCISE EXERCISE EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
--------- ------ --------- ------ --------- ------
OUTSTANDING AT BEGINNING
OF YEAR 3,220,065 $19.19 2,589,730 $18.52 1,746,765 $14.17
Granted 1,781,761 $31.40 1,128,603 $19.01 1,387,689 $21.07
Exercised (662,274) $16.46 (379,575) $14.11 (494,361) $10.59
Forfeited (121,361) $27.35 (118,693) $18.97 (50,363) $15.79
--------- ------ --------- ------ --------- ------
OUTSTANDING AT END OF YEAR 4,218,191 $24.38 3,220,065 $19.19 2,589,730 $18.52
========= ====== ========= ====== ========= ======
EXERCISABLE AT END OF YEAR 1,794,112 $25.11 1,343,123 $19.75 907,443 $16.35
========= ====== ========= ====== ========= ======
WEIGHTED-AVERAGE FAIR VALUE
OF OPTIONS GRANTED $ 12.08 $ 10.47 $ 6.35
========= ========= =========
The following table sets forth K N's December 31, 1998, 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 REMAINING WTD AVG
PRICE NUMBER EXERCISE CONTRACTUAL NUMBER EXERCISE
RANGE OUTSTANDING PRICE LIFE EXERCISABLE PRICE
----- ----------- -------- ----------- ----------- --------
$ 0.00 - $23.58 1,123,786 $ 9.35 5.82 years 498,961 $16.93
$23.79 - $30.65 1,627,759 $25.82 8.11 years 878,968 $25.41
$30.69 - $39.23 1,466,646 $34.31 9.33 years 416,183 $34.27
--------- ---------
4,218,191 $24.38 7.92 years 1,794,112 $25.11
========= =========
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: risk-free interest rate of 5.5 percent, expected weighted-average
lives of 4 years and expected volatility of .25 for grants in 1998, and .20 for
grants in 1997 and 1996; and expected dividend yields of 3.5 percent for grants
in 1998, and 2.5 percent for grants in 1997 and 1996.
12. COMMITMENTS AND CONTINGENT LIABILITIES
(A) Leases
The Company has entered into a number of operating leases, including those
referred to in Note 2.
61
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Expenses incurred under operating leases were $61.2 million in 1998, $33.0
million in 1997 and $22.3 million in 1996. Future minimum commitments under
major operating leases as of December 31, 1998, are as follows:
YEAR AMOUNT
- ---- ------
(In Thousands)
1999 $ 65,208
2000 68,928
2001 70,282
2002 86,045
2003 77,524
Thereafter 999,195
----------
Total $1,367,182
==========
Certain of the Company's operating lease arrangements provide that, in the event
that the rating of K N's senior debt is lowered below investment grade by both
of the two major rating agencies, the Company would be required to post letters
of credit in support of its remaining lease payments. Although the Company
currently has no information to indicate that such downgrades will occur, given
the Company's current level of borrowing and utilization of its letter of credit
facility, the posting of these additional letters of credit in support of lease
obligations would place the Company in default under the terms of its revolving
credit facility. The Company currently believes that, should such a default
occur, it could obtain a waiver of the applicable default provisions or
modification of such provisions to allow the facility to remain in place,
although the pricing would likely increase.
(B) Guarantees of Unconsolidated Subsidiaries' Debt
The Company has executed various guarantees of unconsolidated subsidiaries'
revolving credit agreements as follows:
MAXIMUM BORROWED FINAL
SUBSIDIARY AMOUNT AT 12/31/98 MATURITY
---------- ------- ----------- --------
(In Millions)
TransColorado $100 $80.0 10/13/01
Coyote Gas Treating, LLC $ 10 $ 9.1 12/31/99
Coyote Gas Treating, LLC $ 10 $ 8.0 06/30/00
Red Cedar $ 55 $55.0 10/31/10
Red Cedar $ 25 $ - 10/31/01
(C) Capital Expenditures Budget
The consolidated capital expenditures budget for 1999 totals $160 million.
Approximately $44.3 million had been committed for the purchase of plant and
equipment at December 31, 1998.
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13. FAIR VALUE
The following fair values of Investments, Long-Term Debt, Capital Securities and
K N Preferred Stock were estimated based on an evaluation made by an independent
securities analyst. Fair values of "Energy Financial Instruments, Net" reflect
the estimated amounts that the Company 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 used by the Company.
DECEMBER 31
1998 1997
--------------------------- ----------------------------
CARRYING FAIR CARRYING FAIR
VALUE VALUE VALUE VALUE
--------- --------- --------- ---------
(In Millions)
FINANCIAL ASSETS:
TBI Class A Preferred Stock $ 26.5 $ (i) $ 25.6 $ (i)
TBI Common Stock $ 9.2 $ 9.2 $ 17.7 $ 17.7
FINANCIAL LIABILITIES:
Long-Term Debt $ 3,315.9 $ 3,395.9 $ 585.5 $ 622.1
Capital Securities $ 275.0 $ 297.6 $ 100.0 $ 100.7
Energy Financial Instruments, Net $ 3.2 $ 3.2 $ 11.8 $ 11.8
K N Class A $5.00 Preferred Stock $ 7.0 $ 5.3 $ 7.0 $ 6.0
(i) Fair values for TBI Class A Preferred Stock are not readily available.
14. BUSINESS SEGMENT INFORMATION
K N Energy, Inc. has adopted a strategy of extracting profit from the energy
value stream which extends from the purchase or production of the fuel through
the sale of the energy to the end-user. Consistent with this strategy, K N
manages its business and has segregated its activities into three business
segments, "Upstream," "Midstream" and "Downstream," based on where in the value
stream such activities are conducted. In general, these segments are also
differentiated by the nature of their processes, their principal suppliers and
their target markets and customers. The Company's Upstream operations consist of
natural gas gathering, natural gas processing, and NGLs extraction and
marketing; Midstream operations consist of transportation, storage and bundled
sales transactions for K N's interstate and intrastate pipelines; Downstream
operations principally consist of energy marketing, regulated natural gas
distribution and electric power generation and sales.
The accounting policies applied in the generation of segment information are
generally the same as those described in Note 1 except that, in general, 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. In addition, certain items included in operating income (such as
the merger-related costs incurred in 1998) are not allocated to individual
business segments. With adjustment for these items, the Company currently
evaluates business segment performance primarily based on operating income in
relation to the level of capital employed. In general, intersegment sales are
accounted for at market prices, while asset transfers are made at either market
value or, in some instances, book value. For comparative purposes, prior period
results and balances have been reclassified to conform to the current
presentation.
63
64
\
BUSINESS SEGMENT INFORMATION
(Before Intersegment Eliminations)
YEAR ENDED DECEMBER 31, 1998
-----------------------------------------------------------------------------------
UPSTREAM MIDSTREAM DOWNSTREAM OTHER CONSOLIDATED
-------- --------- ---------- ----- ------------
(In Millions)
Revenues from External Customers $ 480.1 $1,195.9 $2,690.1 $4,366.1
Equity in Earnings of Equity-Method Investees $ 13.6 $ 10.3 $ (2.2) $ 21.7
Intersegment Revenues $ 111.1 $ 298.5 $ 113.4
Depreciation and Amortization $ 26.3 $ 155.0 $ 14.6 $ 195.9
Operating Income $ (18.4) $ 352.1 $ 16.7 $ (5.8) (1) $ 344.6
Segment Assets(2) $ 711.5 $6,549.5 $1,227.7 $ 1,123.5 (3) $9,612.2
Investment in Equity-Method Investees(2) $ 67.1 $ 65.6 $ 86.9 $ 219.6
Capital Expenditures $ 119.3 $ 112.9 $ 24.3 $ 256.5
MidCon Acquisition $ 57.7 $3,029.2 $ 524.1 $3,611.0
Other Acquisitions $ 8.4 $ 6.9 $ 155.2 $ 170.5
YEAR ENDED DECEMBER 31, 1997
-----------------------------------------------------------------------------------
UPSTREAM MIDSTREAM DOWNSTREAM OTHER CONSOLIDATED
-------- --------- ---------- ----- ------------
(In Millions)
Revenues from External Customers $ 468.4 $ 86.9 $1,589.7 $2,145.0
Equity in Earnings of Equity-Method Investees $ 0.8 $ 4.9 $ (1.8) $ 3.9
Intersegment Revenues $ 84.7 $ 139.3 $ 82.0
Depreciation and Amortization $ 16.9 $ 27.6 $ 11.5 $ 56.0
Operating Income $ 58.8 $ 45.5 $ 41.8 $ 146.1
Segment Assets(2) $ 616.3 $ 911.2 $ 745.0 33.3 (3) $2,305.8
Investment in Equity-Method Investees(2) $ 78.5 $ 11.5 $ 14.6 $ 104.6
Capital Expenditures $ 71.3 $ 212.8 $ 27.0 $ 311.1
Acquisitions $ 118.8 $ 1.4 $ 33.6 $ 153.8
YEAR ENDED DECEMBER 31, 1996
-----------------------------------------------------------------------------------
UPSTREAM MIDSTREAM DOWNSTREAM OTHER CONSOLIDATED
-------- --------- ---------- ----- ------------
(In Millions)
Revenues from External Customers $ 281.4 $ 150.0 $1,009.0 $1,440.4
Intersegment Revenues $ 76.1 $ 116.8 $ 155.4
Depreciation and Amortization $ 14.5 $ 24.9 $ 11.8 $ 51.2
Operating Income $ 38.6 $ 43.1 $ 53.1 $ 134.8
Segment Assets(2) $ 288.5 $ 828.3 $ 495.9 17.0 (3) $1,629.7
Investment in Equity-Method Investees(2) $ - $ 3.5 $ 0.7 $ 4.2
Capital Expenditures $ 18.1 $ 96.0 $ 5.9 $ 120.0
Acquisitions $ 61.8 $ 94.0 $ 0.1 $ 155.9
(1) Represents costs related to the MidCon Acquisition (see Note 2).
(2) Balances at December 31 for the year indicated.
(3) Other assets represent principally cash, restricted deposits and U.S.
government securities.
GEOGRAPHIC INFORMATION
All but an insignificant amount of the Company's assets and operations are
located in the continental United States.
64
65
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
K N ENERGY, INC. AND SUBSIDIARIES
QUARTERLY OPERATING RESULTS FOR 1998 AND 1997
1998
FIRST SECOND THIRD FOURTH
---------- ---------- ---------- ----------
(In Thousands Except Per Share Amounts)
Operating Revenues $1,166,522 $1,039,719 $1,045,051 $1,136,551
========== ========== ========== ==========
Operating Income $ 77,786 $ 92,090 $ 92,892 $ 81,783
========== ========== ========== ==========
Net Income (Loss) $ 22,508 $ 16,690 $ 24,474 $ (3,683)
Preferred Stock Dividends 88 87 88 87
---------- ---------- ---------- ----------
Earnings (Loss) Available for Common Stock $ 22,420 $ 16,603 $ 24,386 $ (3,770)
========== ========== ========== ==========
Number of Common Shares Used In
Computing Basic Earnings Per Share 52,635 67,170 67,493 68,442
========== ========== ========== ==========
Number of Common Shares Used In
Computing Diluted Earnings Per Share 53,429 67,986 67,991 68,823
========== ========== ========== ==========
Basic Earnings (Loss) Per Common Share $ 0.43 $ 0.25 $ 0.36 $ (0.06)
========== ========== ========== ==========
Diluted Earnings (Loss) Per Common Share $ 0.42 $ 0.24 $ 0.36 $ (0.05)
========== ========== ========== ==========
1997
FIRST SECOND THIRD FOURTH
---------- ---------- ---------- ----------
(In Thousands Except Per Share Amounts)
Operating Revenues $ 488,842 $ 358,752 $ 518,189 $ 783,198
========== ========== ========== ==========
Operating Income $ 39,537 $ 25,325 $ 34,683 $ 46,567
========== ========== ========== ==========
Net Income $ 20,358 $ 10,872 $ 17,808 $ 28,459
Preferred Stock Dividends 88 87 88 87
---------- ---------- ---------- ----------
Earnings Available for Common Stock $ 20,270 $ 10,785 $ 17,720 $ 28,372
========== ========== ========== ==========
Number of Common Shares Used In
Computing Basic Earnings Per Share 45,777 46,181 47,058 47,337
========== ========== ========== ==========
Number of Common Shares Used In
Computing Diluted Earnings Per Share 46,754 47,066 47,564 47,996
========== ========== ========== ==========
Basic Earnings Per Common Share $ 0.44 $ 0.23 $ 0.38 $ 0.60
========== ========== ========== ==========
Diluted Earnings Per Common Share $ 0.43 $ 0.23 $ 0.37 $ 0.59
========== ========== ========== ==========
65
66
PART III
ITEM 10: DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
(A) Identification of Directors
For information regarding the Directors, see the 1999 Proxy Statement.
(B) Identification of Executive Officers
See Executive Officers of the Registrant under Part I.
(C) Identification of Certain Significant Employees
None.
(D) Family Relationships
See "Election of Directors" Section of the 1999 Proxy Statement.
(E) Business Experience
See Executive Officers of the Registrant under Part I. For business
experience of the Directors, see the 1999 Proxy Statement.
(F) Involvement in Certain Legal Proceedings
None.
(G) Promoters and Control Persons
None.
ITEM 11: EXECUTIVE COMPENSATION
See "Director Compensation," "Report of the Compensation Committee on Executive
Compensation," "Executive Compensation," "Stock Options," "Performance Graph,"
"Pension and Supplemental Benefits" and "Severance and Other Agreements"
Sections in the 1999 Proxy Statement.
ITEM 12: SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
See the 1999 Proxy Statement Sections: (i) relating to common stock owned by
directors; (ii) "Executive Stock Ownership;" and (iii) "Principal Shareholders."
66
67
ITEM 13: CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
(A) Transactions with Management and Others
See "Relationship Between Certain Directors and the Company" section in the 1999
Proxy Statement.
(B) Certain Business Relationships
See "Relationship Between Certain Directors and the Company" section in the 1999
Proxy Statement.
(C) Indebtedness of Management
See "Relationship Between Certain Directors and the Company" section in the 1999
Proxy Statement.
(D) Transactions with Promoters
Not applicable.
67
68
PART IV
ITEM 14: EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) See the index for a listing and page numbers of financial statements and
exhibits included herein or incorporated by reference.
K N ENERGY, INC. AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
YEAR ENDED DECEMBER 31, 1998
--------------------------------------------------------------------------------------
ADDITIONS
-------------------------------
CHARGED TO DEDUCTIONS
BALANCE AT CHARGED TO OTHER ACCOUNTS WRITE-OFF OF
BEGINNING OF COST AND ACQUISITION OF UNCOLLECTIBLE BALANCE AT END
PERIOD EXPENSES MIDCON ACCOUNTS OF PERIOD
------------ ---------- -------------- ------------- --------------
(In Millions)
Allowance for Doubtful Accounts $1.7 $5.0 $5.8 $(1.7) $10.8
Note: Activity and balances prior to 1998 were not material.
68
69
Executive Compensation Plans and Arrangements
Form of Key Employee Severance Agreement (Exhibit 10.2, Amendment No. 1
on Form 8 dated September 2, 1988 to the Annual Report on Form 10-K for the year
ended December 31, 1987)*
1982 Stock Option Plan for Nonemployee Directors of the Company with
Form of Grant Certificate (Exhibit 10.3, Amendment No. 1 on Form 8 dated
September 2, 1988 to the Annual Report on Form 10-K for the year ended December
31, 1987)*
1982 Incentive Stock Option Plan for key employees of the Company
(Exhibit 10.4, Amendment No. 1 on Form 8 dated September 2, 1988 to the Annual
Report on Form 10-K for the year ended December 31, 1987)*
1986 Incentive Stock Option Plan for key employees of the Company
(Exhibit 10.5, Amendment No. 1 on Form 8 dated September 2, 1988 to the Annual
Report on Form 10-K for the year ended December 31, 1987)*
1988 Incentive Stock Option Plan for key employees of the Company
(Exhibit 10.6, Amendment No. 1 on Form 8 dated September 2, 1988 to the Annual
Report on Form 10-K for the year ended December 31, 1987)*
Form of Grant Certificate for Employee Stock Option Plans (Exhibit
10.7, Amendment No. 1 on Form 8 dated September 2, 1988 to the Annual Report on
Form 10-K for the year ended December 31, 1987)*
Directors' Deferred Compensation Plan Agreement (Exhibit 10.8,
Amendment No. 1 on Form 8 dated September 2, 1988 to the Annual Report on Form
10-K for the year ended December 31, 1987)*
1987 Directors' Deferred Fee Plan As Amended and Form of Participation
Agreement regarding the Plan (Exhibit 10(h) to the Annual Report on Form 10-K
for the year ended December 31, 1995)*
1992 Stock Option Plan for Nonemployee Directors of the Company with
Form of Grant Certificate (Exhibit 4.1, File No. 33-46999)*
1994 K N Energy, Inc. Long-Term Incentive Plan (Attachment A to the K N
Energy, Inc. 1994 Proxy Statement on Schedule 14-A)*
K N Energy, Inc. 1996 Executive Incentive Plan (Exhibit 10(l) to the
Annual Report on Form 10-K for the year ended December 31, 1995)*
K N Energy, Inc. Nonqualified Deferred Compensation Plan (Exhibit 10(m)
to the Annual Report on Form 10-K for the year ended December 31, 1994)*
K N Energy, Inc. Nonqualified Retirement Income Restoration Plan
(Exhibit 10(n) to the Annual Report on Form 10-K for the year ended December 31,
1994)*
K N Energy, Inc. Nonqualified Profit Sharing Restoration Plan (Exhibit
10(o) to the Annual Report on Form 10-K for the year ended December 31, 1994)*
Employment Agreement dated December 14, 1995 between K N Energy, Inc.
and Morton C. Aaronson (Exhibit 10(p) to the Annual Report on Form 10-K for the
year ended December 31, 1995)*
69
70
Letter Agreement dated December 4, 1995 between K N Energy, Inc. and
Charles W. Battey (Exhibit 10(q) to the Annual Report on Form 10-K for the year
ended December 31, 1995)*
K N Energy, Inc. Performance Incentive Plan (Exhibit 10(u) to the
Annual Report on Form 10-K for the year ended December 31, 1995)*
Form of Change of Control Severance Agreement (Exhibit 10(u) to the
Annual Report on Form 10-K for the year ended December 31, 1996)*
Form of Incentive Stock Option Agreement (Exhibit 10(v) to the Annual
Report on Form 10-K for the year ended December 31, 1996)*
Form of Restricted Stock Agreement (Exhibit 10(w) to the Annual Report
on Form 10-K for the year ended December 31, 1996)*
Employment Agreement dated March 21, 1996 between K N Energy, Inc. and
Murray R. Smith (Exhibit 10(x) to the Annual Report on Form 10-K for the year
ended December 31, 1996)*
Directors and Executives Deferred Compensation Plan effective January
1, 1998 for executive officers and directors of the Company (Attached hereto as
Exhibit 10(aa).
Management Deferred Compensation Plan effective January 1, 1998 for
senior management of the Company (Attached hereto as Exhibit 10(bb).
(b) Reports on Form 8-K
On October 7, 1998, a Current Report on Form 8-K/A was filed to present
an unaudited pro forma consolidated income statement for K N Energy, Inc. and
MidCon Corp. for the six months ended June 30, 1998 and related notes.
On October 9, 1998, a Current Report on Form 8-K was filed to present
selected historical segment information for the Company.
On November 24, 1998, a Current Report on Form 8-K was filed to report
the issuance on or about November 25, 1998, of 10,706,000 of the Company's 8.25%
Premium Equity Participating Security Units.
* Incorporated herein by reference.
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71
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.
K N ENERGY, INC.
(Registrant)
Date: March 9, 1999 By /s/ Clyde E. McKenzie
-----------------------------
Clyde E. McKenzie
Vice President and Chief
Financial Officer
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/ David W. Burkholder Director
- -----------------------------
David W. Burkholder
/s/ David M. Carmichael Director
- -----------------------------
David M. Carmichael
/s/ Robert H. Chitwood Director
- -----------------------------
Robert H. Chitwood
/s/ Howard P. Coghlan Director
- -----------------------------
Howard P. Coghlan
/s/ Jordan L. Haines Director
- -----------------------------
Jordan L. Haines
/s/ Larry D. Hall Chairman, Chief Executive Officer
- ----------------------------- and Director (Principal Executive Officer)
Larry D. Hall
/s/ William J. Hybl Director
- -----------------------------
William J. Hybl
/s/ Richard D. Kinder Director
- -----------------------------
Richard D. Kinder
/s/ Clyde E. McKenzie Vice President and Chief Financial Officer
- ----------------------------- (Principal Financial and Accounting Officer)
Clyde E. McKenzie
/s/ Edward Randall, III Director
- -----------------------------
Edward Randall, III
/s/ John F. Riordan Director
- -----------------------------
John F. Riordan
/s/ James C. Taylor Director
- -----------------------------
James C. Taylor
/s/ H. A. True, III Director
- -----------------------------
H. A. True, III
71
72
Exhibit Index
Page Number
-----------
List of Executive Compensation Plans and Arrangements 69-70
Exhibit 2(a) - Stock Purchase Agreement, dated December
18, 1997, between K N Energy, Inc. and Occidental
Petroleum Corporation (Exhibit 2.1, File No. 333-44421)*
Exhibit 2(b) - Amendment No.1 to Stock Purchase
Agreement, dated January 30,1998, between K N
Energy, Inc. and Occidental Petroleum Corporation
(Exhibit 2(b) to the Annual Report on Form 10-K
for the year ended December 31, 1997)*
Exhibit 2(c) - Agreement and Plan of Merger among
Sempra Energy, Cardinal Acquisition Corp. and the
Company dated as of February 20, 1999 (Exhibit
99.1 Current Report on Form 8-K Dated February
20, 1999)*
Exhibit 3(a) - Restated Articles of Incorporation
(Exhibit 3(a) to the Annual Report on Form 10-K
for the year ended December 31, 1994)*
Exhibit 3(b) - By-Laws of the Company, as amended
(Exhibit 3(b) to the Annual Report on From 10-K
for the year ended December 31, 1996)*
Exhibit 3(c) - By-Laws of the Company, as amended
on February 10, 1998 (Attached as Exhibit 3(c))**
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 1.2, Current Report on Form 8-K Dated October 5, 1988)*
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
1.2 Current Report on Form 8-K dated December 15, 1992)*
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 the Company and its subsidiaries have
not been furnished. The Company will furnish such
instruments to the Commission upon request.
Exhibit 4(e) - $600,000,000 364-Day Credit
Agreement among K N Energy, Inc., certain banks
listed therein and Morgan Guaranty Trust Company
of New York as Administrative Agent (Exhibit 4(e)
to the Annual Report on Form 10-K for the year
ended December 31, 1997)*
Exhibit 4(f) - $400,000,000 Five-Year Credit
Agreement 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(g) - $2,100,000,000 364 Day Credit
Agreement among K N Energy, Inc., certain banks
listed therein and Morgan Guaranty Trust Company
of New York as Administrative Agent (Exhibit 4(g)
to the Annual Report on Form 10-K for the year
ended December 31, 1997)*
Exhibit 4(h) - $1,394,846,122 Reimbursement Agreement
73
Exhibit Index
Page Number
-----------
among K N Energy, Inc., certain banks listed
therein and Morgan Guaranty Trust Company of New
York as Administrative Agent (Exhibit 4(e) to the
Annual Report on Form 10-K for the year ended
December 31, 1997)*
Exhibit 4(i) - Purchase Contract Agreement dated as
of November 25, 1998, between the Company and
U.S. Bank Trust National Association, as Purchase
Contract Agent for the PEPS Units (Exhibit 4.4
Current Report on Form 8-K Dated November 24,
1998)*
Exhibit 4(j) - Amendment No. 1 to Credit Agreements
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 (Attached hereto as Exhibit
4(j))**
Exhibit 4(k) - $600,000,000 364 Day-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 (Attached hereto as Exhibit
4(k)) **
Exhibit 4(l) - Amendment No. 2 to the $400,000,000
Five-Year Credit Agreement among K N Energy,
Inc., 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 (Attached hereto as Exhibit
4(l)) **
Exhibit 10(a) - Form of Key Employee Severance
Agreement (Exhibit 10.2, Amendment No. 1 on Form
8 dated September 2, 1988 to the Annual Report on
Form 10-K for the year ended December 31, 1987)*
Exhibit 10(b) - 1982 Stock Option Plan for Non-
employee Directors of the Company with Form of
Grant Certificate (Exhibit 10.3, Amendment No. 1
on Form 8 dated September 2, 1988 to the Annual
Report on Form 10-K for the year ended December
31, 1987)*
Exhibit 10(c) - 1982 Incentive Stock Option Plan
for key employees of the Company (Exhibit 10.4,
Amendment No. 1 on Form 8 dated September 2, 1988
to the Annual Report on Form 10-K for the year
ended December 31, 1987)*
Exhibit 10(d) - 1986 Incentive Stock Option Plan
for key employees of the Company (Exhibit 10.5,
Amendment No. 1 on Form 8 dated September 2, 1988
to the Annual Report on Form 10-K for the year
ended December 31, 1987)*
Exhibit 10(e) - 1988 Incentive Stock Option Plan
for key employees of the Company (Exhibit 10.6,
Amendment No. 1 on Form 8 dated September 2, 1988
to the Annual Report on Form 10-K for the year
ended December 31, 1987)*
Exhibit 10(f) - Form of Grant Certificate for
Employee Stock Option Plans (Exhibit 10.7,
Amendment No. 1 on Form 8 dated September 2, 1988
to the Annual Report on Form 10-K for the year
ended December 31, 1987)*
Exhibit 10(g) - Directors' Deferred Compensation
Plan Agreement (Exhibit 10.8, Amendment No. 1 on
Form 8 dated September 2, 1988 to the Annual
Report on Form 10-K for the year ended December
31, 1987)*
Exhibit 10(h) - 1987 Directors' Deferred Fee Plan As Amended
and Form
74
Exhibit Index
Page Number
-----------
of Participation Agreement regarding the Plan
(Exhibit 10(h) to the Annual Report on Form 10-K for the year ended
December 31, 1995)*
Exhibit 10(i) - 1992 Stock Option Plan for Nonemployee
Directors of the Company with Form of Grant Certificate
(Exhibit 4.1, File No. 33-46999)*
Exhibit 10(j) - 1994 K N Energy, Inc. Long-Term Incentive Plan
(Attachment A to the K N Energy, Inc. 1994 Proxy Statement
on Schedule 14-A)*
Exhibit 10(k) - K N Energy, Inc. 1996 Executive
Incentive Plan (Exhibit 10(l) to the Annual
Report on Form 10-K for the year ended
December 31, 1995)*
Exhibit 10(l) - K N Energy, Inc. Nonqualified
Deferred Compensation Plan (Exhibit 10(m) to the
Annual Report on Form 10-K for the year ended
December 31, 1994)*
Exhibit 10(m) - K N Energy, Inc. Nonqualified
Retirement Income Restoration Plan (Exhibit 10(n)
to the Annual Report on Form 10-K for the year
ended December 31, 1994)*
Exhibit 10(n) - K N Energy, Inc. Nonqualified Profit Sharing Restoration
Plan (Exhibit 10(o) to the Annual Report on Form
10-K for the year ended December 31, 1994)*
Exhibit 10(o) - Employment Agreement dated December 14, 1995
between K N Energy, Inc. and Morton C. Aaronson
(Exhibit 10(p) to the Annual Report on Form 10-K for the year ended
December 31, 1995)*
Exhibit 10(p) - Letter Agreement dated December 4,
1995 between K N Energy, Inc. and Charles W.
Battey (Exhibit 10(q) to the Annual Report on
Form 10-K for the year ended December 31, 1995)*
Exhibit 10(q) - Amended and Restated Basket
Agreement dated as of June 30, 1990, by and
between American Pipeline Company ("APC"), Cabot
and Cabot Transmission Corporation (Exhibit
10.5(a) to the Annual Report on Form 10-K for
American Oil and Gas Corporation ("AOG") for the
year ended December 31, 1993)*
Exhibit 10(r) - First Amendment to Amended and
Restated Omnibus Acquisition Agreement and
Amended and Restated Basket Agreement dated as of
March 31, 1992 by and among AOG, APC, Cabot and
Cabot Transmission (Exhibit 10.5(d) to the Annual
Report on Form 10-K for AOG for the year ended
December 31, 1993)*
Exhibit 10(s) - 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 10(t) - K N Energy, Inc. Performance
Incentive Plan (Exhibit 10(u) to the Annual
Report on Form 10-K for the year ended December
31, 1995)*
Exhibit 10(u) - Form of Change of Control Severance
Agreement (Exhibit 10(u) to the Annual Report on
Form 10-K for the year ended December 31, 1996)*
Exhibit 10(v) - Form of Incentive Stock Option
Agreement (Exhibit 10(v) to the Annual Report on
Form 10-K for the year ended December 31, 1996)*
Exhibit 10(w) - Form of Restricted Stock Agreement
(Exhibit 10(w) to the Annual Report on Form 10-K
for the year ended December 31, 1996)*
Exhibit 10(x) - Employment Agreement dated March 21, 1996
between K N Energy, Inc. and Murray R. Smith
75
Exhibit Index
Page Number
-----------
(Exhibit 10(x) to the Annual Report on Form 10-K for the year ended
December 31, 1996)*
Exhibit 10(y) - Intrastate Pipeline System Lease, dated December 31,
1996, between MidCon Texas Pipeline, L.P. and MidCon Texas
Pipeline Operator, Inc. (Exhibit 10(y) to the Annual Report on Form
10-K for the year ended December 31, 1997)*
Exhibit 10(z) - Amendment Number One To Intrastate Pipeline System
Lease, dated January 31, 1998, between MidCon Texas Pipeline, L.P.
and MidCon Texas Pipeline Operator, Inc. (Exhibit 10(z) to the Annual
Report on Form 10-K for the year ended December 31, 1997)*
Exhibit 10(aa) - Directors and Executives Deferred Compensation Plan
effective January 1, 1998 for executive officers and directors of the Company
(Attached hereto as Exhibit 10(aa)).**
Exhibit 10(bb) - Management Deferred Compensation Plan effective January 1, 1998
for senior management of the Company (Attached hereto as Exhibit 10(bb)).**
Exhibit 10(cc) - Amendment No. 1 to Rights Agreement between the Company
and the Bank of New York, as Rights Agent, dated as of September 8, 1998
(Attached hereto as Exhibit 10(cc)).**
Exhibit 12 - Ratio of Earnings to Fixed Charges 76
Exhibit 13 - 1998 Annual Report to Shareholders*** 77
Exhibit 21 - Subsidiaries of the Registrant 78-80
Exhibit 23 - Consent of Independent Public Accountants 81
Exhibit 27 - Financial Data Schedule****
* Incorporated herein by reference.
** Included in SEC and NYSE copies only.
*** Such report is being furnished for the information of the Securities and
Exchange Commission only and is not to be deemed filed as a part of this
annual report on Form 10-K.
**** Included in SEC copy only.