-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, GX8KV/e9It7/JWd0WmWKSDxIClFmvQ+siqJ+FdZqmvfblXKqQOPNES92Wx6hGWhJ BVURgec/1fBzTbsgF+ZNIQ== 0000950129-02-000818.txt : 20020414 0000950129-02-000818.hdr.sgml : 20020414 ACCESSION NUMBER: 0000950129-02-000818 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 7 CONFORMED PERIOD OF REPORT: 20011231 FILED AS OF DATE: 20020220 FILER: COMPANY DATA: COMPANY CONFORMED NAME: KINDER MORGAN INC CENTRAL INDEX KEY: 0000054502 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS TRANSMISSION & DISTRIBUTION [4923] IRS NUMBER: 480290000 STATE OF INCORPORATION: KS FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: 1934 Act SEC FILE NUMBER: 001-06446 FILM NUMBER: 02553968 BUSINESS ADDRESS: STREET 1: 500 DALLAS STREET 2: SUITE 1000 CITY: HOUSTON STATE: TX ZIP: 77002 BUSINESS PHONE: 3039144752 MAIL ADDRESS: STREET 1: 500 DALLAS STREET 2: SUITE 1000 CITY: HUSTON STATE: TX ZIP: 77002 FORMER COMPANY: FORMER CONFORMED NAME: KN ENERGY INC DATE OF NAME CHANGE: 19920430 FORMER COMPANY: FORMER CONFORMED NAME: K N ENERGY INC DATE OF NAME CHANGE: 19920703 FORMER COMPANY: FORMER CONFORMED NAME: KANSAS NEBRASKA NATURAL GAS CO INC DATE OF NAME CHANGE: 19830403 10-K405 1 h94310e10-k405.txt KINDER MORGAN, INC. - 12/31/2001 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, DC 20549 FORM 10-K [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NUMBER 1-6446 KINDER MORGAN, INC. (Exact name of registrant as specified in its charter) KANSAS 48-0290000 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 500 DALLAS, SUITE 1000, HOUSTON, TEXAS 77002 (Address of principal executive offices) (Zip Code)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE (713) 369-9000 SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT: NAME OF EACH EXCHANGE TITLE OF EACH CLASS ON WHICH REGISTERED Common stock, par value $5 per share New York Stock Exchange Preferred share purchase rights New York Stock Exchange Exchange feature of Kinder Morgan New York Stock Exchange Management, LLC shares Purchase obligation of Kinder Morgan New York Stock Exchange Management, LLC shares
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: PREFERRED STOCK, CLASS A $5 CUMULATIVE SERIES (Title of class) Indicate by check 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 [ ] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] The aggregate market value of the voting stock held by non-affiliates of the registrant was $4,794,480,772 as of January 31, 2002. The number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date was: Common stock, $5 par value; authorized 150,000,000 shares; outstanding 123,596,043 shares as of February 1, 2002. DOCUMENTS INCORPORATED BY REFERENCE Part III of this report incorporates by reference specific portions of the Registrant's Proxy Statement relating to the 2002 Annual Meeting of Stockholders. - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- KINDER MORGAN, INC. AND SUBSIDIARIES CONTENTS
PAGE NUMBER ------ PART I Items 1 and 2. Business and Properties..................................... 3-13 Overview.................................................... 4 Natural Gas Pipeline Company of America..................... 5 Kinder Morgan Retail........................................ 7 Power and Other............................................. 8 Regulation.................................................. 9 Environmental Regulation.................................... 11 Risk Factors................................................ 12 Item 3. Legal Proceedings........................................... 13-15 Item 4. Submission of Matters to a Vote of Security Holders......... 16 Executive Officers of the Registrant........................ 16-18 PART II Item 5. Market for Registrant's Equity and Related Security Holder Matters................................................... 18 Item 6. Selected Financial Data..................................... 19-20 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations................................. 21-44 General..................................................... 21 Critical Accounting Policies and Estimates.................. 22 Consolidated Financial Results.............................. 24 Results of Operations....................................... 25 Natural Gas Pipeline Company of America..................... 26 Kinder Morgan Retail........................................ 28 Power and Other............................................. 29 Kinder Morgan Texas Pipeline................................ 30 Kinder Morgan Interstate Gas Transmission................... 31 Other Income and (Expenses)................................. 31 Income Taxes -- Continuing Operations....................... 32 Discontinued Operations..................................... 32 Liquidity and Capital Resources............................. 33 Cash Flows.................................................. 35 Litigation and Environmental................................ 39 Regulation.................................................. 39 Risk Management............................................. 39 Recent Accounting Pronouncements............................ 42 Item 7A. Quantitative and Qualitative Disclosures About Market Risk...................................................... 44 Item 8. Financial Statements and Supplementary Data................. 45-93 Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.................................. 94
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PAGE NUMBER ------ PART III Item 10. Directors and Executive Officers of the Registrant.......... 94 Item 11. Executive Compensation...................................... 94 Item 12. Security Ownership of Certain Beneficial Owners and Management................................................ 94 Item 13. Certain Relationships and Related Transactions.............. 94 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K....................................................... 94-98 Signatures.................................................................. 99
- --------------- Note: Individual financial statements of the parent company are omitted pursuant to the provisions of Accounting Series Release No. 302. 2 PART I ITEMS 1. AND 2. BUSINESS AND PROPERTIES. In this report, unless the context requires otherwise, references to "we," "us," "our," or the "Company" are intended to mean Kinder Morgan, Inc. (a Kansas corporation, incorporated on May 18, 1927, formerly known as K N Energy, Inc.) and its consolidated subsidiaries. All volumes of natural gas are stated at a pressure base of 14.73 pounds per square inch absolute and at 60 degrees Fahrenheit and, in most instances, are rounded to the nearest major multiple. In this report, the term "MMcf" means million cubic feet, the term "Bcf" means billion cubic feet and the term "MMBtus" means million British Thermal Units ("Btus"). Natural gas liquids consist of ethane, propane, butane, iso-butane and natural gasoline. (A) GENERAL DEVELOPMENT OF BUSINESS We are one of the largest energy storage and transportation companies in the United States, operating, either for ourselves or on behalf of Kinder Morgan Energy Partners, L.P., more than 30,000 miles of natural gas and products pipelines. We own and operate Natural Gas Pipeline Company of America, a major interstate natural gas pipeline system with approximately 10,000 miles of pipelines and associated storage facilities. We own and operate a retail natural gas distribution business serving approximately 233,000 customers in Colorado, Nebraska and Wyoming. We construct, operate and, in some cases, own natural gas-fired electric generation facilities. These businesses are discussed in detail in the next section of this report. Our common stock is traded on the New York Stock Exchange under the symbol "KMI." Our executive offices are located at 500 Dallas, Suite 1000, Houston Texas 77002 and our telephone number is (713) 369-9000. In addition to the businesses described above, we own the general partner of, and a significant limited partner interest in, Kinder Morgan Energy Partners, the largest publicly traded limited partnership in the pipeline industry in terms of market capitalization and the second largest products pipeline system in the United States in terms of volumes delivered. Kinder Morgan Energy Partners also owns and/or operates a diverse group of assets used in the transportation, storage and processing of energy products, including refined petroleum products pipeline systems with more than 10,000 miles of pipeline and over 32 associated terminals. Kinder Morgan Energy Partners owns 10,000 miles of natural gas transportation pipelines and natural gas gathering and storage facilities. Kinder Morgan Energy Partners also owns or operates 33 dry bulk terminal facilities that transfer approximately 55 million tons of coal, petroleum coke and other products annually and owns 11 liquids terminals with storage capacity for up to 35 million barrels of refined petroleum products and chemicals. In addition, Kinder Morgan Energy Partners owns 51% of, and operates, Plantation Pipeline Company and owns 100% of Kinder Morgan CO(2) Company, L.P., formerly Shell CO(2) Company, Ltd. On December 17, 2001, Kinder Morgan Energy Partners announced that it had entered into a definitive agreement to acquire Tejas Gas, LLC for approximately $750 million in cash. Tejas Gas owns and operates a 3,400-mile intrastate natural gas pipeline system in the Texas Gulf Coast area. Additional information concerning the business of Kinder Morgan Energy Partners is contained in Kinder Morgan Energy Partners' 2001 Annual Report on Form 10-K. In May 2001, Kinder Morgan Management, LLC, one of our indirect subsidiaries, issued and sold shares in an underwritten initial public offering. The net proceeds from the offering were used by Kinder Morgan Management to buy i-units from Kinder Morgan Energy Partners for $991.9 million. Upon purchase of the i-units, Kinder Morgan Management became a partner in Kinder Morgan Energy Partners and was delegated by Kinder Morgan Energy Partners' general partner the responsibility to manage and control Kinder Morgan Energy Partners' business and affairs. The i-units are a class of Kinder Morgan Energy Partners' limited partner interests and have been, and will be, issued only to Kinder Morgan Management. In the initial public offering, 10 percent of Kinder Morgan Management's shares were purchased by us, with the balance purchased by the public. The equity interest in Kinder Morgan Management (which 3 is consolidated in our financial statements) purchased by the public created an additional minority interest on our balance sheet of $892.7 million at the time of the transaction. The earnings recorded by Kinder Morgan Management that are attributable to its shares held by the public are reported as "minority interest" in our consolidated statements of operations. We have certain rights and obligations with respect to these securities, including an obligation to purchase the Kinder Morgan Management shares or exchange them for Kinder Morgan Energy Partners, L.P.'s common units that we own or for cash. Additional information concerning the business of, and our obligations to, Kinder Morgan Management is contained in Kinder Morgan Management's 2001 Annual Report on Form 10-K. As of December 31, 2001, we owned, directly, and indirectly in the form of i-units corresponding to the number of shares of Kinder Morgan Management, LLC, we own, approximately 31.1 million limited partner units of Kinder Morgan Energy Partners, representing approximately 18.7% of its total outstanding units. We receive quarterly distributions on the i-units in additional i-units and distributions on our other units in cash. We reflect our investment in Kinder Morgan Energy Partners under the equity method of accounting and, accordingly, report our share of Kinder Morgan Energy Partners' earnings as "Equity in Earnings" in our Consolidated Statement of Operations in the period in which such earnings are reported by Kinder Morgan Energy Partners. In addition to distributions received on our limited partner interests as discussed above, we also receive an incentive distribution from Kinder Morgan Energy Partners as a result of our ownership of the general partner interest in Kinder Morgan Energy Partners. This incentive distribution is calculated in increments based on the amount by which quarterly distributions to unit holders exceed specified target levels as set forth in Kinder Morgan Energy Partners' partnership agreement, reaching a maximum of 50% of distributions allocated to the general partner for distributions above $0.23375 per limited partner unit. Including both our general and limited partner interests in Kinder Morgan Energy Partners, at the current level of distributions, we currently are entitled to receive approximately 50% of all quarterly distributions from Kinder Morgan Energy Partners, of which approximately 38% is attributable to our general partner interest and 12% is attributable to our limited partner interest. The actual level of distributions we will receive in the future will vary with the level of distributable cash determined in accordance with Kinder Morgan Energy Partners' partnership agreement. On October 7, 1999, we completed the acquisition of Kinder Morgan (Delaware), Inc., a Delaware corporation and the sole stockholder of the general partner of Kinder Morgan Energy Partners. To effect that acquisition, we issued approximately 41.5 million shares of our common stock in exchange for all of the outstanding shares of Kinder Morgan (Delaware). Upon closing of the transaction, Richard D. Kinder, Chairman and Chief Executive Officer of Kinder Morgan (Delaware), was named Chairman and Chief Executive Officer, and we were renamed Kinder Morgan, Inc. (B) FINANCIAL INFORMATION ABOUT SEGMENTS Note 21 of the accompanying Notes to Consolidated Financial Statements contains financial information about our business segments. (C) NARRATIVE DESCRIPTION OF BUSINESS OVERVIEW We are an energy and related services provider. Our principal business segments are: (1) Natural Gas Pipeline Company of America (NGPL) and affiliated companies, a major interstate natural gas pipeline and storage system, (2) Kinder Morgan Retail, the regulated sale of natural gas to residential, commercial and industrial customers and non-utility sales of natural gas to certain utility customers under the Choice Gas Program, a program that allows utility customers to choose their natural gas provider, and (3) Power and Other, the construction and operation of natural gas-fired electric generation facilities, together with various other activities not constituting separately managed or reportable business segments. Natural gas transportation, sales and storage accounted for approximately 90%, 96% and 95% of our consolidated revenues in 2001, 2000 and 1999, respectively. The operations of Kinder Morgan Energy Partners, a 4 significant master limited partnership equity-method investee in which we hold the general partner interest, include (i) liquids and refined products pipelines, (ii) transportation and storage of natural gas, (iii) carbon dioxide production and transportation and (iv) bulk and liquids terminals. Our equity in the earnings of Kinder Morgan Energy Partners, net of the associated amortization, constituted approximately 40%, 21% and 2% of our income from continuing operations before interest and income taxes in 2001, 2000 and 1999, respectively. As described in "Management's Discussion and Analysis of Financial Condition and Results of Operations", at December 31, 1999 and 2000, we transferred certain assets to Kinder Morgan Energy Partners. In 1999, we discontinued our wholesale natural gas marketing, non-energy retail marketing services and natural gas gathering and processing businesses. Notes 6 and 21 of the accompanying Notes to Consolidated Financial Statements contain additional information on asset sales and our business segments. As discussed following, certain of our operations are regulated by various federal and state entities. NATURAL GAS PIPELINE COMPANY OF AMERICA During 2001, Natural Gas Pipeline Company of America's segment earnings of $346.6 million represented approximately 56% of Kinder Morgan, Inc.'s income before interest and income taxes. Through Natural Gas Pipeline Company of America we own and operate approximately 10,000 miles of interstate natural gas pipelines, field system lines and related facilities, consisting primarily of two major interconnected transmission pipelines terminating in the Chicago metropolitan area. The system is powered by 62 compressor stations in mainline and storage service having an aggregate of approximately 1.0 million horsepower. Natural Gas Pipeline Company of America's system has over 1,700 points of interconnection with 32 interstate pipelines, 19 intrastate pipelines, a number of gathering systems, and over 60 local distribution companies and other end users, thereby providing significant flexibility in the receipt and delivery of natural gas. Natural Gas Pipeline Company of America's Amarillo Line originates in the West Texas and New Mexico producing areas and is comprised of approximately 3,900 miles of mainline and various small-diameter pipelines. The other major pipeline, the Gulf Coast Line, originates in the Gulf Coast areas of Texas and Louisiana and consists of approximately 4,400 miles of mainline and various small-diameter pipelines. These two main pipelines are connected at points in Texas and Oklahoma by Natural Gas Pipeline Company of America's 700-mile Amarillo/Gulf Coast pipeline. Natural Gas Pipeline Company of America provides transportation and storage services to third-party natural gas distribution utilities, marketers, producers, industrial end users and other shippers. Pursuant to transportation agreements and Federal Energy Regulatory Commission tariff provisions, Natural Gas Pipeline Company of America offers its customers firm and interruptible transportation, storage, park-and-loan and no-notice services. Under Natural Gas Pipeline Company of America's tariffs, firm transportation customers pay reservation charges each month plus a commodity charge based on actual volumes transported. Interruptible transportation customers pay a commodity charge based upon actual volumes transported. Reservation and commodity charges are both based upon geographical location and time of year. Under no-notice service, customers pay a reservation charge for the right to have up to a specified volume of natural gas delivered but, unlike with firm transportation service, are able to meet their peaking requirements without making specific nominations. Natural Gas Pipeline Company of America has the authority to negotiate rates with customers as long as it has first offered service under its reservation and commodity charge rate structure. Natural Gas Pipeline Company of America's revenues have historically been higher in the first and fourth quarters of the year, reflecting higher system utilization during the colder months. During the winter months, Natural Gas Pipeline Company of America collects higher transportation commodity revenue, higher interruptible transportation revenue, winter-only capacity revenue and higher peak rates on certain contracts. Natural Gas Pipeline Company of America's principal delivery market area encompasses the states of Illinois, Indiana and Iowa and secondary markets in portions of Wisconsin, Nebraska, Kansas, Missouri and Arkansas. Natural Gas Pipeline Company of America is the largest transporter of natural gas to the Chicago market and we believe that its cost of service is one of the most competitive in the region. In 2001, Natural Gas Pipeline Company of America delivered an average of 1.67 trillion Btus per day of natural gas to this market. Given its strategic location at the center of the North American pipeline grid, 5 we believe that Chicago is likely to continue to be a major natural gas trading hub for the rapidly growing markets in the Midwest and Northeast. Substantially all of Natural Gas Pipeline Company of America's pipeline capacity is committed under firm transportation contracts ranging from one to five years. Approximately 71% of the total transportation volume committed under Natural Gas Pipeline Company of America's long-term firm transportation contracts in effect on January 1, 2002 had remaining terms of less than three years. Natural Gas Pipeline Company of America continues to actively pursue the renegotiation, extension and/or replacement of expiring contracts. Nicor Gas and Peoples Energy are Natural Gas Pipeline Company of America's two largest customers. Contracts representing 28% of Natural Gas Pipeline Company of America's total long-term contracted firm transport capacity as of January 1, 2002 are scheduled to expire during 2002. Natural Gas Pipeline Company of America is one of the nation's largest natural gas storage operators with approximately 600 Bcf of total natural gas storage capacity, 215 Bcf of working gas capacity and up to 4.0 Bcf per day of peak deliverability from its storage facilities, which are located near the markets it serves. Natural Gas Pipeline Company of America owns and operates eight underground storage fields in four states. These storage assets complement its pipeline facilities and allow it to optimize pipeline deliveries and meet peak delivery requirements in its principal markets. Natural Gas Pipeline Company of America provides firm and interruptible gas storage service pursuant to storage agreements and tariffs. Firm storage customers pay a monthly demand charge irrespective of actual volumes stored. Interruptible storage customers pay a monthly charge based upon actual volumes of gas stored. Natural Gas Pipeline Company of America is a 50% joint venturer in the Horizon Pipeline Company. Nicor-Horizon, a subsidiary of Nicor Inc. (NYSE: GAS) is the other joint venturer. The Horizon Pipeline Company will lease 46 miles of existing pipeline from Natural Gas Pipeline Company of America that it will combine with 27 miles of 36-inch pipeline that it is currently constructing at an estimated cost of $79 million. These combined facilities will allow Horizon Pipeline Company to transport 380 MMcf of natural gas per day from near Joliet into McHenry County in Illinois, connecting the emerging supply hub at Joliet with the northern part of the Nicor Gas distribution system and an existing Natural Gas Pipeline Company of America pipeline. Horizon Pipeline Company's pipeline system, expected to be completed in the summer of 2002, will be operated by Natural Gas Pipeline Company of America. Natural Gas Pipeline Company of America is currently constructing a lateral extension of its pipeline system from Centralia, Illinois into the metropolitan east area of St. Louis. This lateral will consist of approximately 50 miles of 24-inch pipeline with an initial capacity of approximately 300,000 MMBtus per day. We expect to place these facilities into service early in the third quarter of 2002 at an estimated cost of $36.4 million. Competition: Natural Gas Pipeline Company of America competes with other transporters of natural gas in virtually all of the markets it serves and, in particular, in the Chicago area, which is the northern terminus of Natural Gas Pipeline Company of America's two major pipeline segments and its largest market. These competitors include both interstate and intrastate natural gas pipelines and, historically, most of the competition has been from such pipelines with supplies originating in the United States. In recent periods, Natural Gas Pipeline Company of America has also faced competition from additional pipelines carrying Canadian produced natural gas into the Chicago market. The most recent example is the Alliance Pipeline, which began service during the 2000-2001 heating season. The additional pipeline capacity into the Chicago market has increased competition for transportation into the area while, at the same time, new pipelines, such as Vector Pipeline, have been or are expected to be constructed for the specific purpose of transporting gas from the Chicago area to other markets, generally further north and further east. The overall impact of the increased pipeline capacity into the Chicago area combined with additional take-away capacity and the increased demand in the area has created a situation that remains dynamic with respect to the ultimate impact on individual transporters such as Natural Gas Pipeline Company of America. Natural Gas Pipeline Company of America also faces competition with respect to the natural gas storage services it provides. Natural Gas Pipeline Company of America has storage facilities in both 6 market and supply areas, allowing it to offer varied storage services to customers. It faces competition from independent storage providers as well as storage services offered by other natural gas pipelines and local natural gas distribution companies. The competition faced by Natural Gas Pipeline Company of America with respect to its natural gas transportation and storage services is generally price-based, although there is also a significant component related to the variety, flexibility and the perceived reliability of services offered. Natural Gas Pipeline Company of America's extensive pipeline system, with access to diverse supply basins and significant storage assets in both the supply and market areas, gives it a competitive advantage in some situations but, typically, customers still have alternative sources for their requirements. In addition, due to the price-based nature of much of the competition faced by Natural Gas Pipeline Company of America, its proven ability to be a low-cost provider is an important factor in its success in acquiring and retaining customers. Additional competition for storage services could result from the utilization of currently underutilized storage facilities or from conversion of existing storage facilities from one use to another. In addition, competitive existing storage facilities could, in some instances, be expanded. KINDER MORGAN RETAIL During 2001, Kinder Morgan Retail's segment earnings of $56.4 million represented approximately 9% of Kinder Morgan, Inc.'s income before interest and income taxes. As of December 31, 2001, through Kinder Morgan Retail, our retail natural gas distribution business served approximately 233,000 customers in Colorado, Nebraska and Wyoming through approximately 8,600 miles of distribution pipelines. Our intrastate pipelines, distribution facilities and retail natural gas sales in Colorado and Wyoming are subject to the regulatory authority of each state's utility commission. In Nebraska, retail natural gas sales rates for residential and small commercial customers are regulated by each municipality served. Kinder Morgan Retail's operations in Nebraska, Wyoming and northeastern Colorado serve areas that are primarily rural and agricultural where natural gas is used primarily for space heating, crop irrigation, grain drying and processing of agricultural products. In much of Nebraska, the winter heating load is balanced by irrigation requirements in the summer and grain drying requirements in the fall. Kinder Morgan Retail's operations in western Colorado serve fast-growing resort and associated service areas, and rural communities. These areas are characterized primarily by natural gas use for space heating, with historical annual growth rates of 6-8%. Kinder Morgan Retail operations include non-jurisdictional products and services including the sale of commodity natural gas in Kinder Morgan Retail's Choice Gas programs and natural gas-related equipment and services. To support Kinder Morgan Retail's business, underground storage facilities are used to provide natural gas for load balancing and peak system demand. Storage services for Kinder Morgan Retail's natural gas distribution services are provided by three facilities in Wyoming and one facility in Colorado, all of which are owned by wholly owned subsidiaries of Kinder Morgan, Inc., and one facility located in Nebraska and owned by Kinder Morgan Energy Partners. The peak natural gas withdrawal capacity available for Kinder Morgan Retail's business is approximately 82 MMcf per day. Kinder Morgan Retail's natural gas distribution business relies on both the intrastate pipelines it operates and third-party pipelines for transportation and storage services required to serve its markets. The natural gas supply requirements for Kinder Morgan Retail's natural gas distribution business are met through contract purchases from third-party suppliers. Through Rocky Mountain Natural Gas Company in Colorado and Northern Gas Company in Wyoming, Kinder Morgan Retail provides transportation services to affiliated local distribution companies as well as natural gas producers, shippers and industrial customers. These two intrastate pipeline systems include approximately 1,500 miles of transmission lines, field system lines and related facilities. Through Northern Gas Company, Kinder Morgan Retail provides storage services in Wyoming to its customers from its three storage fields, Oil Springs, Bunker Hill and Kirk Ranch, which combined have 29.7 Bcf of total storage capacity, 11.7 Bcf of working gas capacity, and up to 37 MMcf per day of peak withdrawal capacity. Rocky Mountain Natural Gas Company operates the Wolf Creek storage facility, which has 7 10.1 Bcf of total storage capacity, 2.7 Bcf of working gas capacity and provides 15 MMcf per day of withdrawal capacity for peak day use by its sales customers in Colorado. Effective November 30, 2001, we purchased natural gas distribution assets from Citizens Communications Company (NYSE: CZN) for approximately $11 million. The natural gas distribution assets serve approximately 13,400 residential, commercial and agricultural customers in Bent, Crowley, Otero, Archuleta, La Plata and Mineral Counties in Colorado. This transaction was approved by the Colorado Public Utilities Commission on October 31, 2001. Competition: The Kinder Morgan Retail natural gas distribution business segment operates in areas with varying service area rules, including state utility commission exclusively certificated service areas, non-exclusive municipal franchises and competitive areas. Limited competitive natural gas distribution pipelines exist within these service areas. The primary competition for Kinder Morgan Retail's products is from alternative fuels such as electric power and propane for heating use, and electric power, propane and diesel fuel for agriculture use. Kinder Morgan Retail provides natural gas utility delivery services based upon cost-of-service regulation in most of its service areas. Kinder Morgan Retail currently has unbundled the regulated commodity natural gas supply in Nebraska and eastern Wyoming under Choice Gas Programs, and on April 20, 2001, filed an application with the Wyoming Public Service Commission to expand Choice Gas to cover all of its Wyoming customers. A Stipulation and Agreement calling for approval of the application to expand Choice Gas has been presented to the Wyoming Public Service Commission for its consideration. The Choice Gas Program allows competitive commodity natural gas providers to sell natural gas to approximately half of its total customers at present, which will increase to approximately two thirds of its customers if its pending application to expand the program in Wyoming is approved. In the unbundled areas, Kinder Morgan Retail competes as one of five natural gas marketing companies to provide the customer with natural gas commodity offerings. Kinder Morgan Retail currently provides the commodity product for 66% of the end use customers in the unbundled areas. POWER AND OTHER During 2001, Power and Other's segment earnings of $63.3 million represented approximately 10% of Kinder Morgan, Inc.'s income before interest and income taxes. Kinder Morgan Power designs, develops and constructs power projects and operates electric generation facilities as an independent power producer. Kinder Morgan Power is, primarily, a fee-for-service business that seeks to develop power projects for the benefit of long-term, off-take customers. These customers take the commodity benefits and risks in the marketplace and pay Kinder Morgan Power a fee for developing and constructing and, in some cases, operating these facilities. Kinder Morgan Power takes limited commodity price risk, as described below. Kinder Morgan Power's customers include power marketers, power generation companies and utilities. In 1998, Kinder Morgan Power acquired interests in the Thermo Companies, which provided us with our first electric generation assets as well as knowledge and expertise with General Electric Company jet engines (LMs) configured in a combined cycle mode. Through the Thermo Companies, Kinder Morgan Power has interests in three independent natural gas-fired LM projects in Colorado with an aggregate of 380 megawatts of electric generation capacity. Kinder Morgan Power used the LM knowledge to develop its proprietary "Orion" technology, which is now being deployed into various power markets. Kinder Morgan Power has natural gas price risk at the Colorado power facilities, which it manages through a combination of fixed-price supply contracts, hedges, and short-term or floating price contracts. In May 2000, Kinder Morgan Power and Mirant Corporation (formerly Southern Energy Inc.) announced plans to build a 550 megawatt natural gas-fired electric power plant southeast of Little Rock, Arkansas, utilizing Kinder Morgan Power's Orion technology. Mirant will operate the plant, manage the natural gas supply and power sales for the project company that owns the power plant, in which project company Kinder Morgan Power has a preferred investment. Natural gas transportation service for the plant will be provided by Natural Gas Pipeline Company of America. Construction is in process on the 8 facility, for which Kinder Morgan Power is the general contractor. Completion of construction is expected by June 2002. On February 20, 2001, Kinder Morgan Power announced an agreement under which Williams Energy Marketing and Trading agreed to supply natural gas to and market capacity for 16 years for up to six 550 megawatt natural gas-fired Orion technology electric power plants. The first of the planned six facilities is currently under construction in Jackson, Michigan. Williams will supply all natural gas to and purchase all power from the power plant under a 16-year tolling agreement with a project company in which Kinder Morgan Power will have a preferred investment. Kinder Morgan Power is the general contractor for the Jackson power plant and will operate the plant, which is expected to begin commercial operation in July 2002. Sites for the remainder of the six plants must be mutually agreed upon between Kinder Morgan Power and Williams. One additional site has been agreed upon, but commencement of construction is subject to permits that have not yet been obtained. No assurance can be given that Kinder Morgan Power and Williams will agree on additional sites or that necessary permits will be obtained for additional power plants beyond the initial plant already under construction in Jackson, Michigan. Competition: Kinder Morgan Power's competitors are other companies that develop power projects. This competition takes the form of competing for a limited number of potential projects and sites and can be based on pricing, length of construction period or other terms and conditions. With respect to the power facilities Kinder Morgan Power owns, the output is currently sold under "qualifying facilities" arrangements with the local utilities. For the power plants we develop for others, we are not responsible for purchasing the fuel or marketing the power being generated. Utilities and power marketers are the customers of power developers. Kinder Morgan Power has developed a proprietary "Orion" design that is targeted for a niche application in the intermediate electric power market. Currently, other technologies are used for the majority of the natural gas-fired power plants being developed. REGULATION INTERSTATE TRANSPORTATION AND STORAGE SERVICES Under the Natural Gas Act and, to a lesser extent, the Natural Gas Policy Act, the Federal Energy Regulatory Commission regulates both the performance of interstate transportation and storage services by interstate natural gas pipeline companies, and the rates charged for such services. As used in this report, FERC refers to the Federal Energy Regulatory Commission. With the adoption of FERC Order No. 636, the FERC required interstate natural gas pipelines that perform open access transportation under blanket certificates to "unbundle" or separate their traditional merchant sales services from their transportation and storage services and to provide comparable transportation and storage services with respect to all natural gas supplies, whether such natural gas is purchased from the pipeline or from other merchants such as marketers or producers. Each interstate natural gas pipeline must now separately state the applicable rates for each unbundled service. Order 636 has been affirmed in all material respects upon judicial review and Natural Gas Pipeline Company of America's own FERC orders approving its unbundling plans are final and not subject to any pending judicial review. Natural Gas Pipeline Company of America had a number of gas purchase contracts that required Natural Gas Pipeline Company of America to purchase natural gas at prices in excess of the prevailing market price. As a result of Order 636 prohibiting interstate natural gas pipelines from using their natural gas transportation and storage facilities to market natural gas to sales customers, Natural Gas Pipeline Company of America lost its sales market for the gas it was required to purchase under these contracts. Order 636 went into effect on Natural Gas Pipeline Company of America's system on December 1, 1993. Natural Gas Pipeline Company of America agreed to pay substantial transition costs to reform these contracts with the natural gas suppliers. Under settlement agreements between Natural Gas Pipeline Company of America and its former sales customers, Natural Gas Pipeline Company of America recovered from these customers a significant amount of the natural gas supply realignment costs over a four-year period beginning December 1, 1993. These settlement agreements were approved by the FERC. 9 The FERC also permitted Natural Gas Pipeline Company of America to implement a tariff mechanism to recover additional portions of its natural gas supply realignment costs in rates charged to transportation customers that were not party to the settlements. On December 1, 1997, the FERC allowed recovery of natural gas supply realignment costs initially allocated to interruptible transportation but not recovered. Effective December 1, 1998, the FERC allowed Natural Gas Pipeline Company of America to recover its remaining natural gas supply realignment costs over the period from December 1, 1998 through November 30, 2001. On October 22, 2001, in Docket No. RP02-22, Natural Gas Pipeline Company of America filed revised tariff sheets eliminating the surcharges for natural gas supply realignment costs applicable to its services. On November 28, 2001, the FERC accepted the revised tariff sheets effective December 1, 2001, as proposed. We are also subject to the requirements of FERC Order Nos. 497, et seq., and 566, et. seq., the Marketing Affiliate Rules, which prohibit preferential treatment by an interstate natural gas pipeline of its marketing affiliates and govern, in particular, the provision of information by an interstate natural gas pipeline to its marketing affiliates. On September 27, 2001 the FERC issued a Notice of Proposed Rulemaking in Docket No. RM01-10 in which it proposed new rules governing the interaction between an interstate gas pipeline and its affiliates. If adopted as proposed, the Notice of Proposed Rulemaking could be read to limit communication between Natural Gas Pipeline Company of America and its affiliates. The Notice could also be read to require separate staffing of Natural Gas Pipeline Company of America and its affiliates, which, if applied, could significantly increase costs for these functions. On December 20, 2001, Natural Gas Pipeline Company of America and Kinder Morgan Interstate Gas Transmission LLC, as well as numerous other parties, jointly submitted their comments on the Notice of Proposed Rulemaking. The FERC to date has not acted on the proposal. INTRASTATE TRANSPORTATION AND SALES The operations of our intrastate pipelines are affected by FERC rules and regulations issued pursuant to the Natural Gas Act and the Natural Gas Policy Act. Of particular importance are regulations that allow increased access to interstate transportation services, without the necessity of obtaining prior FERC authorization for each transaction. A key element of the program is nondiscriminatory access, under which a regulated pipeline must agree, under certain conditions, to transport natural gas for any party requesting such service. Our intrastate pipeline in Colorado, Rocky Mountain Natural Gas Company, is regulated by the Colorado Public Utilities Commission as a public utility in regard to its natural gas transportation and sales services within the state. Rocky Mountain also performs certain natural gas transportation services in interstate commerce pursuant to Section 311 of the Natural Gas Policy Act of 1978. The Colorado Public Utilities Commission regulates the rates, terms, and conditions of natural gas sales and transportation services performed by public utilities in the state of Colorado. Our intrastate pipeline in Wyoming, Northern Gas Company, is regulated by the Wyoming Public Service Commission as a public utility in regard to its natural gas transportation and sales services within the state. Northern Gas also performs certain natural gas transportation services in interstate commerce pursuant to Section 311 of the Natural Gas Policy Act of 1978. The Wyoming Public Service Commission regulates the rates, terms, and conditions of natural gas sales and transportation services performed by public utilities in the state of Wyoming. On April 20, 2001, we filed an application with the Wyoming Public Service Commission to reorganize our Wyoming natural gas utility operations by merging Northern Gas Company into Kinder Morgan, Inc. Northern Gas Company presently serves Kinder Morgan, Inc.'s natural gas distribution system in central Wyoming, and if the application is approved, Northern Gas Company's pipelines will be conveyed to Kinder Morgan, Inc. and thereafter be operated as part of our natural gas distribution system in Wyoming in order to streamline operation of the two systems and facilitate expansion of the Choice Gas Program. 10 RETAIL NATURAL GAS DISTRIBUTION SERVICES Our intrastate pipelines, storage, distribution and/or retail sales in Colorado and Wyoming are under the regulatory authority of those state's utility commission. In Nebraska, retail natural gas sales rates for residential and small commercial customers are regulated by the municipality served. In certain of the incorporated communities in which we provide retail natural gas services, we operate under franchises granted by the applicable municipal authorities. The duration of these franchises varies. In unincorporated areas, our natural gas utility services are not subject to municipal franchise. We have been issued various certificates of public convenience and necessity by the regulatory commissions in Colorado and Wyoming authorizing us to provide natural gas utility services within certain incorporated and unincorporated areas of those states. We emerged as a leader in providing for customer choice in early 1996, when the Wyoming Public Service Commission issued an order allowing us to bring competition to 10,500 residential and commercial customers. In November 1997, we announced a similar plan to give residential and small commercial customers in Nebraska a choice of natural gas suppliers. This program, the Nebraska Choice Gas program, became effective June 1, 1998. As of December 31, 2001, the plan had been adopted by 178 of 181 communities, representing approximately 91,000 customers served by us in Nebraska. On April 20, 2001, we filed an application with the Wyoming Public Service Commission to expand Choice Gas to cover all of our Wyoming customers. A Stipulation and Agreement calling for approval of expansion of the Choice Gas Program has been presented to the Wyoming Public Service Commission for its consideration. The programs have succeeded in providing a choice of suppliers, competitive prices, and new products and services, while maintaining reliability and security of supply. Kinder Morgan Retail continues to provide all services other than the commodity supply in these programs, and competes with other suppliers in offering nonregulated natural gas supplies to retail customers. ENVIRONMENTAL REGULATION Our operations and properties are subject to extensive and evolving federal, state and local laws and regulations governing the release or discharge of regulated materials into the environment or otherwise relating to environmental protection or human health and safety. Numerous governmental departments issue rules and regulations to implement and enforce such laws, which are often costly to comply with and onerous, and which carry substantial administrative, civil and criminal penalties for failure to comply. These laws and regulations can also impose liability for remedial costs on the owner or operator of properties or the generators of waste materials, regardless of fault. Moreover, the recent trends toward stricter standards in environmental legislation and regulation are likely to continue. We had an established environmental reserve at December 31, 2001 of approximately $18 million, excluding any cost of remediation described below, to address remediation issues associated with approximately 35 projects. After consideration of reserves established, we believe that costs for environmental remediation and ongoing compliance with these regulations will not have a material adverse effect on our cash flows, financial position or results of operations or diminish our ability to operate our businesses. However, there can be no assurances that future events, such as changes in existing laws, the promulgation of new laws, or the development of new facts or conditions will not cause us to incur significant unanticipated costs. 11 RISK FACTORS - For 2001, approximately 40% of our income before interest and income taxes was attributable to our general and limited partner interests in Kinder Morgan Energy Partners. A significant decline in Kinder Morgan Energy Partners' earnings and/or cash distributions would have a corresponding negative impact on us. For more information on the earnings and cash distributions, please see Kinder Morgan Energy Partners' 2001 Annual Report on Form 10-K. - For 2001, approximately 56% of our income before interest and income taxes was attributable to the results of operations of Natural Gas Pipeline Company of America, an interstate pipeline that is a major supplier to the Chicago, Illinois area. In recent periods, interstate pipeline competitors of Natural Gas Pipeline Company of America have constructed or expanded pipeline capacity into the Chicago area, although additional take-away capacity has also been constructed. To the extent that an excess of supply into this market area is created and persists, Natural Gas Pipeline Company of America's ability to recontract for expiring transportation capacity at favorable rates could be impaired. - At December 31, 2001, we had approximately $1.6 billion of debt subject to floating interest rates. Should interest rates increase significantly, our earnings would be adversely affected. - While there are currently no material proceedings challenging the rates on any of our pipeline systems, shippers on these pipelines do have rights to challenge the rates we charge under certain circumstances prescribed by applicable regulations. We can provide no assurance that we will not face challenges to the rates we receive on our pipeline systems in the future. - Weather-related factors such as temperature and rainfall at certain times of the year affect our earnings in our natural gas transportation and retail natural gas distribution businesses. While we mitigate this impact through hedging programs and our interstate pipelines collect the majority of their transportation revenues through charges that are collected regardless of actual volumes transported, sustained periods of temperatures and rainfall that differ from normal can create volatility in our earnings. - Our short term liquidity could be impaired in the event the number of shares of Kinder Morgan Management surrendered for exchange exceeds by a significant amount the number of common units of Kinder Morgan Energy Partners owned by us. Kinder Morgan Management shareholders have the option to exchange Kinder Morgan Management shares for common units of Kinder Morgan Energy Partners owned by us, or at our election, cash. If the volume of exchanges exceeds the number of units we own, to the extent of the excess we will need to pay cash for the surrendered shares or buy common units on the open market to exchange for the shares. This need to raise cash could impact our liquidity on a short term basis. For more information on this exchange feature, please see Note 2 to our Financial Statements. - On September 27, 2001, FERC issued a Notice of Proposed Rulemaking in Docket No. RM01-10. The proposed rule would expand FERC's current standards of conduct to include a regulated transmission provider and all of its energy affiliates. It is not known whether FERC will issue a final rule in this docket and, if it does, whether the company could as a result incur increased costs and increased difficulty in its operations. - Environmental regulation could result in increased operating and capital costs for us. Our business operations are subject to federal, state and local laws and regulations relating to environmental protection. If an accidental leak or spill occurs from our pipelines or at our storage or other facilities, we may have to pay a significant amount to clean up the leak or spill. The resulting costs and liabilities could negatively affect our level of earnings and cash flow. In addition, emission controls required under federal and state environmental laws could require significant capital expenditures at our facilities. The impact of Environmental Protection Agency standards or future environmental measures on us could increase our costs significantly if environmental laws and 12 regulations become stricter. Since the costs of environmental regulation are already significant, additional regulation could negatively affect our business. OTHER Amounts we spent during 2001, 2000, and 1999 on research and development activities were not material. We employed 4,937 people at December 31, 2001, including employees of Kinder Morgan Services, LLC who are dedicated to the operations of Kinder Morgan Energy Partners. We are of the opinion that we generally have satisfactory title to the properties owned and used in our businesses, subject to the liens for current taxes, liens incidental to minor encumbrances, and easements and restrictions which do not materially detract from the value of such property or the interests therein or the use of the properties in our businesses. We generally do not own the land on which our pipelines are constructed. Instead, we obtain the right to construct and operate the pipelines on other people's land for a period of time. (D) FINANCIAL INFORMATION ABOUT GEOGRAPHIC AREAS All but an insignificant amount of our assets and operations are located in the continental United States of America. ITEM 3. LEGAL PROCEEDINGS. K N TransColorado, Inc. v. TransColorado Gas Transmission Company, et. al, Case No. 00-CV-129, District Court, County of Garfield, State of Colorado. On June 15, 2000, K N TransColorado filed suit against Questar TransColorado, its parent Questar Pipeline Company, and other affiliated Questar entities, asserting claims for breach of fiduciary duties, breach of contract, constructive trust, rescission of the partnership agreement, breach of good faith and fair dealing, tortious concealment, misrepresentation, aiding and abetting a breach of fiduciary duty, dissolution of the TransColorado partnership, and seeking a declaratory judgment, among other claims. The TransColorado partnership has been made a defendant for purposes of an accounting. The lawsuit alleges, among other things, Questar breached its fiduciary duties as a partner. K N TransColorado seeks to recover damages in excess of $152 million due to Questar's breaches and, in addition, seeks punitive damages. In response to the complaint, on July 28, 2000, the Questar entities filed a counterclaim and third party claims against Kinder Morgan and certain of its affiliates for claims arising out of the construction and operation of the TransColorado pipeline project. The claims allege, among other things, that the Kinder Morgan entities interfered with and delayed construction of the pipeline and made misrepresentations about marketing of capacity. The Questar entities seek to recover damages in excess of $185 million for an alleged breach of fiduciary duty and other claims. The parties agreed to stay the exercise of a contractual provision purportedly requiring K N TransColorado to purchase Questar's interest in the pipeline and to investigate the appointment of an independent operator for the pipeline during the litigation. The Court dismissed Questar's counterclaims for breach of duty of good faith and fair dealing and for indemnity and contribution and dismissed Questar's Third Party Complaint. On July 19, 2001, the Court granted K N TransColorado's motion for summary judgment that: a) fiduciary duties existed between the partners; b) these fiduciary duties were not modified or waived; and c) the affiliates and directors of Questar Pipeline Company and Questar TransColorado acting in their dual capacity had fiduciary obligations which required those individuals to disclose, to the partnership and the partners, information that affected the fundamental business purpose of the partnership. On August 14, 2001, the Court granted leave to Questar to file its First Amended Answer and Counterclaim, once again naming Kinder Morgan, Inc. as a counterclaim defendant, and making similar allegations against us as set forth above. Fact discovery and expert discovery have closed. The case is set for trial on April 1, 2002. Jack J. Grynberg, individually and as general partner for the Greater Green River Basin Drilling Program: 72-73 v. Rocky Mountain Natural Gas Company and K N Energy, Inc., Case No. 90-CV-3686. On June 5, 1990, Jack J. Grynberg filed suit, which is presently pending in Jefferson County District Court for Colorado, against Rocky Mountain Natural Gas Company and us alleging breach of contract 13 and fraud. In essence, Grynberg asserts claims that the named companies failed to pay Grynberg the proper price, impeded the flow of natural gas, mismeasured natural gas, delayed his development of natural gas reserves, and other claims arising out of a contract to purchase natural gas from a field in northwest Colorado. On February 13, 1997, the trial judge entered partial summary judgment for Grynberg on his contract claim that he failed to receive the proper price for his natural gas. This ruling followed an appellate decision that was adverse to us on the contract interpretation of the price issue, but which did not address the question of whether Grynberg could legally receive the price he claimed or whether he had illegally diverted natural gas from a prior purchase. Grynberg has previously claimed damages in excess of $30 million. On August 29, 1997, the trial judge stayed the summary judgment pending resolution of a proceeding at the FERC to determine if Grynberg was entitled to administrative relief from an earlier dedication of the same natural gas to interstate commerce. On March 15, 1999, an Administrative Law Judge for the FERC ruled, after an evidentiary hearing, that Mr. Grynberg had illegally diverted the natural gas when he entered the contract with the named companies and was not entitled to relief. Grynberg filed exceptions to this ruling. In late March 2000, the FERC issued an order affirming in part and denying in part the motions for rehearing of its Initial Decision. On November 21, 2000, the FERC upheld the Administrative Law Judge's factual findings and denial of retroactive abandonment. On June 14, 2001, Rocky Mountain Natural Gas Company filed a motion for Summary Judgment and To Vacate the February 13, 1997, Partial Summary Judgment, as a result of the conclusion of the FERC proceedings. On August 16, 2001, the Court granted Plaintiff's Motion to Continue the Stay of these proceedings pending the proceedings in federal court. The parties have reached a settlement in principle of this matter and the federal court matter. The settlement is conditioned on certain findings by a Special Master. Jack J. Grynberg v. K N Energy, Inc., Rocky Mountain Natural Gas Company, and GASCO, Inc., Civil Action No. 92-N-2000. On October 9, 1992, Jack J. Grynberg filed suit in the United States District Court for the District of Colorado against us, Rocky Mountain Natural Gas Company and GASCO, Inc. alleging that these entities, the K N Entities, as well as K N Production Company and K N Gas Gathering, Inc., have violated federal and state antitrust laws. In essence, Grynberg asserts that the companies have engaged in an illegal exercise of monopoly power, have illegally denied him economically feasible access to essential facilities to store, transport and distribute gas, and illegally have attempted to monopolize or to enhance or maintain an existing monopoly. Grynberg also asserts certain state causes of action relating to a gas purchase contract. In February 1999, the Federal District Court granted summary judgment for the K N Entities as to some of Grynberg's antitrust and state law claims, while allowing other claims to proceed to trial. Grynberg has previously claimed damages in excess of $50 million. In addition to monetary damages, Grynberg has requested that the K N Entities be ordered to divest all interests in natural gas exploration, development and production properties, all interests in distribution and marketing operations, and all interests in natural gas storage facilities, in order to separate these interests from our natural gas gathering and transportation system in northwest Colorado. The parties have reached a settlement in principle of this matter and the state court matter. The court has ordered that the settlement be finalized by March 15, 2002, or the federal case will proceed to trial. The settlement is conditioned on certain findings by a Special Master. United States of America, ex rel., Jack J. Grynberg v. K N Energy, Civil Action No. 97-D-1233, filed in the U.S. District Court, District of Colorado. This action was filed on June 9, 1997 pursuant to the federal False Claim Act and involves allegations of mismeasurement of natural gas produced from federal and Indian lands. The Department of Justice has decided not to intervene in support of the action. The complaint is part of a larger series of similar complaints filed by Mr. Grynberg against 77 natural gas pipelines (approximately 330 other defendants). An earlier single action making substantially similar allegations against the pipeline industry was dismissed by Judge Hogan of the U.S. District Court for the District of Columbia on grounds of improper joinder and lack of jurisdiction. As a result, Mr. Grynberg filed individual complaints in various courts throughout the country. These cases were recently consolidated by the Judicial Panel for Multidistrict Litigation, and transferred to the District of Wyoming. Motions to Dismiss were filed and an oral argument on the Motion to Dismiss occurred on March 17, 2000. On July 20, 2000 the United States of America filed a motion to dismiss those claims by Grynberg that deal 14 with the manner in which defendants valued gas produced from federal leases. Judge Downes denied the defendant's motion to dismiss on May 18, 2001. The defendants have sought reconsideration of this Order and have requested a status conference. Quinque Operating Company, et. al. v. Gas Pipelines, et. al., Cause No. 99-1390-CM, United States District Court for the District of Kansas. This action was originally filed on May 28, 1999 in Kansas state court in Stevens County, Kansas as a class action against approximately 245 pipeline companies and their affiliates, including certain Kinder Morgan entities. The plaintiffs in the case seek to have the Court certify the case as a class action, a class of natural gas producers and fee royalty owners who allege that they have been subject to systematic mismeasurement of natural gas by the defendants for more than 25 years. Among other things, the plaintiffs allege a conspiracy among the pipeline industry to under-measure gas and have asserted joint and several liability against the defendants. Subsequently, one of the defendants removed the action to Kansas Federal District Court. Thereafter, we filed a motion with the Judicial Panel for Multidistrict Litigation to consolidate this action for pretrial purposes with the Grynberg False Claim Act cases referred to above, because of common factual questions. On April 10, 2000, the Judicial Panel for Multidistrict Litigation ordered that this case be consolidated with the Grynberg federal False Claims Act cases. On January 12, 2001, the Federal District Court of Wyoming issued an oral ruling remanding the case back to the State Court in Stevens County, Kansas. A case management conference occurred in State Court in Stevens County, and a briefing schedule was established for preliminary matters. Personal jurisdiction discovery has commenced. Merits discovery has been stayed. Recently, the defendants filed a motion to dismiss on grounds other than personal jurisdiction, and a motion to dismiss for lack of personal jurisdiction for non-resident defendants. K N Energy, Inc., et al. v. James P. Rode and Patrick R. McDonald, Case No. 99CV1239, filed in the District Court, Jefferson County, Division 8, Colorado. The case was filed on May 21, 1999. Defendants counterclaimed and filed third party claims against several of our former officers and/or directors. Messrs. Rode and McDonald are former principal shareholders of Interenergy Corporation. We acquired Interenergy on December 19, 1997 pursuant to a Merger Agreement dated August 25, 1997. Rode and McDonald allege that K N Energy committed securities fraud, common law fraud and negligent misrepresentation as well as breach in contract. Plaintiffs are seeking an unspecified amount of compensatory damages, greater than $2 million, plus unspecified exemplary or punitive damages, attorney's fees and their costs. We filed a motion to dismiss, and on April 21, 2000, the Jefferson County District Court Judge dismissed the case against the individuals and us with prejudice. On April 6, 2001, the Colorado Court of Appeals affirmed the dismissal. Defendants also filed a federal securities fraud action in the United States District Court for the District of Colorado on January 27, 2000 titled: James P. Rode and Patrick R. McDonald v. K N Energy, Inc., et al., Civil Action No. 00-N-190. This case initially raised the identical state law claims contained in the counterclaim and third party complaint in state court. Rode and McDonald filed an amended Complaint, which dropped the state-law claims. On June 20, 2000, the federal district court dismissed this Complaint with prejudice. Rode and McDonald filed notices of appeal of the federal court dismissal. Briefing on this appeal is complete. A third related class action case styled, Adams vs. Kinder Morgan, Inc., et. al., Civil Action No. 00-M-516, in the United States District Court for the District of Colorado was served on us on April 10, 2000. As of this date no class has been certified. On February 23, 2001, the federal district court dismissed several claims raised by the plaintiff, with prejudice, and dismissed the remaining claims, without prejudice. On April 27, 2001, the Adams plaintiffs filed their second amended complaint. We have moved to dismiss this complaint and the briefing on the motion is complete. An oral argument on the motion to dismiss is set for March 29, 2002. We believe that we have meritorious defenses to all lawsuits and legal proceedings in which we are defendants and will vigorously defend against them. Based on our evaluation of the above matters, and after consideration of reserves established, we believe that the resolution of such matters will not have a material adverse effect on our businesses, cash flows, financial position or results of operations. 15 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. None EXECUTIVE OFFICERS OF THE REGISTRANT (A) IDENTIFICATION AND BUSINESS EXPERIENCE OF EXECUTIVE OFFICERS Set forth below is certain information concerning our executive officers. All officers serve at the discretion of our board of directors.
NAME AGE POSITION - ---- --- -------- Richard D. Kinder.................... 57 Director, Chairman and Chief Executive Officer William V. Morgan.................... 58 Director and Vice Chairman Michael C. Morgan.................... 33 President William V. Allison................... 54 President, Natural Gas Pipelines David G. Dehaemers, Jr. ............. 41 Vice President, Corporate Development Joseph Listengart.................... 33 Vice President, General Counsel and Secretary C. Park Shaper....................... 33 Vice President, Treasurer and Chief Financial Officer James E. Street...................... 45 Vice President, Human Resources and Administration
Richard D. Kinder is Director, Chairman and Chief Executive Officer of Kinder Morgan, Inc., Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. Mr. Kinder has served as Director, Chairman and Chief Executive Officer of Kinder Morgan Management, LLC since its formation in February 2001. He was elected Director, Chairman and Chief Executive Officer of Kinder Morgan, Inc. in October 1999. He was elected Director, Chairman and Chief Executive Officer of Kinder Morgan G.P., Inc. in February 1997. Mr. Kinder is also a director of TransOcean Offshore Inc. and Baker Hughes Incorporated. William V. Morgan is Director and Vice Chairman of Kinder Morgan, Inc., Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. Mr. Morgan served as the President of Kinder Morgan Management, LLC from February 2001 to July 2001. He served as President of Kinder Morgan, Inc. from October 1999 to July 2001. He served as President of Kinder Morgan G.P., Inc. from February 2001 to July 2001. Mr. Morgan has served as Director and Vice Chairman of Kinder Morgan Management, LLC since its formation in February 2001. Mr. Morgan has served as Director and Vice Chairman of Kinder Morgan, Inc. since October 1999. Mr. Morgan was elected Vice Chairman of Kinder Morgan G.P., Inc. in February 1997. He served as President of Cortez Holdings Corporation, a pipeline investment company, from October 1992 through March 2000. On January 17, 2002, we announced that Mr. Morgan would transition to a non-executive role in April 2003. At that time, Mr. Morgan will retain his Vice Chairman title and remain an active board member, but he will be less involved in our day-to-day operations. Mr. Morgan is the father of Michael C. Morgan, President of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc., and Kinder Morgan, Inc. Michael C. Morgan is President of Kinder Morgan, Inc., Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. Mr. Morgan was elected to each of these positions in July 2001. Mr. Morgan served as Vice President, Strategy and Investor Relations of Kinder Morgan Management, LLC from February 2001 to July 2001. He served as Vice President, Strategy and Investor Relations of Kinder Morgan, Inc. and Kinder Morgan G.P., Inc. from January 2000 to July 2001. He served as Vice President, Corporate Development of Kinder Morgan G.P., Inc. from February 1997 to January 2000. Mr. Morgan was the Vice President, Corporate Development of Kinder Morgan, Inc. from October 1999 to January 2000. From August 1995 until February 1997, Mr. Morgan was an associate with McKinsey & Company, an international management consulting firm. In 1995, Mr. Morgan received a Masters in Business Administration from the Harvard Business School. From March 1991 to June 1993, Mr. Morgan held various positions, including Assistant to the Chairman, at PSI Energy, Inc., an electric utility. Mr. Morgan received a Bachelor of Arts in Economics and a Masters of Arts in Sociology from Stanford University in 1990. Mr. Morgan is the son of William V. Morgan. 16 William V. Allison is President, Natural Gas Pipelines of Kinder Morgan, Inc., Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. Mr. Allison was elected President, Natural Gas Pipelines of Kinder Morgan Management, LLC upon its formation in February 2001. He was elected President, Natural Gas Pipelines of Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. in September 1999. He was President, Pipeline Operations of Kinder Morgan G.P., Inc. from February 1999 to September 1999. Mr. Allison served as Vice President and General Counsel of Kinder Morgan G.P., Inc. from April 1998 to February 1999. From May 1997 to April 1998, Mr. Allison managed his personal investments. From April 1996 through May 1997, Mr. Allison served as President of Enron Liquid Services Corporation. On February 8, 2002, we announced that Mr. Allison will retire effective June 1, 2002. David G. Dehaemers, Jr. is Vice President, Corporate Development of Kinder Morgan, Inc., Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. Mr. Dehaemers was elected Vice President, Corporate Development of Kinder Morgan Management, LLC upon its formation in February 2001. Mr. Dehaemers was elected Vice President, Corporate Development of Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. in January 2000. He served as Vice President and Chief Financial Officer of Kinder Morgan, Inc. from October 1999 to January 2000. He served as Vice President and Chief Financial Officer of Kinder Morgan G.P., Inc. from July 1997 to January 2000 and Treasurer of Kinder Morgan G.P., Inc. from February 1997 to January 2000. He served as Secretary of Kinder Morgan G.P., Inc. from February 1997 to August 1997. Mr. Dehaemers was previously employed by the national CPA firms of Ernst & Whinney and Arthur Young. Mr. Dehaemers received his law degree from the University of Missouri-Kansas City and is a member of the Missouri Bar. He is also a CPA and received his undergraduate Accounting degree from Creighton University in Omaha, Nebraska. Joseph Listengart is Vice President, General Counsel and Secretary of Kinder Morgan, Inc., Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. Mr. Listengart was elected Vice President, General Counsel and Secretary of Kinder Morgan Management, LLC upon its formation in February 2001. He was elected Vice President and General Counsel of Kinder Morgan G.P., Inc. and Vice President, General Counsel and Secretary of Kinder Morgan, Inc. in October 1999. Mr. Listengart was elected Secretary of Kinder Morgan G.P., Inc. in November 1998 and became an employee of Kinder Morgan G.P., Inc. in March 1998. From March 1995 through February 1998, Mr. Listengart worked as an attorney for Hutchins, Wheeler & Dittmar, a Professional Corporation. Mr. Listengart received his Masters in Business Administration from Boston University in January 1995, his Juris Doctor, magna cum laude, from Boston University in May 1994, and his Bachelor of Arts degree in Economics from Stanford University in June 1990. C. Park Shaper is Vice President, Treasurer and Chief Financial Officer of Kinder Morgan, Inc., Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. Mr. Shaper was elected Vice President, Treasurer and Chief Financial Officer of Kinder Morgan Management, LLC upon its formation in February 2001. He has served as Treasurer of Kinder Morgan, Inc. since April 2000 and Vice President and Chief Financial Officer of Kinder Morgan, Inc. since January 2000. Mr. Shaper was elected Vice President, Treasurer and Chief Financial Officer of Kinder Morgan G.P., Inc. in January 2000. From June 1999 to December 1999, Mr. Shaper was President and Director of Altair Corporation, an enterprise focused on the distribution of web-based investment research for the financial services industry. He served as Vice President and Chief Financial Officer of First Data Analytics, a wholly-owned subsidiary of First Data Corporation, from 1997 to June 1999. From 1995 to 1997, he was a consultant with The Boston Consulting Group. He received a Masters of Business Administration degree from the J.L. Kellogg Graduate School of Management at Northwestern University. Mr. Shaper also has a Bachelor of Science degree in Industrial Engineering and a Bachelor of Arts degree in Quantitative Economics from Stanford University. James E. Street is Vice President, Human Resources and Administration of Kinder Morgan, Inc., Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. Mr. Street was elected Vice President, Human Resources and Administration of Kinder Morgan Management, LLC upon its formation in February 2001. He was elected Vice President, Human Resources and Administration of Kinder Morgan 17 G.P., Inc. and Kinder Morgan, Inc. in August 1999. From October 1996 to August 1999, Mr. Street was Senior Vice President, Human Resources and Administration for Coral Energy, a subsidiary of Shell Oil Company. Mr. Street received a Masters of Business Administration degree from the University of Nebraska at Omaha and a Bachelor of Science degree from the University of Nebraska at Kearney. (B) INVOLVEMENT IN CERTAIN LEGAL PROCEEDINGS None. PART II ITEM 5. MARKET FOR THE REGISTRANT'S EQUITY AND RELATED SECURITY HOLDER MATTERS. Our common stock is listed for trading on the New York Stock Exchange under the symbol KMI. Dividends paid and the price range of our common stock by quarter for the last two years are provided below.
MARKET PRICE PER SHARE DATA ---------------------------------------- 2001 2000 ------------------ ------------------ LOW HIGH LOW HIGH ------- ------- ------- ------- Quarter Ended: March 31.......................................... $42.875 $60.000 $19.875 $34.500 June 30........................................... $50.250 $59.970 $29.188 $34.938 September 30...................................... $46.220 $57.570 $31.625 $41.688 December 31....................................... $46.950 $57.130 $37.063 $54.250
DIVIDENDS PAID PER SHARE ----------------------------- Quarter Ended: March 31.......................................... $ 0.05 $0.05 June 30........................................... $ 0.05 $0.05 September 30...................................... $ 0.05 $0.05 December 31....................................... $ 0.05 $0.05 Stockholders of Record as of February 1, 2002....... 32,000 (approximately)
There were no sales of unregistered equity securities during the period covered by this report. 18 ITEM 6. SELECTED FINANCIAL DATA. FIVE-YEAR REVIEW KINDER MORGAN, INC. AND SUBSIDIARIES
YEAR ENDED DECEMBER 31, ------------------------------------------------------------ 2001 2000 1999(1) 1998(2) 1997 ---------- ---------- ---------- ---------- -------- (IN THOUSANDS EXCEPT PER SHARE AMOUNTS) Operating Revenues.......................... $1,054,918 $2,679,722 $1,836,368 $1,660,259 $340,685 Gas Purchases and Other Costs of Sales...... 339,353 1,926,068 1,050,250 836,614 134,476 ---------- ---------- ---------- ---------- -------- Gross Margin................................ 715,565 753,654 786,118 823,645 206,209 Other Operating Expenses.................... 331,246 358,511 490,416 427,953 128,059 ---------- ---------- ---------- ---------- -------- OPERATING INCOME............................ 384,319 395,143 295,702 395,692 78,150 Other Income and (Expenses)(3).............. 22,917 (87,977) (81,151) (172,787) (21,039) ---------- ---------- ---------- ---------- -------- Income From Continuing Operations Before Income Taxes.............................. 407,236 307,166 214,551 222,905 57,111 Income Taxes................................ 168,601 123,017 79,124 82,710 12,777 ---------- ---------- ---------- ---------- -------- INCOME FROM CONTINUING OPERATIONS........... 238,635 184,149 135,427 140,195 44,334 Gain (Loss) From Discontinued Operations, Net of Tax................................ -- (31,734) (395,319) (77,984) 33,163 ---------- ---------- ---------- ---------- -------- Income (Loss) Before Extraordinary Item..... 238,635 152,415 (259,892) 62,211 77,497 Extraordinary Item -- Loss on Early Extinguishment of Debt, Net of Income Taxes..................................... (13,565) -- -- -- -- ---------- ---------- ---------- ---------- -------- NET INCOME (LOSS)........................... 225,070 152,415 (259,892) 62,211 77,497 Less-Preferred Dividends.................... -- -- 129 350 350 Less-Premium Paid on Preferred Stock Redemption................................ -- -- 350 -- -- ---------- ---------- ---------- ---------- -------- EARNINGS (LOSS) AVAILABLE FOR COMMON STOCK..................................... $ 225,070 $ 152,415 $ (260,371) $ 61,861 $ 77,147 ========== ========== ========== ========== ======== BASIC EARNINGS (LOSS) PER COMMON SHARE: Continuing Operations....................... $ 2.07 $ 1.62 $ 1.68 $ 2.19 $ 0.95 Discontinued Operations..................... -- (0.28) (4.92) (1.22) 0.71 Extraordinary Item -- Loss on Early Extinguishment of Debt.................... (0.12) -- -- -- -- ---------- ---------- ---------- ---------- -------- Total Basic Earnings (Loss) Per Common Share..................................... $ 1.95 $ 1.34 $ (3.24) $ 0.97 $ 1.66 ========== ========== ========== ========== ======== Number of Shares Used in Computing Basic Earnings (Loss) Per Common Share.......... 115,243 114,063 80,284 64,021 46,589 ========== ========== ========== ========== ======== DILUTED EARNINGS (LOSS) PER COMMON SHARE: Continuing Operations....................... $ 1.97 $ 1.61 $ 1.68 $ 2.17 $ 0.93 Discontinued Operations..................... -- (0.28) (4.92) (1.21) 0.70 Extraordinary Item -- Loss on Early Extinguishment of Debt.................... (0.11) -- -- -- -- ---------- ---------- ---------- ---------- -------- Total Diluted Earnings (Loss) Per Common Share..................................... $ 1.86 $ 1.33 $ (3.24) $ 0.96 $ 1.63 ========== ========== ========== ========== ======== Number of Shares Used in Computing Diluted Earnings (Loss) Per Common Share.......... 121,326 115,030 80,358 64,636 47,307 ========== ========== ========== ========== ======== DIVIDENDS PER COMMON SHARE.................. $ 0.20 $ 0.20 $ 0.65 $ 0.76 $ 0.73 ========== ========== ========== ========== ======== CAPITAL EXPENDITURES(4)..................... $ 124,171 $ 85,654 $ 92,841 $ 120,881 $230,814 ========== ========== ========== ========== ========
- --------------- (1) Reflects the acquisition of Kinder Morgan Delaware on October 7, 1999. See Note 3 of the accompanying Notes to Consolidated Financial Statements. (2) Reflects the acquisition of MidCon Corp. on January 30, 1998. (3) Includes significant impacts from sales of assets. See Note 1 (N) of the accompanying Notes to Consolidated Financial Statements. (4) Capital Expenditures shown are for continuing operations only. 19 FIVE-YEAR REVIEW (CONTINUED) KINDER MORGAN, INC. AND SUBSIDIARIES
AS OF DECEMBER 31, ------------------------------------------------------------------------------------------------ 2001 2000 1999 1998 1997 ---------- ---------- ---------- ---------- ---------- (IN THOUSANDS EXCEPT PER SHARE AMOUNTS) TOTAL ASSETS........... $9,533,085 $8,386,989 $9,393,834 $9,623,779 $2,305,805 ========== ========== ========== ========== ========== CAPITALIZATION: Common Equity.......... $2,259,997 39% $1,777,624 39% $1,649,615 32% $1,219,043 25% $ 606,132 46% Preferred Stock........ -- -- -- -- -- -- 7,000 -- 7,000 -- Preferred Capital Trust Securities........... 275,000 5% 275,000 6% 275,000 5% 275,000 6% 100,000 8% Minority Interests..... 817,513 14% 4,910 -- 9,523 -- 63,354 1% 47,303 4% Long-term Debt......... 2,404,967 42% 2,478,983 55% 3,293,326 63% 3,300,025 68% 553,816 42% ---------- --- ---------- --- ---------- --- ---------- --- ---------- --- Total Capitalization... $5,757,477 100% $4,536,517 100% $5,227,464 100% $4,864,422 100% $1,314,251 100% ========== === ========== === ========== === ========== === ========== === BOOK VALUE PER COMMON SHARE......... $ 18.24 $ 15.53 $ 14.64 $ 17.77 $ 12.63 ========== ========== ========== ========== ==========
20 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. GENERAL In this report, unless the context requires otherwise, references to "we," "us," "our," or the "Company" are intended to mean Kinder Morgan, Inc. (a Kansas corporation formerly known as K N Energy, Inc.) and its consolidated subsidiaries. The following discussion should be read in conjunction with the accompanying Consolidated Financial Statements and related Notes. Specifically, as discussed in Notes 3, 6 and 7 of the accompanying Notes to Consolidated Financial Statements, we have engaged in acquisitions (including the October 1999 acquisition of Kinder Morgan (Delaware), Inc., the indirect owner of the general partner interest in Kinder Morgan Energy Partners, L.P., a publicly traded master limited partnership, referred to in this report as "Kinder Morgan Energy Partners"), and divestitures (including the discontinuance of certain lines of business and the transfer of certain assets to Kinder Morgan Energy Partners) that may affect comparisons of financial position and results of operations between periods. BUSINESS STRATEGY On October 7, 1999, we completed the acquisition of Kinder Morgan (Delaware), Inc., a Delaware corporation and the sole stockholder of the general partner of Kinder Morgan Energy Partners. To effect that acquisition, we issued approximately 41.5 million shares of our common stock in exchange for all of the outstanding shares of Kinder Morgan (Delaware). Upon closing of the transaction, Richard D. Kinder, Chairman and Chief Executive Officer of Kinder Morgan (Delaware), was named Chairman and Chief Executive Officer, and we were renamed Kinder Morgan, Inc. In accordance with previously announced plans, we implemented and have continued to pursue our "Back to Basics" strategy. This strategy includes the following key aspects: (i) focus on fee-based energy transportation and storage assets that are core to the energy infrastructure of growing markets, (ii) increase utilization of existing assets while controlling costs, (iii) leverage economies of scale from incremental acquisitions, (iv) maximize the benefits of our unique financial structure and (v) continue to align employee and shareholder incentives. During 1999, we implemented plans to dispose of our non-core businesses and as of December 31, 2000, we effectively completed the disposition of these assets and operations, all as more fully described in Note 7 of the accompanying Notes to Consolidated Financial Statements. The cash proceeds from these dispositions were largely used to retire debt, contributing to the reduction in outstanding indebtedness during 2000. In addition to sales of non-core assets to third parties, we made significant transfers of assets to Kinder Morgan Energy Partners at the end of 1999 and the end of 2000 that, in total, had over $1 billion of fair market value. By contributing assets to Kinder Morgan Energy Partners that are accretive to its earnings and cash flow, we can receive fair market value in the contribution transaction, while still maintaining an indirect interest in the earnings and cash flows of the assets through our limited and general partner interests in Kinder Morgan Energy Partners. As of December 31, 2001, we owned, directly, and indirectly in the form of i-units corresponding to the number of shares of Kinder Morgan Management, LLC we own, approximately 31.1 million limited partner units of Kinder Morgan Energy Partners, representing approximately 18.7% of the total units outstanding. As a result of our general and limited partner interests in Kinder Morgan Energy Partners, at the current level of distribution including incentive distributions to the general partner, we currently are entitled to receive approximately 50% of all distributions from Kinder Morgan Energy Partners. The actual level of distributions received by us in the future will vary with the level of distributable cash determined by Kinder Morgan Energy Partners' partnership agreement. After the dispositions discussed above, our remaining businesses constitute three business segments. Our largest business segment and our primary source of operating income is Natural Gas Pipeline Company of America (NGPL), which owns and operates a major interstate natural gas pipeline system 21 that runs from natural gas producing areas in West Texas and the Gulf of Mexico to its principal market area of Chicago, Illinois. In accordance with our strategy to increase operational focus on core assets, we have worked toward renewing existing agreements and entering into new agreements to fully utilize the transportation and storage capacity of Natural Gas Pipeline Company of America's system. As a result, Natural Gas Pipeline Company of America sold virtually all of its capacity through the 2001-2002 winter season. Natural Gas Pipeline Company of America continues to pursue opportunities to connect its system to power generation facilities and, in addition, has announced plans to extend its system into the metropolitan east area of St. Louis anchored by a contract with Dynegy Marketing and Trade. Our other business segments consist of the retail distribution of natural gas to approximately 233,000 customers in Colorado, Wyoming and Nebraska and the construction and operation of electric power generation facilities. Our retail natural gas distribution operations are located, in part, in areas where significant growth is occurring and we expect to participate in that growth through increased natural gas demand. Our power segment owns and operates power generation facilities, is currently constructing two power plants for other parties and may construct additional natural gas-fired electric generation facilities to help meet the country's growing electric power needs. These power projects, in addition to generating income in their own right, are expected to increase Natural Gas Pipeline Company of America's throughput as described above. With respect to financial strategy, it is our intention to maintain a relatively conservative capital structure that provides flexibility and stability. During 2001, we utilized our significant free cash flow both from operations and financing activities (principally the November 2001 maturity of our premium equity participating securities) to reduce debt and to reacquire approximately $270 million of our common stock (pursuant to a previously announced $300 million stock buyback program). In early 2002, we announced the expansion of our stock buyback program to a total of $400 million. At December 31, 2001, our total debt to total capital was approximately 47%, down from over 70% in late 1999, with approximately 50% of our debt subject to floating interest rates. We believe that we will continue to benefit from accretive acquisitions and business expansions, primarily by Kinder Morgan Energy Partners. Kinder Morgan Energy Partners has a multi-year history of making accretive acquisitions, which benefit us through our limited and general partner interests. This acquisitive strategy is expected to continue, with the availability of potential acquisition candidates being driven by consolidation in the energy industry, as well as realignment of asset portfolios by major energy companies. In addition, we expect to, within strict guidelines as to rate of return and risk and timing of cash flows, expand Natural Gas Pipeline Company of America's pipeline system and acquire natural gas retail distribution properties that fit well with our current profile. It is our intention to carry out the above strategy, modified as necessary to reflect changing economic and other circumstances. However, as discussed under "Risk Factors" elsewhere in this report, there are factors that could affect our ability to carry out our strategy or to affect its level of success even if carried out. CRITICAL ACCOUNTING POLICIES AND ESTIMATES Our discussion and analysis of financial condition and operations are based on our consolidated financial statements, prepared in accordance with accounting principles generally accepted in the United States of America and contained within this report. Certain amounts included in or affecting our financial statements and related disclosure must be estimated, requiring us to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time the financial statements are prepared. Therefore, the reported amounts of our assets and liabilities, revenues and expenses and associated disclosures with respect to contingent assets and obligations are necessarily affected by these estimates. We evaluate these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. 22 In preparing our financial statements and related disclosures, we must use estimates in determining the economic useful lives of our assets, obligations under our employee benefit plans, provisions for uncollectible accounts receivable, unbilled revenues for our natural gas distribution deliveries for which meters have not yet been read, exposures under contractual indemnifications and to determine various other recorded or disclosed amounts. However, we believe that certain accounting policies are of more significance in our financial statement preparation process than others. With respect to revenue recognition, our power plant development business utilizes the percentage of completion method to determine what portion of its overall constructor fee has been earned. We utilize the services of third-party engineering firms to help us estimate the progress being made on each project, but any such process requires subjective judgments. Any errors in this estimation process could result in revenues being reported before or after they were actually earned. Increases or decreases in revenues resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. With respect to our environmental exposure, we utilize both internal staff and external experts to assist us in identifying environmental issues and in estimating the costs and timing of remediation efforts. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in our income in the period in which they are reasonably determinable. We record a valuation allowance to reduce our deferred tax assets to an amount that is more likely than not to be realized. While we have considered future taxable income and prudent and feasible tax planning strategies in determining the amount of our valuation allowance, any difference in the amount that we expect to ultimately realize will be included in income in the period in which such a determination is reached. As discussed under "Risk Management" elsewhere herein, we enter into derivative contracts (natural gas futures, swaps and options) solely for the purpose of mitigating risks that accompany our normal business activities, including interest rates and the price of natural gas and associated transportation. We account for these derivative transactions as hedges in accordance with the authoritative accounting guidelines, marking the derivatives to market at each reporting date, with the unrealized gains and losses either recognized as part of comprehensive income or, in the case of interest rate swaps, as a valuation adjustment to the underlying debt. Any inefficiency in the performance of the hedge is recognized in income currently and, ultimately, the financial results of the hedge are recognized concurrently with the financial results of the underlying hedged item. All but an insignificant amount of our natural gas related derivatives are for terms of 18 months or less, allowing us to utilize widely available, published forward pricing curves in determining the appropriate market values. Our interest rate swaps are similar in nature to many other such financial instruments and are valued for us by commercial banks with expertise in such valuations. Finally, we are subject to litigation as the result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from judgments or settlements. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. 23 CONSOLIDATED FINANCIAL RESULTS
YEAR ENDED DECEMBER 31, --------------------------------------- 2001 2000 1999 ----------- ----------- ----------- (IN THOUSANDS EXCEPT PER SHARE AMOUNTS) Operating Revenues....................................... $1,054,918 $2,679,722 $1,836,368 ========== ========== ========== Gross Margin............................................. $ 715,565 $ 753,654 $ 786,118 ========== ========== ========== General and Administrative Expenses...................... $ 70,386 $ 58,087 $ 85,591 ========== ========== ========== Operating Income......................................... $ 384,319 $ 395,143 $ 295,702 Other Income and (Expenses).............................. 22,917 (87,977) (81,151) Income Taxes............................................. 168,601 123,017 79,124 ---------- ---------- ---------- Income from Continuing Operations........................ 238,635 184,149 135,427 Loss from Discontinued Operations........................ -- -- (50,941) Loss on Disposal of Discontinued Operations.............. -- (31,734) (344,378) Extraordinary Item -- Loss on Early Extinguishment of Debt................................................... (13,565) -- -- ---------- ---------- ---------- Net Income (Loss)........................................ $ 225,070 $ 152,415 $ (259,892) ========== ========== ========== Total Diluted Earnings (Loss) Per Common Share........... $ 1.86 $ 1.33 $ (3.24) Loss from Discontinued Operations...................... -- -- (0.63) Loss on Disposal of Discontinued Operations............ -- (0.28) (4.29) Extraordinary Item -- Loss on Early Extinguishment of Debt................................................ (0.11) -- -- ---------- ---------- ---------- Income from Continuing Operations Per Diluted Share...... 1.97 1.61 1.68 Asset Sales(1)......................................... 0.08 0.32 1.23 Litigation Provision................................... (0.05) -- -- Counterparty Nonperformance Exposure................... (0.02) -- -- Merger-related and Severance Costs..................... -- -- (0.29) ---------- ---------- ---------- $ 1.96 $ 1.29 $ 0.74 ========== ========== ==========
- --------------- (1) Incidental asset sales are included in business segment earnings. Our results for 2001, in comparison to 2000, reflect a decrease of $1.6 billion in operating revenues, a decrease of $38.1 million in gross margin and a decrease of $10.8 million in operating income. These declines are attributable to the fact that consolidated results for 2000 include the results of Kinder Morgan Texas Pipeline, L.P., referred to in this report as "Kinder Morgan Texas Pipeline" (operating revenues, gross margin and operating income before corporate charges of $1.7 billion, $81.3 million and $29.3 million, respectively), which was transferred to Kinder Morgan Energy Partners effective December 22, 2000. If the results of Kinder Morgan Texas Pipeline are excluded from 2000 results, the comparison of 2001 to 2000 reflects increases of $122.7 million, $43.2 million and $13.9 million in operating revenues, gross margin and operating income, respectively. These increases represent improved results at each of our business segments, with Kinder Morgan Retail making the largest contribution to increased revenues and Power and Other making the largest contribution to the increases in gross margin and operating income. General and administrative expenses increased by $12.3 million from 2000 to 2001 principally as a result of (i) increased costs for employee benefits and (ii) a $5.0 million loss resulting from nonperformance by a derivative counterparty (Enron Corp.) as more fully discussed in Note 15 of the accompanying Notes to Consolidated Financial Statements. General and administrative expenses decreased by $27.5 million from 1999 to 2000 principally due to (1) the December 1999 transfer of Kinder Morgan Interstate Gas Transmission and certain other assets to Kinder Morgan Energy Partners and (2) decreased employee benefit costs in 2000 due, in part, to staffing reductions following the October 24 1999 acquisition of Kinder Morgan (Delaware). Individual business segment results are discussed in detail following. Below the operating income line, the improved results for 2001, relative to 2000, were principally due to (i) an increase of $138.5 million in equity earnings in Kinder Morgan Energy Partners, net of amortization of excess investment and (ii) a decrease of $27.0 million in net interest expense. The favorable variance created by these impacts was partially offset by (i) $12.6 million of increased 2001 minority interest (due to the sale of Kinder Morgan Management shares) and (ii) a reduction of approximately $39.1 million in net gains from assets sales in 2001. Additional information on these non-operating income and expense items is included under "Other Income and (Expenses)" following. For 2002, earnings attributable to our investment in Kinder Morgan Energy Partners are expected to increase by approximately 60% due to, among other factors, the improved performance of existing assets and the addition of earnings attributable to Kinder Morgan Energy Partners' pending acquisition of Tejas Gas, LLC. However, there are factors beyond the control of Kinder Morgan Energy Partners that may affect its results, including developments in the regulatory arena and as yet unforeseen competitive developments. Diluted earnings per common share from continuing operations increased from $1.61 in 2000 to $1.97 in 2001. In addition to the operating and financing factors described preceding, this increase reflects an additional 6.3 million (5.5%) average diluted shares outstanding in 2001, largely due to shares issued in conjunction with the November 2001 maturity of our premium equity participating units, partially offset by shares reacquired in our share repurchase program. As shown in the preceding table of our consolidated financial results, after adjustment for net gains from asset sales and two loss provisions recorded in 2001, diluted earnings per share from continuing operations increased from $1.29 per share in 2000 to $1.96 per share in 2001. In total, diluted earnings per common share increased from $1.33 in 2000 to $1.86 in 2001, reflecting, in addition to the factors discussed preceding, the $0.28 loss per share impact of discontinued operations in 2000 and the $0.11 loss per share from early extinguishment of debt in 2001. RESULTS OF OPERATIONS We manage our various businesses by, among other things, allocating capital and monitoring operating performance. This management process includes dividing the company into business segments so that performance can be effectively monitored and reported for a limited number of discrete businesses. Currently, we manage and report our operations in the following business segments:
BUSINESS SEGMENT BUSINESS CONDUCTED REFERRED TO AS: - ---------------- ------------------ --------------- Natural Gas Pipeline Company of America and certain affiliates...................... The ownership and operation of a Natural Gas Pipeline major interstate natural gas Company of America pipeline and storage system Retail Natural Gas Distribution... The regulated transportation, Kinder Morgan Retail distribution and sale of natural gas to residential, commercial and industrial customers and the non-regulated sales of natural gas to certain utility customers under the Choice Gas Program Power Generation and Other........ The construction and operation of Power and Other natural gas-fired electric generation facilities, together with various other activities not constituting separately managed or reportable business segments
25 In previous periods, we owned and operated other lines of business, which we discontinued during 1999. In addition, our direct investment in the natural gas transmission and storage business has significantly decreased as a result of (i) the December 31, 1999 transfer to Kinder Morgan Energy Partners of Kinder Morgan Interstate Gas Transmission LLC, referred to in this report as "Kinder Morgan Interstate Gas Transmission" and (ii) the December 22, 2000 transfer to Kinder Morgan Energy Partners of Kinder Morgan Texas Pipeline. The results of operations of these two businesses are included in our financial statements until their disposition. The accounting policies we apply in the generation of business segment information are generally the same as those described in Note 1 to the accompanying Consolidated Financial Statements, except that certain items below the "Operating Income" line are either not allocated to business segments or are not considered by management in its evaluation of business segment performance. An exception to this is that, with respect to Kinder Morgan Power, which routinely conducts its business activities in the form of joint operations with other parties that are accounted for under the equity method of accounting, we include its equity in earnings of these investees in its operating results. These equity method earnings are included in "Other Income and (Expenses)" in our Consolidated Statements of Operations. In addition, (i) certain items included in operating income (such as merger-related and severance costs and general and administrative expenses) are not allocated to individual business segments and (ii) gains and losses from incidental sales of assets are included in segment earnings. With adjustment for these items, we currently evaluate business segment performance primarily based on operating income in relation to the level of capital employed. We account for intersegment sales at market prices, while we account for asset transfers at either market value or, in some instances, book value. As necessary for comparative purposes, we have reclassified prior period results and balances to conform to the current presentation. Following are operating results by individual business segment (before intersegment eliminations), including explanations of significant variances between the periods presented. NATURAL GAS PIPELINE COMPANY OF AMERICA
YEAR ENDED DECEMBER 31, ------------------------------ 2001 2000 1999 -------- -------- -------- (IN THOUSANDS EXCEPT SYSTEMS THROUGHPUT) Operating Revenues................................... $646,804 $622,002 $626,888 ======== ======== ======== Gross Margin......................................... $515,360 $510,586 $511,407 ======== ======== ======== Segment Earnings..................................... $346,569 $344,405 $306,695 ======== ======== ======== Systems Throughput (Trillion Btus)................... 1,398.9 1,459.3 1,449.9 ======== ======== ========
Natural Gas Pipeline Company of America's segment earnings increased by $2.2 million, or 0.6%, from 2000 to 2001. Operating results for 2001 were positively affected, relative to 2000, by (i) increased natural gas transportation and storage margins and (ii) a $6.1 million pre-tax gain on the sale of offshore laterals in 2001. These positive impacts were partially offset by (i) increased operations and maintenance expenses, primarily attributable to the higher costs of electric power for compression, (ii) increased ad valorem taxes and (iii) the fact that 2000 results include a $3.3 million refund of previously expensed transportation charges from an unaffiliated interstate pipeline and $1.5 million of pre-tax gains from asset sales. Although Natural Gas Pipeline Company of America experienced a reduction in its systems throughput in 2001, this has not had any significant impact on its revenues or contracting level. Recontracting in 2001 has been very successful with 100% of nominated storage service and demand storage service capacity contracted and in excess of 96% of long-haul transportation capacity contracted. The decrease in throughput can be attributed to several factors. In 2001, Natural Gas Pipeline Company of America's market area experienced the warmest November-December period on record. Storage customers have not withdrawn gas as pricing favored continuing to hold inventories. Market area deliveries 26 in general have been affected by decreased natural gas consumption in the industrial sector. Demand that disappeared during the 2000-01 winter, when the price of natural gas was relatively high, has been slow to return, especially as a result of the economic downturn. Another factor impacting Natural Gas Pipeline Company of America's market area deliveries is the increase in Canadian supply via the Alliance Pipeline. This impact has been mitigated by the fact that close to half of Alliance's volumes move into Vector Pipeline and on to points east of the Chicago area. Natural Gas Pipeline Company of America's segment earnings increased by $37.7 million, or 12.3%, from 1999 to 2000. Operating results for 2000 were positively affected, relative to 1999, by (i) increased operational efficiency and the associated favorable impact of increased natural gas prices on operational natural gas sales in 2000, (ii) increased storage service revenues, (iii) a reduction in amortization resulting from the July 1999 change in amortization rates (see Note 5 of the accompanying Notes to Consolidated Financial Statements), (iv) reduced 2000 operations and maintenance expenses due to successful cost control measures and to the sales of certain gathering assets and offshore laterals and (v) reduced ad valorem taxes. These positive effects were partially offset by (i) reduced 2000 revenues due to the sales of certain gathering assets and offshore laterals, (ii) decreased 2000 unit revenues largely attributable to competing pipeline capacity in the upper Midwest, Natural Gas Pipeline Company of America's principal market area, and reduced transport revenue due to the sale of a marketing affiliate during 2000. In accordance with the "fee-based" aspect of our business strategy, Natural Gas Pipeline Company of America has achieved significant success extending existing contracts and obtaining new contracts for firm transportation capacity on its pipeline system. In addition to extending key capacity arrangements, we have also pursued throughput growth on Natural Gas Pipeline Company of America's system through new transportation and balancing services and by pursuing agreements to provide natural gas transportation and storage services to new and existing gas-fired electric generation facilities along the system. On October 2, 2001, we announced that Natural Gas Pipeline Company of America had signed a firm-transportation contract to provide FPL Energy, LLC, a subsidiary of FPL Group, Inc., with natural gas to power its new 1,789-megawatt electric generating facility in Kaufman County, located 20 miles east of Dallas, Texas. Under the long-term agreement, FPL Energy has subscribed for 250,000 MMBtus per day of firm capacity on the Natural Gas Pipeline Company of America system, effective with the startup of operations at the new plant in mid-year 2003. FPL Energy also agreed to extend an existing 50,000 MMBtus per day firm- transportation service contract it holds on Natural Gas Pipeline Company of America for an additional 18 years. In recent periods, Natural Gas Pipeline Company of America has contracted to supply natural gas transportation services to approximately 23 natural gas-fired electric generation facilities along its system totaling approximately 13,000 megawatts of electric generation capacity. In addition to internal growth on Natural Gas Pipeline Company of America's existing pipeline system, we are also pursuing opportunities to expand the system. Two major expansion projects under way are the Horizon Pipeline project in Northern Illinois (see Note 6 of the accompanying Notes to Consolidated Financial Statements) and the extension of Natural Gas Pipeline Company of America's system into the metropolitan east area of St. Louis. Both the Horizon Pipeline and the St. Louis extension are expected to be placed into service by summer of 2002. Substantially all of Natural Gas Pipeline Company of America's pipeline capacity is committed under firm transportation contracts ranging from one to five years. Under these contracts, over 90% of the revenues are derived from a demand charge and, therefore, are collected regardless of the volume of gas actually transported. The principal impact of the actual level of gas transported is on fuel recoveries, which are received in-kind as volumes move on the system. Approximately 71% of the total transportation volume committed under Natural Gas Pipeline Company of America's long-term firm transportation contracts in effect on January 1, 2002 had remaining terms of less than three years. Natural Gas Pipeline Company of America continues to actively pursue the renegotiation, extension and/or replacement of expiring contracts. Nicor Gas and Peoples Energy are Natural Gas Pipeline Company of America's two largest customers. Contracts representing 28% of Natural Gas Pipeline Company of America's total long-term contracted firm transport capacity as of January 1, 2002 are scheduled to expire during 2002. 27 For 2002, Kinder Morgan currently expects that Natural Gas Pipeline Company of America will experience 3-5% growth in segment earnings. This increase in earnings is expected to be derived primarily from the Horizon Pipeline and St. Louis expansions expected to come on-line, augmenting contract renewals that create a stable earnings base. In addition, incremental revenues are anticipated from new electric power generation load and, potentially, from storage capacity expansion. However, as discussed following, there are factors beyond our control that can affect our results, including developments in the regulatory arena and as yet unforeseen competitive developments. Accordingly, our actual future results may differ significantly from our projections. Our principal exposure to market variability is related to the variation in natural gas prices and basis differentials, which can affect gross margins in our Natural Gas Pipeline Company of America segment. "Basis differential" is a term that refers to the difference in natural gas prices between two locations or two points in time. These price differences can be affected by, among other things, natural gas supply and demand, available transportation capacity, storage inventories and deliverability, prices of alternative fuels and weather conditions. In recent periods, additional competitive pressures have been generated in midwest natural gas markets due to the introduction and planned introduction of pipeline capacity to bring additional supplies of natural gas into the Chicago market area, although incremental pipeline capacity to take gas out of the area has also been constructed. We have attempted to reduce our exposure to this form of market variability by pursuing long-term, fixed-rate type contract agreements to utilize the capacity on Natural Gas Pipeline Company of America's system. In addition, as discussed under "Risk Management" elsewhere in this document and in Note 15 of the accompanying Notes to Consolidated Financial Statements, we utilize a comprehensive risk management program to mitigate our exposure to changes in the market price of natural gas and associated transportation. The majority of Natural Gas Pipeline Company of America's system is subject to rate regulation under the jurisdiction of the Federal Energy Regulatory Commission. Currently, there are no material proceedings challenging the rates on any of our pipeline systems. Nonetheless, shippers on our pipelines do have rights to challenge the rates we charge under certain circumstances prescribed by applicable regulations. There can be no assurance that we will not face challenges to the rates we receive for services on our pipeline systems in the future. KINDER MORGAN RETAIL
YEAR ENDED DECEMBER 31, ------------------------------ 2001 2000 1999 -------- -------- -------- (IN THOUSANDS EXCEPT SYSTEMS THROUGHPUT) Operating Revenues................................... $285,142 $229,509 $182,912 ======== ======== ======== Gross Margin......................................... $111,063 $100,698 $ 75,648 ======== ======== ======== Segment Earnings..................................... $ 56,398 $ 49,755 $ 20,055 ======== ======== ======== Systems Throughput (Trillion Btus)................... 42.0 44.0 36.8 ======== ======== ========
Kinder Morgan Retail's segment earnings increased by $6.6 million, or 13.4%, from 2000 to 2001. Kinder Morgan Retail's operating results were positively impacted in 2001, relative to 2000, by (i) continued successful risk management of gas supply needs, which has reduced, but not eliminated, weather-related volatility in earnings (refer to the heading "Risk Management" in this Item and Note 15 of the accompanying Notes to Consolidated Financial Statements for a more detailed discussion of our risk management policies) and (ii) the inclusion, in 2001 results, of income from the Wolf Creek storage system. These positive impacts were partially offset by higher operating expenses resulting from overall system expansion. Kinder Morgan Retail's segment earnings increased by $29.7 million, or 148.1% from 1999 to 2000. Operating results for 2000 were positively impacted, relative to 1999, by (i) increased system throughput in 2000, although a portion of this increase represents volumes transported for relatively low margins, 28 (ii) increased service revenues in 2000 and (iii) reduced 2000 operating expenses. The increase in gross margins (operating revenues minus gas purchases and other costs of sales) which resulted from increased throughput volumes was principally due to increased irrigation demand in the third quarter of 2000 and increased space heating demand in the fourth quarter. Weather-related demand in Kinder Morgan Retail's service territory was affected by colder than normal weather in the fourth quarter of 2000, compared with warmer than normal weather in the fourth quarter of 1999. The reduced 2000 operating expenses resulted from (i) a reduction in advertising and marketing expenses for the Choice Gas program (unregulated sales of natural gas made to certain of Kinder Morgan Retail's utility customers), (ii) continued focus on efficient operations, (iii) reduced ad valorem and use taxes in 2000 and (iv) reduced costs for certain administrative functions due to renegotiation of a contract with a third-party service provider. For 2002, we currently expect that Kinder Morgan Retail will experience 4-6% growth in segment earnings. With a stable base of earnings due to its regulated business, as supplemented by our weather hedging program, increased earnings are expected to derive from the impact of the Citizens acquisition as discussed following and from the impact of a full year of cost savings resulting from capital projects to reduce operating costs through efficiency improvements. However, as discussed following, there are factors beyond our control that can affect our results, including developments in the regulatory arena, currently unforeseen competitive developments and weather-related impacts outside our hedging program. Accordingly, our actual future results may differ significantly from our projections. During the fourth quarter of 2001, Kinder Morgan Retail successfully completed the acquisition of natural gas distribution facilities from Citizens Communications Company (NYSE: CZN, CZB) for approximately $11 million in cash and assumed liabilities. The natural gas distribution assets serve approximately 13,400 residential, commercial and agricultural customers in Bent, Crowley, Otero, Archuleta, La Plata and Mineral Counties in Colorado. A significant portion of Kinder Morgan Retail's business is subject to rate regulation by various state and local jurisdictions in Colorado, Wyoming and Nebraska. There are currently no material proceedings challenging the rates on any of our intrastate pipeline or distribution systems. Nonetheless, there can be no assurance that we will not face challenges to the rates we receive for these services in the future. Kinder Morgan Retail is also subject to market variability in natural gas prices and basis differentials. Please refer to the discussion of basis differentials under the heading "Natural Gas Pipeline Company of America" in this Item. POWER AND OTHER
YEAR ENDED DECEMBER 31, ---------------------------- 2001 2000 1999 -------- ------- ------- (IN THOUSANDS) Operating Revenues..................................... $125,045 $80,697 $59,305 ======== ======= ======= Gross Margin........................................... $ 89,142 $61,044 $46,384 ======== ======= ======= Segment Earnings....................................... $ 63,348 $33,460 $34,379 ======== ======= =======
Our Power and Other segment earnings increased by $29.9 million, or 89.3%, from 2000 to 2001. Operating results for 2001 were positively impacted, relative to 2000, by (i) increased power plant development fee revenues of $26.8 million, principally resulting from our development of two 550-megawatt electric generating plants currently under construction in Wrightsville, Arkansas and Jackson, Michigan, (ii) increased equity in the earnings of Thermo Cogeneration Partnership, (iii) $1.9 million of increased earnings from our agreements with Kerr-McGee Gathering LLC (formerly HS Resources, Inc.), (iv) improved performance from our natural gas distribution operations in Mexico and (v) the fact that 2000 results include $2.3 million of losses related to the disposition of certain of our power turbine purchase agreements. These positive impacts were partially offset by (i) increased operations and maintenance expenses related to power plant site development, (ii) increased depreciation expense 29 from corporate computer and telecommunications equipment and (iii) the fact that 2000 results included $0.8 million of gains from asset sales. Power and Other segment earnings decreased by $0.9 million, or 2.7%, from 1999 to 2000. Operating results for 2000 were negatively impacted, relative to 1999, by (i) a decrease in earnings from equity investments largely attributable to increased fuel (natural gas) costs related to electricity generation and (ii) increased operating expenses associated with other operations, principally our agreements with Kerr-McGee Gathering LLC and certain telecommunications assets used primarily by internal business units. These negative impacts were partially offset by profits from development of the Wrightsville, Arkansas power plant. For 2002, we currently expect that our Power and Other segment will experience a decline of 20-25% in segment earnings. The power plants in Wrightsville, Arkansas and Jackson, Michigan that contributed approximately $32 million in construction fee revenues during 2001 are expected to be completed in mid 2002. The Jackson, Michigan plant is the first of six plants we agreed to construct under an agreement with The Williams Companies announced in early 2001. Several other sites have been selected, are currently under consideration or are currently in the permitting process, although there is no certainty that we will construct additional power generation facilities at these or other sites. Therefore, we have not projected additional power plant construction revenues for 2002 beyond those attributable to power plants currently under construction. In addition, our Wattenberg natural gas facility that was previously included in this segment was sold to Kerr-McGee Gathering LLC at December 28, 2001. Accordingly, there will be no future segment earnings from that asset. Given (i) the lengthy development phase, including the lengthy and uncertain permitting process that precedes actual construction of a power generation facility and (ii) the impact that projections of future electrical demand and pricing can have on the desirability, timing and locations for new power plant development, it is difficult to determine the level of future earnings for a project-driven segment such as this one. Accordingly, our actual future results may differ significantly from our projections. KINDER MORGAN TEXAS PIPELINE We transferred Kinder Morgan Texas Pipeline to Kinder Morgan Energy Partners in December of 2000. See Note 6 of the accompanying Notes to Consolidated Financial Statements for more information regarding these transactions.
YEAR ENDED DECEMBER 31, ----------------------- 2000 1999 ----------- --------- (IN THOUSANDS EXCEPT SYSTEMS THROUGHPUT) Operating Revenues.......................................... $1,747,499 $872,161 ========== ======== Gross Margin................................................ $ 81,330 $ 67,487 ========== ======== Segment Earnings............................................ $ 29,318 $ 16,554 ========== ======== Systems Throughput (Trillion Btus).......................... 654.4 575.3 ========== ========
Operating revenues for Kinder Morgan Texas Pipeline increased by $875.3 million, or 100.4%, from 1999 to 2000. This increased revenue reflects a 75% increase in the average sales price of natural gas during 2000 (the increased price of natural gas is directly reflected in the overall sales rate, of which it is a component part), together with a 17% increase in sales volumes. Gross margin (operating revenues minus gas purchases and other costs of sales) increased by $13.8 million, or 20.5%, from 1999 to 2000, as the increased operating revenues were offset approximately proportionally by the increased cost of natural gas purchased. Segment earnings increased by $12.8 million, or 77.1%, from 1999 to 2000 as the increase in gross margin discussed preceding was partially offset by increased ad valorem taxes. 30 KINDER MORGAN INTERSTATE GAS TRANSMISSION
YEAR ENDED DECEMBER 31, 1999 -------------------- (IN THOUSANDS EXCEPT SYSTEMS THROUGHPUT) Operating Revenues.......................................... $113,207 ======== Gross Margin................................................ $ 99,253 ======== Segment Earnings............................................ $ 53,630 ======== Systems Throughput (Trillion Btus).......................... $ 203.1 ========
OTHER INCOME AND (EXPENSES)
YEAR ENDED DECEMBER 31, --------------------------------- 2001 2000 1999 --------- --------- --------- (IN THOUSANDS) Interest Expense, Net............................. $(216,200) $(243,155) $(251,920) Equity in Earnings of Kinder Morgan Energy Partners: Equity in Earnings.............................. 277,504 140,913 15,733 Amortization of Excess.......................... (25,644) (27,593) (7,335) Equity in Earnings of Power Segment............... 5,299 3,669 10,511 Other Equity in Earnings (Losses)................. (5,054) (10,255) 14,140 Minority Interests................................ (36,740) (24,121) (24,845) Gains from Sales of Assets........................ 22,621 61,684 157,938 Other, Net........................................ 1,131 10,881 4,627 --------- --------- --------- $ 22,917 $ (87,977) $ (81,151) ========= ========= =========
"Other Income and (Expense)" was a net decrease to earnings of $88.0 million in 2000 and a net increase of $22.9 million in 2001. This positive change of $110.9 million was principally due to: (i) an increase of $138.5 million in equity in earnings of Kinder Morgan Energy Partners, net of associated amortization, (ii) a decrease of $27.0 million in net interest expense in 2001, reflecting reduced interest rates and reduced debt outstanding and (iii) a reduction of $6.8 million from equity in losses of equity method investees other than Kinder Morgan Energy Partners, principally TransColorado Gas Transmission Company. These favorable impacts were partially offset by (i) a decrease of $39.1 million in 2001 net gains from sales of assets, (ii) an increase of $12.6 million in expense due to minority interest in 2001, principally due to the issuance of Kinder Morgan Management shares as discussed under "Financing Activities" and (iii) a decrease of $9.8 million in income from "Other, Net" in 2001, largely due to the items included in 2000 results as discussed following. The increase of $6.8 million, or 8.4%, in net expense under "Other Income and (Expenses)" from 1999 to 2000 is principally due to decreased gains from sales of assets and reduced other equity in earnings in 2000, partially offset by higher 2000 equity in earnings of Kinder Morgan Energy Partners and increased "Other, Net." The decrease in gains from sales of assets in 2000 reflects the fact that 1999 results include (i) a gain of $127.0 million from the transfer to Kinder Morgan Energy Partners of Kinder Morgan Interstate Gas Transmission and interests in two equity method investments and (ii) a gain of $28.9 million from the sale of two offshore pipeline assets, while 2000 results include a gain of $61.6 million from the sale of Kinder Morgan Texas Pipeline to Kinder Morgan Energy Partners. The equity in earnings of Kinder Morgan Energy Partners and associated amortization during 2000 and 1999 result from our October 1999 acquisition of interests in Kinder Morgan Energy Partners and, thus, 1999 includes only one quarter of earnings on this investment while 2000 reflects earnings for the full year. The decrease in other equity in earnings from 1999 to 2000 is principally due to the sale of various equity 31 method investments. In addition, 2000 results reflect increased equity in losses of the TransColorado pipeline joint venture, which was placed in service March 31, 1999. The expense associated with "Minority Interests" in each period principally represents the costs associated with our two series of Capital Securities. These securities are described in Note 13 of the accompanying Notes to Consolidated Financial Statements. The increase in "Other, Net" from 1999 to 2000 reflects the fact that, while each period includes miscellaneous items of income and expense, 2000 results also include (i) $4.1 million due to the recovery of note receivable proceeds in excess of its carrying value and (ii) $3.9 million due to the settlement of a regulatory matter for an amount less than that previously reserved. INCOME TAXES -- CONTINUING OPERATIONS
YEAR ENDED DECEMBER 31, ----------------------------- 2001 2000 1999 -------- -------- ------- (IN THOUSANDS) Income Tax Provision.................................. $168,601 $123,017 $79,124 ======== ======== ======= Effective Tax Rate.................................... 41.4% 40.0% 36.9% ======== ======== =======
The increase of $45.6 million in the income tax provision from 2000 to 2001 is almost solely due to increased 2001 pre-tax income. The apparent increase in the effective tax rate in 2001 is due to the fact that the minority interest in the earnings of Kinder Morgan Management is presented net of its associated tax expense. The increase of $43.9 million in the income tax provision from 1999 to 2000 is comprised of (i) an increase of $34.2 million due to an increase in pretax income and (ii) an increase of $9.7 million due to an increase in the effective tax rate in 2000. The increased effective tax rate for 2000 is principally due to an increased effective rate associated with state income taxes. DISCONTINUED OPERATIONS
YEAR ENDED DECEMBER 31, ------------------------ 2000 1999 ---------- ----------- (IN THOUSANDS) Loss from Discontinued Operations, Net of Tax............... $ -- $ (50,941) ======== ========= Loss on Disposal of Discontinued Operations, Net of Tax..... $(31,734) $(344,378) ======== =========
During the third quarter of 1999, we adopted and implemented a plan to discontinue the direct marketing of non-energy products and services (principally under the "Simple Choice" brand), which activities had been carried on largely through our EN-able joint venture with PacifiCorp. During the fourth quarter of 1999, we adopted and implemented plans to discontinue the following lines of business: (i) gathering and processing of natural gas, including short-haul intrastate pipelines and providing field services to natural gas producers, (ii) wholesale marketing of natural gas and natural gas liquids and (iii) international operations. We recorded a loss of $344.4 million, representing the estimated loss to be recognized upon final disposal of these businesses, including estimated operating losses prior to disposal. During 2000, we completed the disposition of these businesses, with the exception of international operations (principally consisting of a natural gas distribution system under construction in Hermosillo, Mexico), which, in the fourth quarter of 2000, we decided to retain. Neither the decision to dispose of our international operations nor our subsequent decision to retain them had any material effect on our results of operations, commitments and contingencies, known trends or capital resources. In the fourth quarter of 2000, we recorded an incremental loss on disposal of discontinued operations of $31.7 million, representing the impact of the final disposition transactions and adjustment of previously recorded estimates. We had a remaining liability of approximately $5.2 million at December 31, 2001 associated with these discontinued operations. We do not expect significant additional financial impacts associated with these matters. Note 7 of the accompanying Notes to Consolidated Financial Statements contains certain additional financial information with respect to these discontinued operations. 32 LIQUIDITY AND CAPITAL RESOURCES The following table illustrates the sources of our invested capital. In addition to our results of operations, these balances are affected by our financing activities as discussed following.
DECEMBER 31, ------------------------------------ 2001 2000 1999 ---------- ---------- ---------- (DOLLARS IN THOUSANDS) Long-term Debt................................... $2,404,967 $2,478,983 $3,293,326 Minority Interests............................... 817,513 4,910 9,523 Common Equity.................................... 2,259,997 1,777,624 1,649,615 Capital Securities............................... 275,000 275,000 275,000 ---------- ---------- ---------- Capitalization................................. 5,757,477 4,536,517 5,227,464 Short-term Debt, Less Cash and Cash Equivalents.................................... 613,918 766,244 555,189 ---------- ---------- ---------- Invested Capital............................... $6,371,395 $5,302,761 $5,782,653 ========== ========== ========== Capitalization: Long-term Debt................................. 41.8% 54.6% 63.0% Minority Interests............................. 14.2% 0.1% 0.2% Common Equity.................................. 39.2% 39.2% 31.5% Capital Securities............................. 4.8% 6.1% 5.3% Invested Capital: Total Debt..................................... 47.4% 61.2% 66.6% Equity, Including Capital Securities and Minority Interests.......................... 52.6% 38.8% 33.4%
In addition to the direct sources of financing shown in the preceding table, we obtain financing indirectly through our ownership interests in unconsolidated entities. Our largest unconsolidated investment is in Kinder Morgan Energy Partners. As discussed in detail in Note 2 of the accompanying Notes to Consolidated Financial Statements, holders of Kinder Morgan Management shares may exchange each one of their shares for one common unit of Kinder Morgan Energy Partners owned by us and our affiliates. This exchange feature is subject to our right to settle the exchange in cash rather than common units. It was intended and expected that these securities would trade within a narrow range. During the period the Kinder Morgan Management shares have been outstanding, the difference between the market price of the Kinder Morgan Management shares and the Kinder Morgan Energy Partners common units has been minimal and, in recent periods, the Kinder Morgan Management shares have traded at a slight premium to the price of Kinder Morgan Energy Partners' common units. Accordingly, the exchange feature does not represent a significant financial asset to the holder. Kinder Morgan G.P., Inc., our subsidiary that is the general partner in Kinder Morgan Energy Partners, is obligated to support the operations and debt service payments of Kinder Morgan Energy Partners. This obligation, however, does not arise until the assets of Kinder Morgan Energy Partners have been fully utilized in meeting its own obligations and, in any event, does not extend beyond the assets of Kinder Morgan G.P., Inc. 33 We utilize equity method accounting for several investees and have interests in or obligations with respect to these entities as shown following:
At December 31, 2001 ----------------------- Incremental INVESTMENT INVESTMENT ENTITY ENTITY INVESTMENT DEBT ENTITY AMOUNT PERCENT ASSETS(1) DEBT OBLIGATION RESPONSIBILITY ------ ---------- ---------- --------- ------ ----------- -------------- (Dollars in millions) TransColorado Gas Transmission Company(2).... $134.3 50.0% $ 300 $ -- $ -- $ -- Horizon Pipeline Company..... -- 50.0% 79 45(3) --(4) --(5) Ft. Lupton Power Plant....... 138.9 49.5% 186 149(6) -- -- Igasamex..................... 6.1 21.0% 18 5 -- 1 Kinder Morgan Energy Partners, L.P.............. 1,336.0 20.3% 6,733 2,792 -- 522(7)
- --------------- (1) At recorded value, in each case, consisting principally of property, plant and equipment. (2) There is litigation with respect to this investment; see "Legal and Environmental" elsewhere herein. (3) Currently recorded as payable to the partners of Horizon Pipeline. Total project is expected to be 3rd party project financed at 60% debt and 40% equity. (4) No incremental investment is necessary unless project financing is not obtained. The maximum incremental investment obligation possible is $17 million. (5) Expected to be non-recourse to owners. (6) Non-recourse to owners. (7) We would only be obligated if Kinder Morgan Energy Partners, L.P. and/or its assets cannot satisfy its obligations.
AMOUNT OF COMMITMENT EXPIRATION PER PERIOD ----------------------------------------------------- LESS THAN TOTAL 1 YEAR 2-3 YEARS 4-5 YEARS AFTER 5 YEARS ---------- --------- ----------- ----------- ------------- (IN THOUSANDS) CONTRACTUAL OBLIGATIONS Long-Term Debt, including current maturities......................... $2,619,375 $206,267 $502,534 $507,284 $1,403,290 Operating Leases..................... 62,055 9,697 18,504 18,100 15,754 Commercial Paper Outstanding......... 423,785 423,785 Kinder Morgan -- Obligated Mandatorily Redeemable Preferred Capital Trust Securities of Subsidiary Trust Holding Solely Debentures of Kinder Morgan........ 275,000 275,000 Incremental Investment in Power Plants............................. 118,000 118,000 ---------- -------- -------- -------- ---------- Total Contractual Cash Obligations... $3,498,215 $757,749 $521,038 $525,384 $1,694,044 ========== ======== ======== ======== ========== OTHER COMMERCIAL COMMITMENTS: Standby Letters of Credit............ $ 10,384 $ 10,384 $ -- $ -- $ -- ========== ======== ======== ======== ==========
We have sufficient liquidity to satisfy our near-term obligations through the combination of free cash flow and our credit facilities totaling $900 million. 34
CONTINGENCY AMOUNT OF CONTINGENT LIABILITY ----------- ------------------------------ CONTINGENT LIABILITIES: Guarantor of the Bushton Gas Default by ONEOK, Inc. Averages $23 million per year Processing Plant Lease through 2012; Total $247.4 million Assumption of Power Plant Long-term Financing not Approximately $250 million Note obtained by March 29, 2002 Power Plant Incremental Operational Performance $3 to 8 million per year for Investment 16 years Power Plant Incremental Cash Flow Performance Up to a total of $25 million Investment beginning in the 17th year following commercial operations
CASH FLOWS The following discussion of cash flows should be read in conjunction with the accompanying Consolidated Statements of Cash Flows and related supplemental disclosures. All highly liquid investments purchased with an original maturity of three months or less are considered to be cash equivalents. NET CASH FLOWS FROM OPERATING ACTIVITIES "Net Cash Flows Provided by Operating Activities" increased from $167.1 million in 2000 to $437.3 million in 2001, an increase of $270.2 million, or 162%. This increase is primarily due to (i) a decrease of $106.7 million in cash flows used for discontinued operations, primarily attributable to the termination of our receivables sales program (see "Net Cash Flows from Financing Activities" following), (ii) a $117.5 million increase in cash distributions received in 2001 attributable to our interest in Kinder Morgan Energy Partners (see Note 3 of the accompanying Notes to Consolidated Financial Statements and the discussion following) and (iii) a $20.8 million increase in cash inflow in 2001 due to decreased deferred purchase gas costs resulting from lower natural gas prices. "Net Cash Flows Provided by Operating Activities" decreased from $321.2 million in 1999 to $167.1 million in 2000, a decline of $154.1 million, or 48%. This decline is primarily due to an increase in cash flows used for discontinued operations, which increased from a source of $94.5 million in 1999 to a use of $110.4 million in 2000, a $204.9 million increased use of cash reflecting (i) $124.7 million of cash outflow in 2000 attributable to the termination of our receivable sale program and (ii) $124.7 million of cash inflow in 1999 attributable to the receivable sale program (see "Net Cash Flows from Financing Activities" following). The decline in "Net Cash Flows Provided by Operating Activities" for discontinued operations was partially offset by an increase in cash flows provided by continuing operations, which increased from a source of $226.7 million in 1999 to a source of $277.5 million in 2000. This $50.8 million of increased cash flow is primarily due to (i) $121.3 million of cash distributions received in 2000 attributable to our interest in Kinder Morgan Energy Partners and (ii) a decrease in cash used in 2000 to make interest payments, reflecting the decreased average debt balance outstanding. Partially offsetting this increase was an increase of $97.3 million in cash used for working capital in 2000, primarily due to January 2000 payments associated with December 1999 gas supply purchases. In general, distributions from Kinder Morgan Energy Partners are declared in the month following the end of the quarter to which they apply and are paid in the month following the month of declaration to the general partner and unit holders of record as of the end of the month of declaration. Therefore, the accompanying Statements of Consolidated Cash Flows for 2001 and 2000 reflect the receipt of a total of $238.8 million and $121.3 million, respectively, of cash distributions from Kinder Morgan Energy Partners for the fourth quarter of 2000 and the first nine months of 2001, and for the fourth quarter of 1999 and the first nine months of 2000, respectively. The cash distributions attributable to our interest for the three months and twelve months ended December 31, 2001 total $70.3 million and $264.5 million, respectively. 35 The cash distributions attributable to our interest for the three months and twelve months ended December 31, 2000 totaled $44.5 million and $149.9 million, respectively. The increase in distributions during 2000 and 2001 reflects, among other factors, acquisitions made by Kinder Morgan Energy Partners and its results of operations. Summarized financial information for Kinder Morgan Energy Partners is contained in Note 20 of the accompanying Notes to Consolidated Financial Statements. NET CASH FLOWS FROM INVESTING ACTIVITIES "Net Cash Flows Provided by (Used in) Investing Activities" decreased from a source of $498.7 million in 2000 to a use of $1.3 billion in 2001, a net decrease of $1.8 billion. This decrease is principally due to (i) an outflow of $991.9 million in 2001 for additional investment in Kinder Morgan Energy Partners, (ii) a $500.3 million decrease due to the fact that 2000 cash flows included proceeds from our December 1999 and December 2000 transfers of certain assets and interests to Kinder Morgan Energy Partners, (iii) an outflow of $298.0 million in 2001 for investments in power plant facilities, partially offset by proceeds of $247.0 million received in 2001 from the sale of our investment in the Jackson, Michigan power plant facilities, (iv) an outflow of $104.7 million in 2001 for additional investment in TransColorado Gas Transmission Company and (v) a $128.4 million decrease in cash flows from discontinued investing activities in 2001 as a result of (1) $25.7 million received in 2001 for discontinued operations sold during 2000 and (2) for 2000, an inflow of $163.9 million received for discontinued operations sold, partially offset by an outflow of $59.9 million for a lease buyout on assets included in discontinued operations prior to divestiture. Please refer to Notes 6 and 7 of the accompanying Notes to Consolidated Financial Statements for additional information regarding these transactions. "Net Cash Flows Provided by (Used in) Investing Activities" decreased from $1.02 billion in 1999 to $498.7 million in 2000, a decline of $521.5 million principally due to the sale of approximately $1.1 billion of government securities during 1999, with the proceeds utilized to repay a short-term note assumed in conjunction with the January 1998 acquisition of MidCon Corp. Partially offsetting this decrease was (i) $500.3 million of cash received during 2000 from the sale of certain interests and assets to Kinder Morgan Energy Partners and (ii) cash flows of discontinued investing activities increasing from a use of $46.6 million in 1999 to a source of $154.2 million in 2000, principally a result of the $163.9 million of proceeds received in 2000 from the sale to ONEOK, Inc. of gathering and processing businesses in Oklahoma, Kansas and West Texas. Total proceeds received in 2001 from asset sales were $32.8 million, of which $25.7 million represented proceeds from the 2000 sale of our gathering and processing businesses in Oklahoma, Kansas and West Texas as well as our marketing and trading business to ONEOK. During the year 2000, major asset dispositions included (i) Kinder Morgan Texas Pipeline, the Casper and Douglas Natural Gas Gathering and Processing Systems, our 50 percent interest in Coyote Gas Treating, LLC and our 25 percent interest in Thunder Creek Gas Services, L.L.C. to Kinder Morgan Energy Partners, (ii) gathering and processing businesses in Oklahoma, Kansas and West Texas as well as our marketing and trading business to ONEOK, (iii) three natural gas gathering systems and a natural gas processing facility to WBI Holdings, Inc. and (iv) certain assets within Wildhorse Energy Partners, LLC to Tom Brown, Inc. Total proceeds received in 2000 from asset sales were $730.3 million of which $330 million represented proceeds from the 1999 transfer of assets to Kinder Morgan Energy Partners. Major asset dispositions during 1999 included (i) Kinder Morgan Interstate Gas Transmission, Kinder Morgan Trailblazer LLC and our interest in Red Cedar Gathering Company to Kinder Morgan Energy Partners, (ii) all of our major offshore assets in the Gulf of Mexico area, including our interests in Stingray Pipeline Company L.L.C. and West Cameron Dehydration Company L.L.C., and the HIOS and UTOS offshore pipeline systems and (iii) MidCon Gas Products of New Mexico Corp. Total proceeds received in 1999 from asset sales were $111.1 million. Notes 6 and 7 of the accompanying Notes to Consolidated Financial Statements and "Net Cash Flows from Financing Activities" following contain more information concerning these transactions. 36 NET CASH FLOWS FROM FINANCING ACTIVITIES "Net Cash Flows Provided By (Used In) Financing Activities" increased from a use of $550.3 million in 2000 to a source of $711.6 million in 2001, an increase of $1.3 billion. This increase is principally due to (i) net proceeds of $888.1 million in 2001 from the issuance of membership shares by Kinder Morgan Management (see Note 2 of the accompanying Notes to Consolidated Financial Statements), (ii) $495.7 million of cash used in 2001 for the early extinguishment of three series of debt securities (see Note 13 of the accompanying Notes to Consolidated Financial Statements), (iii) $265.7 million of cash used in 2001 to repurchase a portion of our outstanding common stock, (iv) proceeds of $460.4 million in 2001 from the issuance of 13,382,474 shares of additional common stock due to the maturity of our Premium Equity Participating Security Units, primarily offset by cash used for the retirement of the $400 million of 6.45% Series of Senior Notes (see Note 13 of the accompanying Notes to Consolidated Financial Statements) and (v) a change in net short-term borrowing of $798.2 million principally due to (1) a reduction in net short-term borrowing in 2000 facilitated by cash inflows from investing activities (see "Net Cash Flows from Investing Activities" above) and (2) an increase in net short-term borrowing in 2001, principally to fund a portion of the early extinguishment of long-term debt and the reacquisition of a portion of our outstanding common shares, in each case as discussed preceding. "Net Cash Flows Provided by (Used in) Financing Activities" decreased from a use of approximately $1.3 billion in 1999 to a use of $550.3 million in 2000, a decline of approximately $786.7 million. This decrease was principally due to the first-quarter 1999 repayment of a $1.39 billion short-term note as discussed preceding, partially offset by increased short-term borrowings during the same period, as well as reduced cash payments for dividends in 2000. SHORT-TERM LIQUIDITY AND FINANCING TRANSACTIONS Our principal sources of short-term liquidity are our revolving bank facilities, our commercial paper program (which is supported by our revolving bank facilities) and cash provided by operations. As of December 31, 2001, we had available a $500 million 364-day facility dated October 23, 2001, and a $400 million amended and restated five-year revolving credit agreement dated January 30, 1998. These bank facilities can be used for general corporate purposes, including as backup for our commercial paper program. At December 31, 2001, we had $423.8 million of bank borrowings and commercial paper issued and outstanding. The corresponding amount outstanding was $477.7 million at February 1, 2002. After inclusion of applicable letters of credit, the remaining available borrowing capacity under the bank facilities was $465.8 million and $411.9 million at December 31, 2001 and February 1, 2002, respectively. The bank facilities include covenants that are common in such arrangements. For example, the $500 million facility requires consolidated debt to be less than 68% of consolidated total capitalization. The $400 million facility requires that consolidated debt must be less than 67% of consolidated total capitalization. Both of the bank facilities require the debt of consolidated subsidiaries to be less than 10% of our consolidated debt and require the consolidated debt of each material subsidiary to be less than 65% of our consolidated total capitalization. The $400 million facility requires our consolidated net worth (inclusive of trust preferred securities) be at least $1.236 billion plus 50 percent of consolidated net income earned for each fiscal quarter beginning with the last quarter of 1998. The $500 million facility requires our consolidated net worth (inclusive of trust preferred securities) be at least $1.236 billion plus 50 percent of consolidated net income earned for each fiscal quarter beginning with the last quarter of 1999. Our short-term debt of $630.1 million at December 31, 2001 consisted of (i) $423.8 million of borrowings under our commercial paper program, (ii) $200 million of Floating Rate Notes due October 10, 2002 and (iii) $6.3 million of miscellaneous current maturities of long-term debt. Our current liabilities, net of our current assets, represents an additional short-term obligation of approximately $67.4 million. Given our expected cash flows from operations and our unused debt capacity as discussed preceding, including our five-year revolving credit facility, and based on our projected cash needs in the near term, we do not expect any liquidity issues in the foreseeable future. 37 On February 14, 2002, we paid a cash dividend on our common stock of $0.05 per share to common stockholders of record as of January 31, 2002. On November 30, 2001, our Premium Equity Participating Security Units matured, which resulted in our receipt of $460 million in cash and our issuance of 13,382,474 shares of additional common stock. We used the cash proceeds to retire the $400 million of 6.45% Series of Senior Notes that became due on the same date and a portion of our short-term borrowings then outstanding. On October 10, 2001, we issued $200 million of Floating Rate Notes due October 10, 2002 in an offering made pursuant to Rule 144A of the regulations of the Securities and Exchange Commission. These notes bear interest at the three-month London Interbank Offered Rate (LIBOR) plus 95 basis points, with interest paid quarterly. The proceeds from the offering were used to retire a portion of outstanding short-term borrowings. On September 10, 2001, we retired our $45 million of 9.625% Series Sinking Fund Debentures due March 1, 2021, utilizing incremental short-term borrowings. In March 2001, we retired (i) our $400 million of Reset Put Securities due March 1, 2021 and (ii) our $20 million of 9.95% Series Sinking Fund Debentures due 2020, utilizing a combination of cash and incremental short-term borrowings. In conjunction with these early extinguishments of debt, we recorded extraordinary losses of $13.6 million (net of associated tax benefit of $9.0 million). These losses are included under the caption, "Extraordinary Item, Loss on Early Extinguishment of Debt" in the accompanying Consolidated Statements of Operations. On August 14, 2001, we announced a plan to repurchase $300 million of our outstanding common stock under a program that was largely completed by the end of 2001. At the trading price at the time of the announcement, the $300 million represented approximately 5.7 million shares, or about 4.4 percent of the shares outstanding. As of December 31, 2001, we had repurchased approximately $270.4 million (5,294,800 shares) of our outstanding common stock under the program, and an additional $33.5 million was repurchased in January 2002, completing the previously announced plan. On February 5, 2002, we announced that our Board of Directors had approved expanding the repurchase plan to a total of $400 million. As further described under "Risk Management" following, in August 2001, we entered into $1 billion face value of fixed-to-floating interest rate swaps, effectively converting the interest expense associated with two of our fixed-rate debt issues to a floating rate based on the three-month LIBOR. These swaps are accounted for as fair value hedges under Statement of Financial Accounting Standards ("SFAS") No. 133, Accounting for Derivative Instruments and Hedging Activities. In May 2001, Kinder Morgan Management, one of our indirect subsidiaries, issued and sold its shares in an underwritten initial public offering. The net proceeds from the offering were used by Kinder Morgan Management to buy i-units from Kinder Morgan Energy Partners for $991.9 million. Upon purchase of the i-units, Kinder Morgan Management became a partner in Kinder Morgan Energy Partners and assumed the responsibility to manage and control its business and affairs. The i-units are a class of Kinder Morgan Energy Partners' limited partner interests that have been, and will be, issued only to Kinder Morgan Management. In the initial public offering, 10 percent of Kinder Morgan Management's shares were purchased by us, with the balance purchased by the public. The equity interest in Kinder Morgan Management (which we consolidate for financial reporting purposes) purchased by the public created an additional minority interest on our balance sheet of $892.7 million at the time of the transaction. We have certain rights and obligations with respect to these securities, including an obligation to purchase the Kinder Morgan Management shares or exchange them for Kinder Morgan Energy Partners, L.P. common units that we own or for cash. In September 1999, we established an accounts receivable sales facility that provided up to $150 million of additional liquidity. In accordance with this agreement, we received proceeds of $150 million on September 30, 1999. Cash flows associated with this facility are included with "Cash flows from Operating Activities" in the accompanying Consolidated Statements of Cash Flows in 1999 and 2000. In February 2000, we reduced our participation in this receivables sales program by $124.9 million, 38 principally as a result of our then-pending disposition of our wholesale gas marketing business. On April 25, 2000, we repaid the residual balance and terminated the agreement. On January 4, 1999, we repaid a short-term note for $1.4 billion which we had assumed in connection with the early-1998 acquisition of MidCon Corp. and that had been payable to Occidental Petroleum Corporation. The note was repaid using the proceeds of approximately $1.1 billion from the sale of U.S. government securities that had been held as collateral, with the balance of the funds provided by an increase in short-term borrowings. CAPITAL EXPENDITURES AND COMMITMENTS Capital expenditures in 2001 were $124.2 million. The 2002 capital expenditure budget totals approximately $145.8 million, before expenditures that may be made on the Horizon Pipeline project. We expect that funding for the capital expenditure budget will be provided from internal sources and, if necessary, incremental borrowings. Approximately $16.9 million of this amount had been committed for the purchase of plant and equipment at December 31, 2001. Additional information on commitments is contained in Note 18 of the accompanying Notes to Consolidated Financial Statements. LITIGATION AND ENVIRONMENTAL Our anticipated environmental capital costs and expenses for 2002, including expected costs for remediation efforts, are approximately $6 million, compared to approximately $4 million of such costs and expenses incurred in 2001. A substantial portion of our environmental costs are either recoverable through insurance and indemnification provisions or have previously recorded liabilities associated with them. We had an established environmental reserve of approximately $18 million at December 31, 2001 to address remediation issues associated with approximately 35 projects. This reserve is primarily established to address and clean up soil and ground water impacts from former releases to the environment at facilities we have acquired. Reserves for each project are established by reviewing existing documents, conducting interviews and performing site inspections to determine the overall size and impact to the environment. Reviews are made on a quarterly basis to determine the status of the cleanup, the costs associated with the effort and to identify if the reserve allocation is appropriately valued. In assessing environmental exposure in conjunction with proposed acquisitions, we perform thorough reviews of all records relating to environmental issues, conduct site inspections, interview employees, and, if necessary, collect soil and groundwater samples. After consideration of reserves established, we believe that costs for environmental remediation and ongoing compliance with these regulations will not have a material adverse effect on our cash flows, financial position or results of operations or diminish our ability to operate our businesses. However, there can be no assurances that future events, such as changes in existing laws, the promulgation of new laws, or the development of new facts or conditions will not cause us to incur significant unanticipated costs. Refer to Notes 10(A) and 10(B) of the accompanying Consolidated Financial Statements for additional information on our pending litigation and environmental matters. We believe we have established adequate reserves such that the resolution of pending litigation and environmental matters will not have a material adverse impact on our business, cash flows, financial position or results of operations. REGULATION See Note 9 of the accompanying Notes to Consolidated Financial Statements for information regarding regulatory matters. RISK MANAGEMENT The following discussion should be read in conjunction with Note 15 of the accompanying Notes to Consolidated Financial Statements, which contains additional information on our risk management activities. 39 Effective January 1, 2001, we adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 137, Accounting for Derivative Instruments and Hedging Activities -- Deferral of the Effective Date of FASB Statement No. 133 and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, collectively, "Statement 133." Statement 133 established accounting and reporting standards requiring that every derivative financial instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. Statement 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. If the derivatives meet those criteria, Statement 133 allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company formally designate a derivative as a hedge and document and assess the effectiveness of derivatives associated with transactions that receive hedge accounting. We enter into derivative contracts solely for the purpose of hedging exposures that accompany our normal business activities. As a result of the adoption of Statement 133, the fair value of our derivative financial instruments utilized for hedging activities as of January 1, 2001 (a loss of $11.9 million) was reported as accumulated other comprehensive income. In accordance with the provisions of Statement 133, we designated these instruments as hedges of various exposures as discussed following, and we test the effectiveness of changes in the value of these hedging instruments with the risk being hedged. Hedge ineffectiveness is recognized in income in the period in which it occurs. We enter into these transactions only with counterparties whose debt securities are rated investment grade by the major rating agencies. In general, the risk of default by these counterparties is low. However, we recently experienced a loss as discussed following. During the fourth quarter of 2001, we determined that Enron Corp. was no longer likely to honor the obligations it had to us in conjunction with derivatives we were accounting for as hedges under Statement 133. Upon making that determination, we (i) ceased to account for those derivatives as hedges, (ii) entered into new derivative transactions with other counterparties to replace our position with Enron, (iii) designated the replacement derivative positions as hedges of the exposures that had been hedged with the Enron positions and (iv) recognized a $5.0 million pre-tax loss (included with "General and Administrative Expenses" in the accompanying Consolidated Statement of Operations for 2001) in recognition of the fact that it was unlikely that we would be paid the amounts then owed under the contracts with Enron. While we enter into derivative transactions only with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that additional losses will result from counterparty credit risk in the future. Our businesses require that we purchase, sell and consume natural gas. Specifically, we purchase, sell and/or consume natural gas (i) to serve our regulated natural gas distribution sales customers, (ii) to serve certain of our retail natural gas distribution customers in areas where regulatory restructuring has provided for competition in natural gas supply, for customers who have selected the Company as their supplier of choice under our "Choice Gas" program, (iii) as fuel in our Colorado power generation facilities, (iv) as fuel for compressors located on Natural Gas Pipeline Company of America's pipeline system and (v) for operational sales of gas by Natural Gas Pipeline Company of America. With respect to item (i), we have no commodity risk because the regulated retail gas distribution regulatory structure provides that actual gas cost is "passed-through" to our customers. With respect to item (iii), only one of these power generation facilities is not covered by a long-term, fixed price gas supply agreement at a level sufficient for the current and projected capacity utilization. With respect to item (iv), this fuel is supplied by in-kind fuel recoveries that are part of the transportation tariff. Items (ii), (v) and the one power facility included under item (iii) that is not covered by a long-term fixed-price natural gas supply agreement, give rise to natural gas commodity price risk which we have chosen to substantially mitigate through our risk management program. We provide this mitigation through the use of financial derivative products, and we do not utilize these derivatives for any purpose other than risk mitigation. 40 Under our Choice Gas program, customers in certain areas served by Kinder Morgan Retail are allowed to choose their natural gas supplier from a list of qualified suppliers, although the transportation of the natural gas to the homes and businesses continues to be provided by Kinder Morgan Retail in all cases. When those customers choose an affiliate of Kinder Morgan Retail as their supplier, we enter into agreements providing for sales of gas to these customers during a one-year period at fixed prices per unit, but variable volumes. We mitigate the risk associated with these anticipated sales of gas by purchasing natural gas futures contracts on the New York Mercantile Exchange ("NYMEX") and, as applicable, over-the-counter basis swaps to mitigate the risk associated with the difference in price changes between Henry Hub (NYMEX) basis and the expected physical delivery location. In addition, we mitigate a portion of the volumetric risk through the purchase of over-the-counter natural gas options. The time period covered by this risk management strategy does not extend beyond one year. With respect to the power generation facility described above that is not covered by an adequately sized, fixed-price gas supply contract, we are exposed to changes in the price of natural gas as we purchase it to use as fuel for the electricity-generating turbines. In order to mitigate this exposure, we purchase natural gas futures on the NYMEX and, as discussed above, over-the-counter basis swaps on the NYMEX, in amounts representing our expected fuel usage in the near term. In general, we do not hedge this exposure for periods longer than one year. With respect to operational sales of natural gas made by Natural Gas Pipeline Company of America, we are exposed to risk associated with changes in the price of natural gas during the periods in which these sales are made. We mitigate this risk by selling natural gas futures and, as discussed above, over-the-counter basis swaps, on the NYMEX in the periods in which we expect to make these sales. In general, we do not hedge this exposure for periods in excess of 18 months. We use a Value-at-Risk model to measure the risk of price changes in the natural gas and natural gas liquids markets. Value-at-Risk is a statistical measure of how much the marked-to-market value of a portfolio could change during a period of time, within a certain level of statistical confidence. We use a closed form model to evaluate risk on a daily basis. Our Value-at-Risk computations use a confidence level of 97.7 percent for the resultant price movement and a holding period of one day chosen for the calculation. The confidence level used means that there is a 97.7 percent probability that the mark-to-market losses for a single day will not exceed the Value-at-Risk amount presented. Instruments evaluated by the model include forward physical gas, storage and transportation contracts and financial products including commodity futures and options contracts, fixed price swaps, basis swaps and over-the-counter options. During 2001, Value-at-Risk reached a high of $9.5 million and a low of $6.5 million. Value-at-Risk at December 31, 2001, was $7.7 million and, based on quarter-end values, averaged $8.0 million for 2001. Our calculated Value-at-Risk exposure represents an estimate of the reasonably possible net losses that would be recognized on our portfolio of derivatives assuming hypothetical movements in future market rates, and is not necessarily indicative of actual results that may occur. It does not represent the maximum possible loss or any expected loss that may occur, since actual future gains and losses will differ from those estimated. Actual gains and losses may differ from estimates due to actual fluctuations in market rates, operating exposures and the timing thereof, as well as changes in our portfolio of derivatives during the year. During 2001, all of our natural gas derivative activities were designated and qualified as cash flow hedges. We recognized approximately $5,000 of pre-tax loss during 2001 as a result of ineffectiveness of these hedges, which amount is reported within the caption "Gas Purchases and Other Costs of Sales" in the accompanying Consolidated Statement of Income for the year ended December 31, 2001. There was no component of these derivative instruments' gain or loss excluded from the assessment of hedge effectiveness. As the hedged sales and purchases take place and we record them into earnings, we will also reclassify the gains and losses included in accumulated other comprehensive income into earnings. We expect to reclassify into earnings, during 2002, substantially all of the accumulated other comprehensive income balance of $9.8 million, representing unrecognized net gains on derivative activities at 41 December 31, 2001. During 2001, we reclassified no gains or losses into earnings as a result of the discontinuance of cash flow hedges due to a determination that the forecasted transactions would no longer occur by the end of the originally specified time period. We also provide certain administrative risk management services to Kinder Morgan Energy Partners, although Kinder Morgan Energy Partners retains the obligations and rights arising from all derivative transactions entered into on its behalf. In order to maintain a cost effective capital structure, it is our policy to borrow funds utilizing a mixture of fixed-interest-rate and floating-interest-rate debt. In August 2001, in order to move closer to a mix of 50% fixed, 50% floating, we entered into fixed-to-floating interest rate swap agreements with a notional principal amount of $1.0 billion. These agreements effectively converted the interest expense associated with our 6.65% senior notes and our 7.25% debentures from fixed rates to floating rates based on three-month LIBOR plus a credit spread. These swaps have been designated as fair value hedges as defined by Statement 133. These swaps meet the conditions required to assume no ineffectiveness under Statement 133 and, therefore, we have accounted for them utilizing the "shortcut" method prescribed for fair value hedges. Accordingly, the carrying value of the swap is adjusted to its fair value as of each reporting period, with an offsetting entry to adjust the carrying value of the debt whose fair value is being hedged. We record interest expense equal to the floating rate payments, which is accrued monthly and paid semi-annually. Based on short-term borrowings outstanding and the long-term debt effectively converted to floating rate debt as a result of the swap discussed above, at December 31, 2001, the market risk related to a one percent change in interest rates would result in a $16.5 million annual impact on pre-tax income. RECENT ACCOUNTING PRONOUNCEMENTS Statement of Financial Accounting Standards No. 141 supercedes Accounting Principles Board Opinion No. 16 and requires that all transactions fitting the description of a business combination be accounted for using the purchase method and prohibits the use of the pooling of interests for all business combinations initiated after June 30, 2001. The Statement also modifies the accounting for the excess of fair value of net assets acquired as well as intangible assets acquired in a business combination. The provisions of this statement apply to all business combinations initiated after June 30, 2001, and all business combinations accounted for by the purchase method that are completed after July 1, 2001. This Statement requires disclosure of the primary reasons for a business combination and the allocation of the purchase price paid to the assets acquired and liabilities assumed by major balance sheet caption. In June 2001, the FASB issued SFAS No. 142, Goodwill and Other Intangible Assets. This Statement addresses financial accounting and reporting for (i) intangible assets acquired individually or with a group of other assets (but not those acquired in a business combination) at acquisition and (ii) goodwill and other intangible assets subsequent to their acquisition. This Statement supersedes APB Opinion No. 17, Intangible Assets. Under the provisions of this Statement, if an intangible asset is determined to have an indefinite useful life, it shall not be amortized until its useful life is determined to be no longer indefinite. An intangible asset that is not subject to amortization shall be tested for impairment annually, or more frequently if events or changes in circumstances indicate that the asset might be impaired. Goodwill will not be amortized. Goodwill will be tested for impairment on an annual basis and between annual tests in certain circumstances at a level of reporting referred to as a reporting unit. This Statement is required to be applied starting with fiscal years beginning after December 15, 2001. Goodwill and intangible assets acquired after June 30, 2001 will be subject immediately to the nonamortization and amortization provisions of this Statement. At December 31, 2001, we had approximately $25 million of goodwill recorded in conjunction with the 1998 acquisition of the Thermo Companies. In accordance with the provisions of SFAS No. 142, we will complete our analysis of that goodwill balance for impairment no later than June 30, 2002 and will record any indicated impairment during 2002. In addition, we have a significant amount of "excess investment" or "equity method goodwill," principally as a result of our investment in Kinder Morgan Energy Partners. As provided in SFAS No. 142, this type of investment will continue to be tested for impairment in accordance with the 42 provisions of Accounting Principles Board Opinion No. 18, The Equity Method of Accounting for Investments in Common Stock. We estimate that the reduction in amortization expense resulting from the cessation of amortization of both the goodwill and the equity method goodwill will result in $0.13 of earnings per diluted common share in 2002. In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations. This Statement addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. This Statement requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. This Statement contains disclosure requirements that provide descriptions of asset retirement obligations and reconciliations of changes in the components of those obligations. This Statement is effective for financial statements issued for fiscal years beginning after June 15, 2002. Earlier applications are encouraged. We have not yet quantified the impacts of adopting this Statement on our financial position or results of operations. In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. This Statement addresses financial accounting and reporting for the impairment or disposal of long-lived assets. This Statement retains the requirements to (i) recognize an impairment loss only if the carrying amount of a long-lived asset is not recoverable from its undiscounted cash flows and (ii) measure an impairment loss as the difference between the carrying amount and fair value of the asset. This Statement removes goodwill from its scope, eliminating the requirement to allocate goodwill to long-lived assets to be tested for impairment. This Statement requires that a long-lived asset to be abandoned, exchanged for a similar productive asset, or distributed to owners in a spin-off be considered held and used until it is disposed of. This Statement requires the accounting model for long-lived assets to be disposed of by sale be used for all long-lived assets, whether previously held and used or newly acquired. Discontinued operations are no longer measured on a net realizable value basis, and future operating losses are no longer recognized before they occur. This Statement broadens the presentation of discontinued operations in the income statement to include a component of an entity (rather than a segment of a business). A component of an entity comprises operations and cash flows that can be clearly distinguished, operationally and for financial reporting purposes, from the rest of the entity. The provisions of this Statement are effective for financial statements issued for fiscal years beginning after December 15, 2001, and interim periods within those fiscal years, with early application encouraged. The provisions of this Statement generally are to be applied prospectively. INFORMATION REGARDING FORWARD-LOOKING STATEMENTS This filing includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as "anticipate," "believe," "intend," "plan," "projection," "forecast," "strategy," "position," "continue," "estimate," "expect," "may," "will," or the negative of those terms or other variations of them or by comparable terminology. In particular, statements, express or implied, concerning future operating results or the ability to generate sales, income or cash flow are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. The future results of our operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from those in the forward-looking statements include but are not limited to the following: - price trends, stability and overall demand for natural gas and electricity in the United States; economic activity, weather, alternative energy sources, conservation and technological advances that may affect price trends and demand; 43 - national, international, regional and local economic, competitive and regulatory conditions and developments; - the various factors which affect Kinder Morgan Energy Partners' ability to maintain or increase its level of earnings and distributions; - our ability to integrate any acquired operations into our existing operations; - changes in laws or regulations, third-party relationships and approvals, decisions of courts, regulators and governmental bodies that may affect our business or our ability to compete; - our ability to achieve cost savings and revenue growth; - conditions in capital markets; - rates of inflation; - interest rates; - political and economic stability of oil producing nations; - the pace of deregulation of retail natural gas and electricity; - acts of sabotage and terrorism for which insurance is not available at reasonable premiums; - the timing and extent of changes in commodity prices for oil, natural gas, electricity and certain agricultural products; and - the timing and success of business development efforts. You should not put an undue reliance on forward-looking statements. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. Information required by this item is in Item 7 under the heading "Risk Management." 44 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. INDEX
PAGE ----- Report of Independent Accountants........................... 46 Consolidated Statements of Operations....................... 47 Consolidated Statements of Comprehensive Income............. 48 Consolidated Balance Sheets................................. 49 Consolidated Statements of Stockholders' Equity............. 50 Consolidated Statements of Cash Flows....................... 51 Notes to Consolidated Financial Statements.................. 52-91 Selected Quarterly Financial Data (unaudited)............... 92-93
45 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Stockholders of Kinder Morgan, Inc. In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Kinder Morgan, Inc. (formerly K N Energy, Inc.) and its subsidiaries at December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule appearing under Item 14(a)(2) on page 95 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. As discussed in Note 15 to the financial statements, the Company changed its method of accounting for derivative instruments and hedging activities effective January 1, 2001. /s/ PRICEWATERHOUSECOOPERS LLP Houston, Texas February 15, 2002 46 CONSOLIDATED STATEMENTS OF OPERATIONS KINDER MORGAN, INC. AND SUBSIDIARIES
YEAR ENDED DECEMBER 31, ------------------------------------ 2001 2000 1999 ---------- ---------- ---------- (IN THOUSANDS EXCEPT PER SHARE AMOUNTS) OPERATING REVENUES: Natural Gas Transportation and Storage...................... $ 645,369 $ 596,774 $ 745,179 Natural Gas Sales........................................... 301,994 1,965,633 1,004,097 Other....................................................... 107,555 117,315 87,092 ---------- ---------- ---------- Total Operating Revenues................................ 1,054,918 2,679,722 1,836,368 ---------- ---------- ---------- OPERATING COSTS AND EXPENSES: Gas Purchases and Other Costs of Sales...................... 339,353 1,926,068 1,050,250 Operations and Maintenance.................................. 126,564 164,286 184,888 General and Administrative.................................. 70,386 58,087 85,591 Depreciation and Amortization............................... 108,290 108,165 147,933 Taxes, other than Income Taxes.............................. 26,006 27,973 34,561 Merger-related and Severance Costs.......................... -- -- 37,443 ---------- ---------- ---------- Total Operating Costs and Expenses...................... 670,599 2,284,579 1,540,666 ---------- ---------- ---------- OPERATING INCOME............................................ 384,319 395,143 295,702 ---------- ---------- ---------- OTHER INCOME AND (EXPENSES): Kinder Morgan Energy Partners: Equity in Earnings........................................ 277,504 140,913 15,733 Amortization of Excess Investment......................... (25,644) (27,593) (7,335) Equity in Earnings (Losses) of Other Equity Investments..... 245 (6,586) 24,651 Interest Expense, Net....................................... (216,200) (243,155) (251,920) Minority Interests.......................................... (36,740) (24,121) (24,845) Other, Net.................................................. 23,752 72,565 162,565 ---------- ---------- ---------- Total Other Income and (Expenses)....................... 22,917 (87,977) (81,151) ---------- ---------- ---------- INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES....... 407,236 307,166 214,551 Income Taxes................................................ 168,601 123,017 79,124 ---------- ---------- ---------- INCOME FROM CONTINUING OPERATIONS........................... 238,635 184,149 135,427 ---------- ---------- ---------- DISCONTINUED OPERATIONS, NET OF TAX: Loss from Discontinued Operations........................... -- -- (50,941) Loss on Disposal of Discontinued Operations................. -- (31,734) (344,378) ---------- ---------- ---------- Total Loss from Discontinued Operations................. -- (31,734) (395,319) ---------- ---------- ---------- Income (Loss) Before Extraordinary Item..................... 238,635 152,415 (259,892) Extraordinary Item -- Loss on Early Extinguishment of Debt, Net of Income Tax Benefit of $9,044....................... (13,565) -- -- ---------- ---------- ---------- NET INCOME (LOSS)........................................... 225,070 152,415 (259,892) Less -- Preferred Dividends................................. -- -- 129 Less -- Premium Paid on Preferred Stock Redemption.......... -- -- 350 ---------- ---------- ---------- EARNINGS (LOSS) AVAILABLE FOR COMMON STOCK.................. $ 225,070 $ 152,415 $ (260,371) ========== ========== ========== BASIC EARNINGS (LOSS) PER COMMON SHARE: Income from Continuing Operations........................... $ 2.07 $ 1.62 $ 1.68 Loss from Discontinued Operations........................... -- -- (0.63) Loss on Disposal of Discontinued Operations................. -- (0.28) (4.29) Extraordinary Item -- Loss on Early Extinguishment of Debt...................................................... (0.12) -- -- ---------- ---------- ---------- Total Basic Earnings (Loss) Per Common Share............ $ 1.95 $ 1.34 $ (3.24) ========== ========== ========== Number of Shares Used in Computing Basic Earnings (Loss) Per Common Share (Thousands).................................. 115,243 114,063 80,284 ========== ========== ========== DILUTED EARNINGS (LOSS) PER COMMON SHARE: Income from Continuing Operations........................... $ 1.97 $ 1.61 $ 1.68 Loss from Discontinued Operations........................... -- -- (0.63) Loss on Disposal of Discontinued Operations................. -- (0.28) (4.29) Extraordinary Item -- Loss on Early Extinguishment of Debt...................................................... (0.11) -- -- ---------- ---------- ---------- Total Diluted Earnings (Loss) Per Common Share.......... $ 1.86 $ 1.33 $ (3.24) ========== ========== ========== Number of Shares Used in Computing Diluted Earnings (Loss) Per Common Share (Thousands).............................. 121,326 115,030 80,358 ========== ========== ========== DIVIDENDS PER COMMON SHARE.................................. $ 0.20 $ 0.20 $ 0.65 ========== ========== ==========
The accompanying notes are an integral part of these statements. 47 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME KINDER MORGAN, INC. AND SUBSIDIARIES
YEAR ENDED DECEMBER 31, ------------------------------- 2001 2000 1999 -------- -------- --------- (IN THOUSANDS) NET INCOME (LOSS)........................................... $225,070 $152,415 $(259,892) -------- -------- --------- OTHER COMPREHENSIVE INCOME, NET OF TAX: Change in Fair Value of Derivatives Utilized for Hedging Purposes (Net of tax of $24,068)....................... 36,102 -- -- Reclassification of Change in Fair Value of Derivatives to Net Income (Net of tax benefit of $9,567).............. (14,351) Reclassification of Unrealized Gain on Available-for-Sale Securities (Net of tax of $1,068 and $498 in 2000 and 1999, respectively).................................... -- 1,602 852 Cumulative Effect Transition Adjustment (Net of tax benefit of $7,922)..................................... (11,883) -- -- -------- -------- --------- OTHER COMPREHENSIVE INCOME.................................. 9,868 1,602 852 -------- -------- --------- COMPREHENSIVE INCOME (LOSS)................................. $234,938 $154,017 $(259,040) ======== ======== =========
The accompanying notes are an integral part of these statements. 48 CONSOLIDATED BALANCE SHEETS KINDER MORGAN, INC. AND SUBSIDIARIES
DECEMBER 31, ----------------------- 2001 2000 ---------- ---------- (IN THOUSANDS) ASSETS CURRENT ASSETS: Cash and Cash Equivalents................................... $ 16,134 $ 141,923 Restricted Deposits......................................... 15,010 14,063 Notes Receivable: Related Party............................................. 22,576 -- Other..................................................... 18,890 -- Accounts Receivable, Net: Trade..................................................... 161,926 109,722 Related Parties........................................... 29,502 2,046 Other..................................................... -- 56,750 Inventories................................................. 61,959 19,600 Gas Imbalances.............................................. 50,775 40,838 Other....................................................... 44,260 48,700 ---------- ---------- 421,032 433,642 ---------- ---------- INVESTMENTS: Kinder Morgan Energy Partners............................... 2,806,146 1,819,281 Other....................................................... 449,056 263,146 ---------- ---------- 3,255,202 2,082,427 ---------- ---------- PROPERTY, PLANT AND EQUIPMENT, NET.......................... 5,703,952 5,667,991 ---------- ---------- DEFERRED CHARGES AND OTHER ASSETS........................... 152,899 202,929 ---------- ---------- TOTAL ASSETS................................................ $9,533,085 $8,386,989 ========== ========== LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES: Current Maturities of Long-term Debt........................ $ 206,267 $ 808,167 Notes Payable............................................... 423,785 100,000 Accounts Payable: Trade..................................................... 160,309 126,245 Related Parties........................................... 70,606 13,556 Accrued Interest............................................ 76,606 72,222 Accrued Taxes............................................... 14,933 26,584 Gas Imbalances.............................................. 58,266 39,496 Payable for Purchase of Thermo Companies.................... -- 15,000 Reserve for Loss on Disposal of Discontinued Operations..... 5,209 23,694 Other....................................................... 102,492 129,911 ---------- ---------- 1,118,473 1,354,875 ---------- ---------- OTHER LIABILITIES AND DEFERRED CREDITS: Deferred Income Taxes....................................... 2,428,504 2,273,177 Other....................................................... 228,631 222,420 ---------- ---------- 2,657,135 2,495,597 ---------- ---------- LONG-TERM DEBT.............................................. 2,404,967 2,478,983 ---------- ---------- KINDER MORGAN-OBLIGATED MANDATORILY REDEEMABLE PREFERRED CAPITAL TRUST SECURITIES OF SUBSIDIARY TRUST HOLDING SOLELY DEBENTURES OF KINDER MORGAN........................................ 275,000 275,000 ---------- ---------- MINORITY INTERESTS IN EQUITY OF SUBSIDIARIES................ 817,513 4,910 ---------- ---------- COMMITMENTS AND CONTINGENT LIABILITIES (NOTES 2, 10 AND 18) STOCKHOLDERS' EQUITY: Preferred Stock (Note 14)................................... -- -- Common Stock: Authorized -- 150,000,000 Shares, Par Value $5 Per Share; Outstanding -- 129,092,689 and 114,578,800 Shares, Respectively, Before Deducting 5,165,911 and 96,140 Shares Held in Treasury.......................... 645,463 572,894 Additional Paid-in Capital.................................. 1,652,846 1,189,270 Retained Earnings........................................... 219,995 17,787 Treasury Stock.............................................. (263,967) (2,327) Other....................................................... 5,660 -- ---------- ---------- Total Stockholders' Equity.................................. 2,259,997 1,777,624 ---------- ---------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY.................. $9,533,085 $8,386,989 ========== ==========
The accompanying notes are an integral part of these statements. 49 CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY KINDER MORGAN, INC. AND SUBSIDIARIES
YEAR ENDED DECEMBER 31, ------------------------------------------------------------------------------ 2001 2000 1999 ------------------------ ------------------------ ------------------------ SHARES AMOUNT SHARES AMOUNT SHARES AMOUNT ----------- ---------- ----------- ---------- ----------- ---------- (DOLLARS IN THOUSANDS) PREFERRED STOCK: Beginning Balance.............................. -- $ -- -- $ -- 70,000 $ 7,000 Redemption of Preferred Stock.................. -- -- -- -- (70,000) (7,000) ----------- ---------- ----------- ---------- ----------- ---------- Ending Balance................................. -- -- -- -- -- -- =========== ---------- =========== ---------- =========== ---------- COMMON STOCK: Beginning Balance.............................. 114,578,800 572,894 112,838,379 564,192 68,645,906 343,230 Acquisition of Kinder Morgan Delaware.......... -- -- -- -- 41,683,323 208,417 Acquisitions of Other Businesses............... -- -- 946,207 4,731 2,065,909 10,330 Conversion of Premium Equity Participating Security Units (PEPS)........................ 13,382,474 66,912 -- -- -- -- Employee and Executive Benefit Plans........... 1,131,415 5,657 794,214 3,971 443,241 2,215 ----------- ---------- ----------- ---------- ----------- ---------- Ending Balance................................. 129,092,689 645,463 114,578,800 572,894 112,838,379 564,192 ----------- ---------- ----------- ---------- ----------- ---------- ADDITIONAL PAID-IN CAPITAL: Beginning Balance.............................. 1,189,270 1,203,008 694,223 Costs Related to PEPS Offering................. (504) (1,151) (514) Revaluation of KMP Investment (Note 6)......... 28,322 (51,074) -- Gain on KMP Units Exchanged for Kinder Morgan Management Shares (Note 2)................... 15,722 -- -- Issuance Costs Related to Kinder Morgan Management Offering.......................... (4,548) -- -- Acquisition of Kinder Morgan Delaware.......... -- -- 470,831 Acquisition of Other Businesses................ (72) 23,824 34,670 Conversion of PEPS............................. 393,446 -- -- Employee and Executive Benefit Plans........... 31,210 14,663 3,798 ---------- ---------- ---------- Ending Balance................................. 1,652,846 1,189,270 1,203,008 ---------- ---------- ---------- RETAINED EARNINGS (DEFICIT): Beginning Balance.............................. 17,787 (111,841) 196,147 Net Income (Loss).............................. 225,070 152,415 (259,892) Cash Dividends: Common....................................... (22,862) (22,787) (47,967) Preferred.................................... -- -- (129) ---------- ---------- ---------- Ending Balance................................. 219,995 17,787 (111,841) ---------- ---------- ---------- TREASURY STOCK AT COST: Beginning Balance.............................. (96,140) (2,327) (172,402) (4,142) (48,598) (1,417) Treasury Stock Acquired........................ (5,297,132) (270,533) (1,743) (62) (135,510) (2,956) Treasury Stock Issued.......................... 227,361 8,893 78,005 1,877 11,706 231 ----------- ---------- ----------- ---------- ----------- ---------- Ending Balance................................. (5,165,911) (263,967) (96,140) (2,327) (172,402) (4,142) ----------- ---------- ----------- ---------- ----------- ---------- OTHER: DEFERRED COMPENSATION: Beginning Balance............................ -- -- (10,686) Executive Benefit Plans...................... (4,208) -- 10,686 ---------- ---------- ---------- Ending Balance............................... (4,208) -- -- ---------- ---------- ---------- ACCUMULATED OTHER COMPREHENSIVE INCOME (NET OF TAX): Beginning Balance............................ -- (1,602) (2,454) Unrealized Gain on Derivatives Utilized for Hedging Purposes........................... 21,751 -- -- Sale of Tom Brown, Inc. Common Stock......... -- 1,602 -- Unrealized Gain on Equity Securities......... -- -- 852 Cumulative Effect Transition Adjustment...... (11,883) -- -- ---------- ---------- ---------- Ending Balance............................... 9,868 -- (1,602) ---------- ---------- ---------- TOTAL OTHER...................................... 5,660 -- (1,602) ----------- ---------- ----------- ---------- ----------- ---------- TOTAL STOCKHOLDERS' EQUITY....................... 123,926,778 $2,259,997 114,482,660 $1,777,624 112,665,977 $1,649,615 =========== ========== =========== ========== =========== ==========
The accompanying notes are an integral part of these statements. 50 CONSOLIDATED STATEMENTS OF CASH FLOWS KINDER MORGAN, INC. AND SUBSIDIARIES
YEAR ENDED DECEMBER 31, ------------------------------------- 2001 2000 1999 ----------- --------- ----------- (IN THOUSANDS) INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS CASH FLOWS FROM OPERATING ACTIVITIES: Net Income (Loss)........................................... $ 225,070 $ 152,415 $ (259,892) Adjustments to Reconcile Net Income (Loss) to Net Cash Flows from Operating Activities: Loss from Discontinued Operations, Net of Tax............. -- 31,734 395,319 Extraordinary Losses on Early Extinguishment of Debt...... 22,609 -- -- Depreciation and Amortization............................. 108,290 108,165 147,933 Deferred Income Taxes..................................... 129,911 105,714 46,000 Equity in Earnings of Kinder Morgan Energy Partners....... (251,860) (113,320) (8,398) Distributions from Kinder Morgan Energy Partners.......... 238,775 121,323 15,918 Deferred Purchased Gas Costs.............................. 23,499 2,685 6,646 Net Gains on Sales of Facilities.......................... (22,621) (61,684) (157,938) Changes in Other Working Capital Items (Note 1(O))........ (29,659) (65,030) 32,316 Changes in Deferred Revenues.............................. (5,228) (4,457) (15,641) Other, Net................................................ 2,253 (58) 24,425 ----------- --------- ----------- Net Cash Flows Provided by Continuing Operations............ 441,039 277,487 226,688 Net Cash Flows Provided by (Used in) Discontinued Operations................................................ (3,737) (110,399) 94,488 ----------- --------- ----------- NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES............. 437,302 167,088 321,176 ----------- --------- ----------- CASH FLOWS FROM INVESTING ACTIVITIES: Capital Expenditures........................................ (124,171) (85,654) (92,841) Proceeds from Sales to Kinder Morgan Energy Partners........ -- 500,302 -- Other Acquisitions.......................................... (23,899) (19,412) (34,565) Investment in Kinder Morgan Energy Partners (Note 2)........ (991,869) -- -- Other Investments........................................... (414,648) (80,511) (14,847) Proceeds from Sale of Investment in Power Plant............. 247,029 -- -- Proceeds from Sale of Tom Brown, Inc. Stock................. -- 14,823 28,650 Sale of U.S. Government Securities.......................... -- -- 1,092,415 Proceeds from Sales of Other Assets......................... 7,077 14,998 87,949 ----------- --------- ----------- Net Cash Flows Provided by (Used in) Continuing Investing Activities................................................ (1,300,481) 344,546 1,066,761 Net Cash Flows Provided by (Used in) Discontinued Investing Activities................................................ 25,742 154,176 (46,568) ----------- --------- ----------- NET CASH FLOWS PROVIDED BY (USED IN) INVESTING ACTIVITIES... (1,274,739) 498,722 1,020,193 ----------- --------- ----------- CASH FLOWS FROM FINANCING ACTIVITIES: Short-Term Debt, Net........................................ 323,785 (474,400) (1,117,446) Floating Rate Notes Issued.................................. 200,000 -- -- Long-Term Debt Retired...................................... (872,185) (14,055) (158,934) Issuance of Shares by Kinder Morgan Management.............. 942,614 -- -- Common Stock Issued for Premium Equity Participating Securities................................................ 460,358 -- -- Other Common Stock Issued................................... 31,184 17,773 8,323 Premiums Paid on Early Extinguishment of Debt............... (30,694) -- -- Other Financing, Net........................................ 7,951 (45,239) -- Preferred Stock Redeemed.................................... -- -- (7,350) Treasury Stock Issued....................................... 2,464 1,877 231 Treasury Stock Acquired..................................... (265,706) (62) (2,956) Cash Dividends, Common and Preferred........................ (22,862) (22,787) (48,096) Minority Interests, Net..................................... 375 (2,436) 379 Premium Equity Participating Securities Contract Fee........ (10,931) (10,936) (11,097) Securities Issuance Costs................................... (54,705) -- -- ----------- --------- ----------- NET CASH FLOWS PROVIDED BY (USED IN) FINANCING ACTIVITIES... 711,648 (550,265) (1,336,946) ----------- --------- ----------- Net Increase (Decrease) in Cash and Cash Equivalents........ (125,789) 115,545 4,423 Cash and Cash Equivalents at Beginning of Year.............. 141,923 26,378 21,955 ----------- --------- ----------- Cash and Cash Equivalents at End of Year.................... $ 16,134 $ 141,923 $ 26,378 =========== ========= ===========
The accompanying notes are an integral part of these statements. 51 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (A) NATURE OF OPERATIONS We are an energy and related services provider and have operations in the Rocky Mountain and mid-continent regions, with principal operations in Arkansas, Colorado, Illinois, Iowa, Kansas, Nebraska, Oklahoma, Texas and Wyoming. Services we offer include: (i) storing, transporting and selling natural gas, (ii) providing retail natural gas distribution services, and (iii) designing, developing, constructing and operating electric generation facilities. We have both regulated and nonregulated operations. Our common stock is traded on the New York Stock Exchange under the ticker symbol "KMI." During 1999, we acquired Kinder Morgan Delaware as discussed in the following paragraph. As a result, we own, through Kinder Morgan Delaware, the general partner interest in Kinder Morgan Energy Partners, L.P., a publicly traded pipeline master limited partnership, referred to in these Notes as "Kinder Morgan Energy Partners," and receive a substantial portion of our earnings from returns on this investment. In October 1999, K N Energy, Inc. (as we were then named), a Kansas corporation, acquired Kinder Morgan, Inc., a Delaware corporation, referred to in these Notes as "Kinder Morgan Delaware." We then changed our name to Kinder Morgan, Inc. Unless the context requires otherwise, references to "we," "us," "our," or the "Company" are intended to mean Kinder Morgan, Inc. (a Kansas corporation and formerly known as K N Energy, Inc.) and its consolidated subsidiaries. During the third and fourth quarters of 1999, we adopted and implemented plans to discontinue our businesses involved in (i) wholesale marketing of natural gas and natural gas liquids, (ii) gathering and processing of natural gas, including field services and short-haul intrastate pipelines, (iii) direct marketing of non-energy products and services and (iv) international operations. During the fourth quarter of 2000, we determined that, due to the start-up nature of these operations and the unwillingness of buyers to pay for the value created to date, it was not in the best interests of the Company to dispose of our international operations and, accordingly, we decided to retain them. Additional information concerning these discontinued operations is contained in Note 7. (B) BASIS OF PRESENTATION The consolidated financial statements include the accounts of Kinder Morgan, Inc. and its majority-owned subsidiaries. Investments in jointly owned operations in which we have the ability to exercise significant influence over their operating and financial policies are accounted for under the equity method, as is our investment in Kinder Morgan Energy Partners, which is further described in Note 3. All material intercompany transactions and balances have been eliminated. Certain prior year amounts have been reclassified to conform to the current presentation. Critical Accounting Policies and Estimates Our discussion and analysis of financial condition and operations are based on our consolidated financial statements, prepared in accordance with accounting principles generally accepted in the United States of America and contained within this report. Certain amounts included in or affecting our financial statements and related disclosure must be estimated, requiring us to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time the financial statements are prepared. Therefore, the reported amounts of our assets and liabilities, revenues and expenses and associated disclosures with respect to contingent assets and obligations are necessarily affected by these estimates. We evaluate these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. In preparing our financial statements and related disclosures, we must use estimates in determining the economic useful lives of our assets, obligations under our employee benefit plans, provisions for uncollectible accounts receivable, unbilled revenues for our natural gas distribution deliveries for which 52 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) meters have not yet been read, exposures under contractual indemnifications and to determine various other recorded or disclosed amounts. However, we believe that certain accounting policies are of more significance in our financial statement preparation process than others. With respect to revenue recognition, our power plant development business utilizes the percentage of completion method to determine what portion of its overall constructor fee has been earned. We utilize the services of third-party engineering firms to help us estimate the progress being made on each project, but any such process requires subjective judgments. Any errors in this estimation process could result in revenues being reported before or after they were actually earned. Increases or decreases in revenues resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. With respect to our environmental exposure, we utilize both internal staff and external experts to assist us in identifying environmental issues and in estimating the costs and timing of remediation efforts. Often, as remediation evaluations and efforts progress, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in our income in the period in which they are reasonable determinable. We record a valuation allowance to reduce our deferred tax assets to an amount that is more likely than not to be realized. While we have considered future taxable income and prudent and feasible tax planning strategies in determining the amount of our valuation allowance, any difference in the amount that we expect to ultimately realize will be included in income in the period in which such a determination is reached. As discussed in Note 15, we enter into derivative contracts (natural gas futures, swaps and options) solely for the purpose of mitigating risks that accompany our normal business activities, including interest rates and the price of natural gas and associated transportation. We account for these derivative transactions as hedges in accordance with the authoritative accounting guidelines, marking the derivatives to market at each reporting date, with the unrealized gains and losses either recognized as part of comprehensive income or, in the case of interest rate swaps, as a valuation adjustment to the underlying debt. Any inefficiency in the performance of the hedge is recognized in income currently and, ultimately, the financial results of the hedge are recognized concurrently with the financial results of the underlying hedged item. All but an insignificant amount of our natural gas related derivatives are for terms of 18 months or less, allowing us to utilize widely available, published forward pricing curves in determining the appropriate market values. Our interest rate swaps are similar in nature to many other such financial instruments used for managing interest rate risk and are valued for us by commercial banks with expertise in such valuations. Finally, we are subject to litigation as the result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from judgments or settlements. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. (C) ACCOUNTING FOR REGULATORY ACTIVITIES Our regulated utilities are accounted for in accordance with the provisions of Statement of Financial Accounting Standards ("SFAS") No. 71, Accounting for the Effects of Certain Types of Regulation, which prescribes the circumstances in which the application of generally accepted accounting principles is affected by the economic effects of regulation. Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges and credits that will be recovered from or refunded to 53 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) customers through the ratemaking process. The following regulatory assets and liabilities are reflected in the accompanying Consolidated Balance Sheets:
DECEMBER 31, ------------------ 2001 2000 -------- ------- (IN THOUSANDS) REGULATORY ASSETS: Employee Benefit Costs.................................... $ 6,355 $ 6,576 Debt Refinancing Costs.................................... 1,342 1,664 Deferred Income Taxes..................................... 16,405 16,801 Purchased Gas Costs....................................... 3,431 23,470 Plant Acquisition Adjustments............................. 454 454 Rate Regulation and Application Costs..................... 2,580 3,040 -------- ------- Total Regulatory Assets................................... 30,567 52,005 -------- ------- REGULATORY LIABILITIES: Employee Benefit Costs.................................... 5,967 5,967 Deferred Income Taxes..................................... 26,311 28,930 Purchased Gas Costs....................................... 19,890 22,405 -------- ------- Total Regulatory Liabilities.............................. 52,168 57,302 -------- ------- NET REGULATORY LIABILITIES.................................. $(21,601) $(5,297) ======== =======
As of December 31, 2001, $23.8 million of our regulatory assets and $46.2 million of our regulatory liabilities were being recovered from or refunded to customers through rates over periods ranging from 1 to 12 years. (D) REVENUE RECOGNITION POLICIES We recognize revenues as services are rendered or goods are delivered and, if applicable, title has passed. Our rate-regulated retail natural gas distribution business bills customers on a monthly cycle billing basis. Revenues are recorded on an accrual basis, including an estimate at the end of each accounting period for gas delivered and, if applicable, title has passed but for which bills have not yet been rendered. With respect to our construction activities, we utilize the percentage of completion method whereby revenues and associated expenses are recognized over the construction period based on work performed in relation to the total expected for the entire project. We provide various types of natural gas storage and transportation services to customers, principally through Natural Gas Pipeline Company of America's pipeline system. The gas remains the property of the customers at all times. In many cases (generally described as "firm service"), the customer pays a two- part rate that includes (i) a fixed fee reserving the right to transport or store gas in our facilities and (ii) a per-unit rate for volumes actually transported or injected into/withdrawn from storage. The fixed-fee component of the overall rate is recognized as revenue ratably over the contract period. The per-unit charge is recognized as revenue when the volumes are delivered to the customers' agreed upon delivery point, or when the volumes are injected into/withdrawn from our storage facilities. In other cases (generally described as "interruptible service"), there is no fixed fee associated with the services because the customer accepts the possibility that service may be interrupted at our discretion in order to serve customers who have purchased firm service. In the case of interruptible service, revenue is recognized in the same manner utilized for the per-unit rate on firm service. 54 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (E) EARNINGS PER SHARE Basic earnings per common share is computed based on the monthly weighted-average number of common shares outstanding during each period. Diluted earnings per common share is computed based on the monthly weighted-average number of common shares outstanding during each period, increased by the assumed exercise or conversion of securities (stock options and Premium Equity Participating Security Units) convertible into common stock, for which the effect of conversion or exercise using the treasury stock method would be dilutive.
2001 2000 1999 ------- ------- ------ (IN THOUSANDS) Weighted Average Common Shares Outstanding............... 115,243 114,063 80,284 Premium Equity Participating Security Units.............. 4,328 -- -- Dilutive Common Stock Options............................ 1,755 967 74 ------- ------- ------ Shares Used to Compute Diluted Earnings Per Common Share.................................................. 121,326 115,030 80,358 ======= ======= ======
Weighted-average stock options outstanding totaling 9,200 for 2001, 307,100 for 2000 and 3,824,000 for 1999 were excluded from the diluted earnings per common share calculation because the effect of including them would have been antidilutive. Common shares issuable upon conversion of the premium equity participating security units were not included in diluted earnings per common share calculations in 1999 and 2000 because to do so would have been antidilutive. These common shares were given dilutive effect in 2001 and are included in the weighted-average common shares outstanding beginning with their issuance in November 2001 as a result of the maturity of the premium equity participating security units. Preferred stock dividends and premiums paid on preferred stock redemptions totaling $479 thousand in 1999 were deducted from net income in arriving at the balance available to common stockholders. Note 13 (B) contains more information regarding premium equity participating security units, while Note 17 contains more information regarding stock options. (F) RESTRICTED DEPOSITS Restricted Deposits consist of monies on deposit with brokers that are restricted to meet exchange trading requirements; see Note 15. (G) ACCOUNTS RECEIVABLE The caption "Accounts Receivable, Net" in the accompanying Consolidated Balance Sheets is presented net of allowances for doubtful accounts of $3.4 million and $2.3 million at December 31, 2001 and 2000, respectively. The caption "Accounts Receivable, Net: Other" principally consists of a receivable from ONEOK due to cash management services provided to them during 2000 in conjunction with their purchase of certain of our assets as discussed in Note 7. (H) INVENTORIES
DECEMBER 31, ----------------- 2001 2000 ------- ------- (IN THOUSANDS) Gas in Underground Storage (Current)........................ $46,451 $ 5,145 Materials and Supplies...................................... 15,508 14,455 ------- ------- $61,959 $19,600 ======= =======
Inventories are accounted for using the following methods, with the percent of the total dollars at December 31, 2001 shown in parentheses: average cost (33.48%), last-in, first-out (65.84%) and first-in, 55 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) first-out (0.68%). All non-utility inventories held for resale are valued at the lower of cost or market. The excess of current cost over the reported last-in, first-out value of gas in underground storage valued under that method was not material at December 31, 2001. We also maintain gas in our underground storage facilities on behalf of certain third parties. We receive a fee from our storage service customers but do not reflect the value of their gas stored in our facilities in the accompanying Consolidated Balance Sheets. (I) OTHER INVESTMENTS
DECEMBER 31, ------------------- 2001 2000 -------- -------- (IN THOUSANDS) TransColorado Pipeline Company.............................. $134,255 $ 34,824 Power Investments: Thermo Companies.......................................... 138,939 135,279 Wrightsville/Jackson Plant Investments.................... 97,471 64,695 Other Site Development Investments........................ 68,806 11,845 Other....................................................... 9,585 16,503 -------- -------- $449,056 $263,146 ======== ========
Investments consist primarily of equity method investments in unconsolidated subsidiaries and joint ventures, and include ownership interests in net profits. At December 31, 2001 and 2000, "Other" included an investment in Igasamex USA, Ltd. of approximately $6 million and assets held for deferred employee compensation, among other individually insignificant items. (J) PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment is stated at historical cost, which for constructed plant includes indirect costs such as payroll taxes, fringe benefits, administrative and general costs. Expenditures that increase capacities, improve efficiencies or extend useful lives are capitalized. Routine maintenance, repairs and renewal costs are expensed as incurred. The cost of normal retirements of depreciable utility property, plant and equipment, plus the cost of removal less salvage, is recorded in accumulated depreciation with no effect on current period earnings. Gains or losses are recognized upon retirement of non-utility property, plant and equipment, and utility property, plant and equipment constituting an operating unit or system, when sold or abandoned. In accordance with the provisions of SFAS 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, we review the carrying values of our long-lived assets whenever events or changes in circumstances indicate that such carrying values may not be recoverable. As yet, no asset or group of assets has been identified for which the sum of expected future cash flows (undiscounted and without interest charges) is less than the carrying amount of the asset(s) and, accordingly, no impairment losses have been recorded. However, currently unforeseen events and changes in circumstances could require the recognition of impairment losses at some future date. (K) GAS IMBALANCES We value gas imbalances due to or due from interconnecting pipelines at the lower of cost or market. Gas imbalances represent the difference between customer nominated versus actual gas receipts from and gas deliveries to our interconnecting pipelines under various Operational Balancing Agreements. Natural gas imbalances are settled in cash or made up in-kind subject to the pipelines' various terms. 56 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (L) DEPRECIATION AND AMORTIZATION Depreciation is computed based on the straight-line method over the estimated useful lives of assets. The range of estimated useful lives used in depreciating assets for each property type are as follows:
PROPERTY TYPE RANGE OF ESTIMATED USEFUL LIVES OF ASSETS - ------------- ------------------------------------------ (IN YEARS) Natural Gas Pipelines........................ 24 to 68 (Transmission assets: average 56) Retail Natural Gas Distribution.............. 33 Power Generation............................. 10 to 30 General and Other............................ 3 to 56
(M) INTEREST EXPENSE, NET
YEAR ENDED DECEMBER 31, -------------------------- 2001 2000 1999 ------ ------ ------ (IN MILLIONS) Interest Expense......................................... $221.0 $248.4 $254.3 AFUDC -- Interest........................................ (4.8) (2.6) (1.9) Interest Income.......................................... -- (2.6) (0.5) ------ ------ ------ Interest Expense, Net.................................... $216.2 $243.2 $251.9 ====== ====== ======
"Interest Expense, Net" as presented in the accompanying Consolidated Statements of Operations is net of (i) the debt component of the allowance for funds used during construction ("AFUDC -- Interest"), (ii) in 2000, interest income attributable to (1) our note receivable from Kinder Morgan Energy Partners associated with the transfer of certain interests (see Note 6) and (2) interest income associated with settlement of our net cash position with ONEOK and (iii) in 1999, interest income related to government securities associated with the acquisition of MidCon Corp. In conjunction with our sale of certain assets to ONEOK as discussed in Note 7, we agreed to continue managing cash for these assets for a period of months, following which an audit was conducted to affirm the assignment of specific amounts to the two parties based on the timing of the underlying business transactions. We included the interest income attributable to our net receivable resulting from this transaction, together with the related interest expense, in the caption "Interest Expense, Net" in the accompanying consolidated Statements of Operations. (N) OTHER, NET "Other, Net" as presented in the accompanying Consolidated Statements of Operations includes $22.6 million, $61.7 million and $157.9 million in 2001, 2000 and 1999, respectively, attributable to gains from sales of assets. These transactions are discussed in Note 6. (O) CASH FLOW INFORMATION We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. "Other, Net," presented as a component of "Net Cash Flows From Operating Activities" in the accompanying Consolidated Statements of Cash Flows includes, among other things, undistributed equity in earnings of unconsolidated subsidiaries and joint ventures (other than Kinder Morgan Energy Partners) and other non-cash charges and credits to income. 57 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) ADDITIONAL CASH FLOW INFORMATION: CHANGES IN OTHER WORKING CAPITAL ITEMS: (NET OF EFFECTS OF ACQUISITIONS AND SALES) INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
YEAR ENDED DECEMBER 31, ------------------------------- 2001 2000 1999 -------- --------- -------- (IN THOUSANDS) Accounts Receivable................................. $(42,153) $(172,781) $(16,483) Materials and Supplies Inventory.................... (1,512) (2,626) 2,894 Gas in Underground Storage -- Current............... (41,306) 30,453 (17,626) Other Current Assets................................ (6,052) (27,737) 114 Accounts Payable.................................... 33,375 122,421 37,506 Other Current Liabilities........................... 27,989 (14,760) 25,911 -------- --------- -------- $(29,659) $ (65,030) $ 32,316 ======== ========= ========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
YEAR ENDED DECEMBER 31, ------------------------------ 2001 2000 1999 -------- -------- -------- (IN THOUSANDS) CASH PAID FOR: Interest (Net of Amount Capitalized)................. $225,327 $248,177 $284,762 ======== ======== ======== Distributions on Preferred Capital Trust Securities......................................... $ 21,913 $ 21,913 $ 21,913 ======== ======== ======== Income Taxes Paid (Received)......................... $ 27,524 $ 7,674 $(10,883) ======== ======== ========
In April 2000, we made the final scheduled payment for our third-quarter 1998 acquisition of interests in the Thermo Companies using 961,153 shares of our common stock, approximately $30 million of value. For our December 31, 2000 sale of assets to Kinder Morgan Energy Partners, we received both cash and non-cash consideration. In October 1999, we acquired Kinder Morgan Delaware in a non-cash transaction. Notes 3 and 6 contain additional information on these matters. (P) STOCK-BASED COMPENSATION SFAS 123, Accounting for Stock-Based Compensation, encourages, but does not require, entities to adopt the fair value method of accounting for stock-based compensation plans. As allowed under SFAS 123, we continue to apply Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees. Accordingly, compensation expense is not recognized for stock options unless the options are granted at an exercise price lower than the market price on the grant date. Note 17 contains information regarding our common stock option and purchase plans. (Q) TRANSACTIONS WITH RELATED PARTIES We account for our investment in Kinder Morgan Energy Partners (among other entities) under the equity method of accounting. In each accounting period, we record our share of these investees' earnings, and amortize any "excess" investment. We adjust the amount of our excess investment when an equity method investee or a consolidated subsidiary issues additional equity (or reacquires equity shares) in any manner that alters our ownership percentage. Differences between the per unit sales proceeds from these equity issuances (or reacquisitions) and our underlying book basis, as well as the pro rata portion of the excess investment (including associated deferred taxes), are recorded directly to paid-in capital rather than 58 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) being recognized as gains or losses. Three such transactions are described in Note 6. If incremental equity is received in conjunction with sales of assets to equity method investees, gains and losses are not recognized to the extent of the interest retained in the assets transferred. The Notes Receivable and Accounts Receivable related party balances consist primarily of advances to Horizon Pipeline Company, an enterprise we jointly own with Nicor, Inc.; see Note 6. The Note Receivable from Horizon Pipeline Company is expected to be repaid in part and replaced with an equity investment when Horizon completes its long-term financing in 2002. The Accounts Receivable from Horizon relates to construction costs that were reimbursed to us in January 2002. The Accounts Payable related party balance is primarily payable to Kinder Morgan Energy Partners for amounts arising from performing administrative functions for them, including cash management, hedging activities, centralized payroll and employee benefits services and expenses incurred in performing as general partner of Kinder Morgan Energy Partners. The net monthly balance payable or receivable from these activities is settled in cash in the following month. The caption "Gas Purchases and Other Costs of Sales" in the accompanying Consolidated Statements of Operations includes related-party costs totaling $47.4 million, $22.2 million and $0.6 million for the years 2001, 2000 and 1999, respectively, primarily for natural gas transportation and storage services and natural gas provided by entities owned by Kinder Morgan Energy Partners. (R) ACCOUNTING FOR RISK MANAGEMENT ACTIVITIES We utilize energy derivatives for the purpose of mitigating our risk resulting from fluctuations in the market price of natural gas and associated transportation. Prior to December 31, 2000, our accounting policy for these activities was based on a number of authoritative pronouncements including SFAS No. 80, Accounting for Futures Contracts. This policy is described in detail in Note 15, as is our new policy, which is based on SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, which became effective for us on January 1, 2001. (S) INCOME TAXES Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. Deferred tax assets are reduced by a valuation allowance for the amount of any tax benefit we do not expect to be realized. Note 12 contains information about our income taxes, including the components of our income tax provision and the composition of our deferred income tax assets and liabilities. 2. KINDER MORGAN MANAGEMENT, LLC In May 2001, Kinder Morgan Management, LLC, one of our indirect subsidiaries, issued and sold its limited liability shares in an underwritten initial public offering. The net proceeds from the offering were used by Kinder Morgan Management to buy i-units from Kinder Morgan Energy Partners for $991.9 million. Upon purchase of the i-units, Kinder Morgan Management became a partner in Kinder Morgan Energy Partners and was delegated by Kinder Morgan Energy Partners' general partner the responsibility to manage and control the business and affairs of Kinder Morgan Energy Partners. The i-units are a class of Kinder Morgan Energy Partners' limited partner interests that have been, and will be, issued only to Kinder Morgan Management. We have certain rights and obligations with respect to these securities, including an obligation to purchase the Kinder Morgan Management shares or exchange them for Kinder Morgan Energy Partners' common units we own or cash as discussed following. In the initial public offering, Kinder Morgan Management issued a total of 14,875,000 shares, of which 1,487,500 shares (29,750,000 and 2,975,000 shares respectively, after adjustment for the stock split described following) were purchased by Kinder Morgan, Inc. (utilizing incremental short-term 59 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) borrowings), with the balance purchased by the public. The equity interest in Kinder Morgan Management (our consolidated subsidiary) purchased by the public created a minority interest on our balance sheet of $892.7 million at the time of the transaction. On July 18, 2001, Kinder Morgan Energy Partners announced a two-for-one split of its common units. The common unit split, in the form of a one-common-unit distribution for each common unit outstanding, occurred on August 31, 2001. This split resulted in Kinder Morgan, Inc. receiving one additional common unit for each common unit it owned and Kinder Morgan Management receiving one additional i-unit for each i-unit it owned. Also on July 18, 2001, Kinder Morgan Management announced a two-for-one split of its shares. This share split, in the form of a one-share distribution for each share outstanding, occurred on August 31, 2001. Holders of Kinder Morgan Management shares may exchange each of their shares for one common unit of Kinder Morgan Energy Partners owned by us or our affiliates. This exchange feature is subject to our right to settle the exchange in cash rather than common units. It was intended and expected that these securities would trade within a narrow range. During the period the Kinder Morgan Management shares have been outstanding, the difference between the market price of the Kinder Morgan Management shares and the Kinder Morgan Energy Partners common units has been minimal and, in recent periods, the Kinder Morgan Management shares have traded at a slight premium to Kinder Morgan Energy Partners common units. Accordingly, the exchange feature does not represent a significant financial asset to the holder. As of December 31, 2001, approximately 2.8 million Kinder Morgan Management shares (after adjustment for the stock split as discussed preceding) had been exchanged for Kinder Morgan Energy Partners' common units. As a result of these exchanges, at December 31, 2001, Kinder Morgan, Inc. owned approximately 6.0 million (19.4%) of Kinder Morgan Management's outstanding shares. Our income statement is not affected by these exchanges, which are taxable events for income tax purposes. The impacts on our balance sheet are a decrease in minority interest and a change in paid-in capital equal to the difference between the book value of the minority interest associated with the Kinder Morgan Management shares received in the exchange and the book value of the Kinder Morgan Energy Partners' units surrendered, net of the associated tax liability. Through December 31, 2001, these exchanges have increased our paid-in capital by approximately $15.7 million. On January 17, 2002, Kinder Morgan Management announced that its board of directors had approved a share distribution equal to $0.55 per share payable on February 14, 2002 to its shareholders of record as of January 31, 2002. This distribution was paid in the form of additional shares based on the average market price of a share determined for a ten-trading day period ending on the trading day immediately prior to the ex-dividend date for the shares. 3. BUSINESS COMBINATIONS On October 7, 1999, we completed the acquisition of Kinder Morgan Delaware, the sole stockholder of the general partner of Kinder Morgan Energy Partners. Additional information on the assets and operations of Kinder Morgan Energy Partners is contained in Notes 1 and 20. To effect the business combination, we issued approximately 41.5 million shares of our common stock in exchange for all of the outstanding shares of Kinder Morgan Delaware. Upon closing of the transaction, Richard D. Kinder, Chairman and Chief Executive Officer of Kinder Morgan Delaware, was named our Chairman and Chief Executive Officer, and we were renamed Kinder Morgan, Inc. This acquisition was accounted for as a purchase for accounting purposes and, accordingly, the assets acquired and liabilities assumed were recorded at their respective estimated fair market values as of the 60 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) acquisition date. The calculation of the total purchase price and the allocation of that purchase price to the assets acquired and liabilities assumed based on their fair market values is shown following:
(MILLIONS OF DOLLARS) Purchase Price: Kinder Morgan, Inc. Common Stock Issued................... $ 679 Transaction Fees.......................................... 8 ------ Total.................................................. $ 687 ====== The Purchase Price was Allocated as Follows: Investment in Kinder Morgan Energy Partners............... $1,336 Cash and Cash Equivalents................................. 1 Accounts Receivable....................................... 9 Prepayments and Other Current Assets...................... 4 Deferred Charges.......................................... 1 Note Payable Assumed...................................... (149) Deferred Income Taxes..................................... (503) Accounts Payable and Accrued Liabilities Assumed.......... (12) ------ Total.................................................. $ 687 ======
The allocation of the purchase price resulted in an excess of the purchase price over Kinder Morgan Delaware's share of the underlying equity in the net assets of Kinder Morgan Energy Partners totaling $1.3 billion. This excess has been fully allocated to the Kinder Morgan Delaware investment in Kinder Morgan Energy Partners and reflects the estimated fair market value of this investment at the date of acquisition. This excess investment is being amortized over 44 years, approximately the estimated remaining useful life of Kinder Morgan Energy Partners' assets, and is shown in the accompanying Consolidated Income Statements as "Amortization of Excess Investment" under the sub-heading "Kinder Morgan Energy Partners" within "Other Income and (Expenses)." This amortization will be discontinued in 2002 as a result of the provisions of SFAS No. 142, Goodwill and Other Intangible Assets, which were effective as of January 1, 2002. The assets, liabilities and results of operations of Kinder Morgan Delaware are included with those of Kinder Morgan beginning with the October 7, 1999 acquisition date. The following pro forma information gives effect to our acquisition of Kinder Morgan Delaware as if the business combination had occurred January 1, 1999. This unaudited pro forma information should be read in conjunction with the accompanying consolidated financial statements. This pro forma information does not necessarily indicate the financial results that would have occurred if this acquisition had taken place on January 1, 1999, nor should it necessarily be viewed as an indicator of future financial results. UNAUDITED PRO FORMA FINANCIAL INFORMATION
YEAR ENDED DECEMBER 31, 1999 -------------------- (DOLLARS IN MILLIONS EXCEPT PER SHARE AMOUNTS) Operating Revenues.......................................... $1,745.5 Net Loss.................................................... $ (233.9) Loss Per Diluted Common Share............................... $ (2.09) Number of Shares Used in Computing Loss Per Diluted Common Share (In Thousands)...................................... 112,334
61 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) On February 22, 1999, Sempra Energy and we announced that our respective boards of directors had unanimously approved a definitive agreement under which Sempra and we would combine in a stock-and-cash transaction valued in the aggregate at $6.0 billion. On June 21, 1999, Sempra and we announced that we had mutually agreed to terminate the merger agreement. Sempra reimbursed us $5.95 million for expenses incurred in connection with the proposed merger. 4. MERGER-RELATED AND SEVERANCE COSTS In anticipation of the completion of the transaction with Kinder Morgan Delaware, during the third quarter of 1999, a number of our officers terminated their employment with us, as did certain other employees. In addition, we terminated the employment of a number of additional employees during the fourth quarter of 1999 and in early 2000 as a result of cost saving initiatives implemented following the closing of the Kinder Morgan Delaware transaction. In total, approximately 150 employees were severed. In conjunction with these terminations, we agreed to provide severance benefits and incurred certain legal and other associated costs. Also in conjunction with the Kinder Morgan Delaware transaction, we elected to discontinue certain projects, consolidate certain facilities and relocate certain employees. The $37.4 million pre-tax expense ($23.6 million after tax or $0.29 per diluted share) associated with these matters (included in the accompanying Consolidated Statement of Operations for 1999 under the caption "Merger-related and Severance Costs") was composed of the following: (i) severance and relocation, including restricted stock -- $22.7 million, (ii) facilities costs, including moving expenses -- $5.3 million, (iii) write-down/write-off of project costs -- $8.0 million and (iv) other -- $1.4 million. Of this total, approximately $9.4 million remained as an accrual at December 31, 1999, all of which was expended during the first half of 2000. 5. CHANGE IN ACCOUNTING ESTIMATE Pursuant to a revised study of the useful lives of the underlying assets by an independent third party, in July 1999, we changed the depreciation rates associated with the gas plant acquisition adjustment recorded in conjunction with the acquisition of MidCon Corp. Relative to the amounts which would have been recorded utilizing the previous depreciation rates, this change had the effect of decreasing "Depreciation and Amortization" by approximately $19.3 million for the year ended December 31, 1999. Consequently, "Income from Continuing Operations" and "Net Income" were increased by approximately $12.1 million for the year ended December 31, 1999 ($0.15 per diluted common share). 6. INVESTMENTS AND SALES On December 28, 2001, we completed the previously announced sale of certain assets in the Wattenberg field area of the Denver-Julesberg Basin to Kerr-McGee Gathering LLC (formerly HS Resources, Inc.). Under terms of agreements with them, Kerr-McGee Gathering LLC has operated these assets since December 1999 and made monthly payments to us until the sale of assets was completed. We recorded a pre-tax loss of $22.1 million (approximately $13.3 million after tax or $0.11 per diluted share) in conjunction with this sale, shown in the caption "Other Net" in the accompanying Consolidated Statement of Operations for 2001. Effective December 1, 2001, we purchased natural gas distribution assets from Citizens Communications Company (NYSE: CZN) for approximately $11 million in cash and assumed liabilities. The natural gas distribution assets serve approximately 13,400 residential, commercial and agricultural customers in Bent, Crowley, Otero, Archuleta, La Plata and Mineral Counties in Colorado. On October 31, 2001, the Colorado Public Utilities Commission approved this transaction. On November 5, 2001, the Horizon Pipeline Company announced that construction has started on its new $79 million natural gas pipeline in northern Illinois. Horizon Pipeline is a joint venture of Nicor-Horizon, a subsidiary of Nicor Inc. (NYSE: GAS), and Natural Gas Pipeline Company of America. 62 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Completion of the entire project is projected for April 2002. The action allowing work to get under way included a confirmation from the Federal Energy Regulatory Commission that Horizon Pipeline was in compliance with pre-construction conditions of the original certificate of public convenience and necessity issued in July 2001. The Horizon natural gas pipeline entails the new construction of 27 miles of 36-inch diameter pipeline, the lease of capacity in 46 miles of existing pipeline from Natural Gas Pipeline Company of America, and the installation of gas compression facilities. Upon completion of the project, Horizon Pipeline will be able to transport 380 million cubic feet of natural gas per day from near Joliet into McHenry County, connecting the emerging supply hub at Joliet with the northern part of the Nicor natural gas distribution system and the existing Natural Gas Pipeline Company of America pipeline system. In May 2001, Kinder Morgan Energy Partners issued i-units in conjunction with the Kinder Morgan Management initial public offering of its shares to the public. This issuance of i-units reduced our percentage ownership of Kinder Morgan Energy Partners from approximately 22.7 percent to approximately 20.8 percent and had the associated effects of increasing (i) our investment in the net assets of Kinder Morgan Energy Partners by $145.1 million, (ii) associated accumulated deferred income taxes by $18.9 million and (iii) paid-in capital by $28.3 million and reducing (i) our excess investment in Kinder Morgan Energy Partners by $97.9 million and (ii) the monthly amortization of the excess investment by $192 thousand; see Notes 1(Q) and 2. In December 2000, we transferred approximately $300 million of assets to Kinder Morgan Energy Partners effective December 31, 2000. The largest asset we transferred was our wholly owned subsidiary Kinder Morgan Texas Pipeline, L.P. and certain associated entities (the lessee a major intrastate natural gas pipeline system). We also transferred the Douglas and Casper gas processing facilities and associated natural gas gathering systems, our 50 percent interest in Coyote Gas Treating, LLC and our 25 percent interest in Thunder Creek Gas Services, L.L.C. As consideration for the transfer, we received approximately $150 million in cash (with an additional cash payment for working capital), 1.3 million Kinder Morgan Energy Partners' common limited partner units and 5.3 million Class-B Kinder Morgan Energy Partners' limited partner units. At December 31, 2000, we recorded a pre-tax gain of $61.6 million (approximately $37.0 million after tax or $0.32 per diluted share) in conjunction with this sale. During 2001, we made a final working capital adjustment associated with this transfer, and reduced our provision for exposure under an indemnification provision of the contribution agreement, resulting in positive pre-tax adjustments of $17.0 million (approximately $10.2 million after tax or $0.08 per diluted share) and $9.9 million (approximately $5.9 million after tax or $0.05 per diluted share), in each case adjusted for our continuing interest in the assets transferred. In May and August of 2000, Kinder Morgan Power announced plans to construct 550-megawatt power generation facilities in Wrightsville, Arkansas and Jackson, Michigan, respectively. These plants are currently under construction, with completion on both facilities expected by mid-2002. Kinder Morgan Power has contracted to operate the facility in Jackson, Michigan. Kinder Morgan Power does not own either facility, but has an investment in them as discussed in Notes 1 and 18. In April 2000, Kinder Morgan Energy Partners issued 9.0 million common units in a public offering at a price of $39.75 per common unit, receiving total net proceeds (after underwriting discount) of $171.3 million. We did not acquire any of these common units. This transaction reduced our then percentage ownership of Kinder Morgan Energy Partners from approximately 19.9% to approximately 18.6% and had the associated effects of increasing our investment in the net assets of Kinder Morgan Energy Partners by $6.1 million and reducing (i) our excess investment in Kinder Morgan Energy Partners by $81.1 million, (ii) associated accumulated deferred income taxes by $30.0 million, (iii) paid-in capital by $45.0 million and (iv) our monthly amortization of the excess investment by approximately $176 thousand. In February 2000, Kinder Morgan Energy Partners issued 1.1 million common units, 63 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) assumed approximately $7.0 million in liabilities and paid $0.8 million in cash as consideration for acquiring all the capital stock of Milwaukee Bulk Terminals, Inc. and Dakota Bulk Terminal, Inc. This transaction reduced our percentage ownership of Kinder Morgan Energy Partners and had the associated effects of increasing our investment in the net assets of Kinder Morgan Energy Partners by $1.1 million and reducing (i) our excess investment in Kinder Morgan Energy Partners by $11.3 million, (ii) associated accumulated deferred income taxes by $4.1 million, (iii) paid-in capital by $6.1 million and (iv) the monthly amortization of the excess investment by approximately $21 thousand; see Notes 1(Q) and 3. In March 2000, we sold the 918,367 shares of Tom Brown, Inc. common stock we had held since early 1996 (see the discussion of the sale of Tom Brown preferred stock following). We recorded a pre-tax gain of $1.4 million ($0.8 million after tax or approximately $0.01 per diluted common share) in conjunction with the sale. On December 30, 1999, we entered into an agreement with several of our wholly owned subsidiaries and Kinder Morgan Energy Partners. As a result, effective as of December 31, 1999, we transferred all of our interests in the following to Kinder Morgan Energy Partners: (i) our wholly owned subsidiary, Kinder Morgan Interstate Gas Transmission LLC (formerly K N Interstate Gas Transmission Co.), (ii) our wholly owned subsidiary, Kinder Morgan Trailblazer LLC (formerly NGPL-Trailblazer, Inc.), which owns a one-third interest in Trailblazer Pipeline Company and (iii) our 49% interest in Red Cedar Gathering Company. In exchange, Kinder Morgan Energy Partners issued to us 19.6 million common units representing limited partnership interest in Kinder Morgan Energy Partners. In addition, Kinder Morgan Energy Partners paid us $330 million in cash in early 2000. We recorded a pre-tax gain of $127.0 million (approximately $80.7 million after tax or $1.00 per diluted common share) in conjunction with the transfer of these interests. On September 30, 1999, we sold (to an unaffiliated party) our interests in Stingray Pipeline Company, L.L.C., an offshore pipeline that gathers natural gas, and West Cameron Dehydration Company, L.L.C., which dehydrates natural gas for shippers on the Stingray Pipeline. On June 30, 1999, we sold our interests in the HIOS and UTOS offshore pipeline systems and related laterals to Leviathan Gas Pipeline Partners, L. P. These two sales yielded total cash proceeds of approximately $75.1 million, resulted in a total pre-tax gain of approximately $28.9 million (approximately $17.6 million after tax or $0.25 per diluted share), and substantially eliminated our investment in offshore assets. On September 3, 1999, we sold 1,000,000 shares of preferred stock of Tom Brown, Inc. for approximately $29 million in cash. We recorded a pre-tax gain of $2.2 million (approximately $1.3 million after tax or $0.02 per diluted share) in conjunction with the sale. On March 31, 1999, the TransColorado Gas Transmission Company ("TransColorado"), an enterprise we jointly own with Questar Corp., placed in service a 280-mile-long natural gas pipeline. This pipeline includes two compressor stations and extends from near Rangely, Colorado, to its southern terminus at the Blanco Hub near Aztec, New Mexico. The pipeline has a design transmission capacity of approximately 300 million cubic feet of natural gas per day. Beginning 24 months after the in-service date, Questar has the right, for a 12-month period, to require that we purchase Questar's ownership interest in TransColorado for $121 million. This right has been stayed; see Note 10. See Note 7 for information regarding sales of assets and businesses included in discontinued operations. 7. DISCONTINUED OPERATIONS Prior to mid-1999, we had major business operations in the upstream (gathering and processing), midstream (natural gas pipelines) and downstream (wholesale and retail marketing) portions of the natural gas industry and, in addition, had (i) non-energy retail marketing operations in the form of a joint 64 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) venture called EN -- able and (ii) limited international operations. During the third quarter of 1999, we adopted a plan to discontinue the direct marketing of non-energy products and services (principally under the "Simple Choice" brand). During the fourth quarter of 1999 and following our merger with Kinder Morgan Delaware, we adopted and implemented plans to discontinue the following lines of business: (i) gathering and processing natural gas, including short-haul intrastate pipelines and providing field services to natural gas producers, (ii) wholesale marketing of natural gas and natural gas liquids, and (iii) international operations, which we subsequently decided to retain as discussed following. In accordance with the provisions of Accounting Principles Board Opinion No. 30, Reporting the Results of Operations -- Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions ("APB 30"), our consolidated financial statements have been restated to present these businesses as discontinued operations. Accordingly, the revenues, costs and expenses, assets and liabilities and cash flows of these discontinued operations have been excluded from the respective captions in the accompanying Consolidated Statements of Operations and Consolidated Statements of Cash Flows, and have been reported in the various statements under the captions "Loss from Discontinued Operations, Net of Tax"; "Loss on Disposal of Discontinued Operations, Net of Tax"; "Net Cash Flows Provided by (Used in) Discontinued Operations" and "Net Cash Flows Provided by (Used in) Discontinued Investing Activities" for all relevant periods. In addition, certain of these Notes have been restated for all relevant periods to reflect the discontinuance of these operations. During the fourth quarter of 2000, we decided that, due to the start-up nature of these operations and the unwillingness of buyers to pay for the value created to date, it was not in the best interests of the Company to dispose of our international operations, which consist principally of a natural gas distribution system under development in Hermosillo, Mexico. Consequently, results from our international operations have been reclassified to continuing operations for all periods presented. The $3.9 million estimated after-tax loss on disposal recorded in 1999, consisting principally of a write down to estimated net realizable value including estimated costs of disposal, was reversed in 2000 and is included under the caption "Loss on Disposal of Discontinued Operations" in the accompanying Consolidated Statements of Operations. The following table contains additional information concerning our international operations. INTERNATIONAL OPERATIONS
YEAR ENDED DECEMBER 31, ----------------------- 2000 1999 --------- --------- (THOUSANDS OF DOLLARS) Total Assets (at December 31)............................... $32,347 $25,325 Total Liabilities (at December 31).......................... $ 3,984 $ 29 Operating Revenues.......................................... $ 5,699 $ 1,129 Operating Loss.............................................. $ 2,071 $ 2,523
65 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Summarized financial data of discontinued operations are as follows:
YEAR ENDED DECEMBER 31, ----------------------- INCOME STATEMENT DATA 2000 1999 - --------------------- --------- ----------- (IN THOUSANDS) Operating Revenues: Wholesale Natural Gas and Liquids Marketing............... $580,159 $3,550,568 Gathering and Processing, Including Field Services and Short-haul Intrastate Pipelines........................ $436,979 $ 630,005 Loss From Discontinued Operations, Net of Tax: Wholesale Marketing, Net of Tax Benefits of $9,300..... $ (15,046) Gathering and Processing, Net of Tax Benefits of $18,177.............................................. $ (29,404) EN -- able/Orcom, Net of Tax Benefits of $4,150........ $ (6,491) Loss on Disposal of Discontinued Operations, Net of Tax: Wholesale Marketing, Net of Tax Benefits of $2,013 and $34,588.............................................. $ (3,013) $ (55,780) Gathering and Processing, Net of Tax Benefits of $21,617 and $169,413................................. $(32,638) $ (273,202) EN -- able/Orcom, Net of Tax Benefits of $7,340........ $ (11,479) International Operations, Net of $2,430 of Tax and $2,430 of Tax Benefits............................... $ 3,917 $ (3,917)
With the exception of our international operations, which, as discussed above, we decided to retain, we completed the divestiture of our discontinued operations by December 31, 2000. In the fourth quarter of 2000, we recorded an incremental loss on disposal of discontinued operations of $31.7 million, representing the impact of the final disposition transactions and adjustment of previously recorded estimates. We had a remaining liability of approximately $5.2 million at December 31, 2001 associated with these discontinued operations, principally consisting of indemnification obligations under the various sale agreements. Following is additional information concerning the various disposition transactions. We completed the disposition of our investment in EN -- able and sold our businesses involved in providing field services to natural gas producers (K N Field Services, Inc. and Compressor Pump and Engine, Inc.) and MidCon Gas Products of New Mexico Corp., a wholly owned subsidiary providing natural gas gathering and processing services, prior to the end of 1999. We received $23.3 million in cash as consideration for these sales. Effective March 1, 2000, ONEOK purchased (i) our gathering and processing businesses in Oklahoma, Kansas and West Texas, (ii) our marketing and trading business and (iii) certain storage, gathering and transmission pipelines in the Mid-continent region. As consideration, ONEOK paid us approximately $108 million plus approximately $56 million for estimated net working capital at closing. In addition, ONEOK assumed (i) the operating lease associated with the Bushton, Kansas processing plant (although we remain secondarily liable as discussed in Note 18) and (ii) long-term throughput capacity commitments on Natural Gas Pipeline Company of America and Kinder Morgan Interstate. During the second quarter of 2000, we completed the sale of three natural gas gathering systems and a natural gas processing facility to WBI Holdings, Inc., the natural gas pipeline unit of MDU Resources Group, Inc. for approximately $21 million. Gathering systems included in the sale were the Bowdoin System located in north-central Montana, the Niobrara System located in northeastern Colorado and northwestern Kansas, and the Yenter System located in northeastern Colorado and western Nebraska. The natural gas processing facility included in the sale was the Yenter Plant, located northwest of Sterling, Colorado. 66 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) During the fourth quarter of 2000, Wildhorse Energy Partners, LLC distributed all of its assets to its members and ended its operations. Formed in 1996, Wildhorse was owned 55 percent by us and 45 percent by Tom Brown, Inc. All the Wildhorse gathering and processing assets were distributed to Tom Brown and we received the Wolf Creek storage facility (which will be utilized in our natural gas distribution business) and cash. Also during the fourth quarter of 2000, our Douglas and Casper gas processing facilities and associated natural gas gathering systems, our 50 percent interest in Coyote Gas Treating, LLC and our 25 percent interest in Thunder Creek Gas Services, L.L.C. were included as part of a larger transaction with Kinder Morgan Energy Partners; see Note 6. 8. ACCOUNTS RECEIVABLE SALES FACILITY In September 1999, certain of our wholly owned subsidiaries entered into a five-year agreement to sell all of their accounts receivable, on a revolving basis, to K N Receivables Corporation, our wholly owned subsidiary. K N Receivables was formed prior to the execution of that receivables agreement for the purpose of buying and selling accounts receivable and was determined to be bankruptcy remote. Also in September 1999, K N Receivables entered into a five-year agreement with a financial institution whereby K N Receivables could sell, on a revolving basis, an undivided percentage ownership interest in certain eligible accounts receivable, as defined, up to a maximum of $150 million. This transaction was accounted for as a sale of receivables. Losses from the sale of these receivables are included in "Other, Net" in the accompanying Consolidated Statements of Operations during the periods in which the facility was utilized. We received compensation for servicing that was approximately equal to the amount an independent servicer would receive. Accordingly, no servicing assets or liabilities were recorded. The full amount of the allowance for possible losses was retained by K N Receivables. The fair value of this recourse liability approximated the allocated allowance for doubtful accounts given the short-term nature of the transferred receivables. We received $150 million in proceeds from the sale of receivables in 1999. The proceeds were used to retire notes payable of Kinder Morgan Delaware that were outstanding when we acquired it. In 2000 we repaid $150 million and terminated the agreement. Cash flows associated with this program are included with "Accounts Receivable" under "Cash Flows from Operating Activities" in the accompanying Statements of Consolidated Cash Flows for 1999 and 2000. 9. REGULATORY MATTERS On July 17, 2000, Natural Gas Pipeline Company of America filed its compliance plan, including pro forma tariff sheets, pursuant to the FERC's Order Nos. 637 and 637-A. The FERC directed all interstate pipelines to file pro forma tariff sheets to comply with new regulatory requirements in the Orders regarding scheduling procedures, capacity segmentation, imbalance management services and penalty credits, or in the alternative, to explain why no changes to existing tariff provisions are necessary. A technical conference was held on July 10, 2001 to discuss Natural Gas Pipeline Company of America's Order 637 filing. Parties have filed comments on Natural Gas Pipeline Company of America's filing and all parties are awaiting the FERC's decision. Numerous issues regarding Order Nos. 637, 637-A and 637-B are on appeal in the Court of Appeals for the District of Columbia. Briefing has been completed and the oral argument was held on November 29, 2001. Currently, there are no material proceedings challenging the rates on any of our pipeline systems. Nonetheless, shippers on our pipelines do have rights to challenge the rates we charge under certain circumstances prescribed by applicable regulations. There can be no assurance that we will not face challenges to the rates we receive for services on our pipeline systems in the future. 67 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 10. ENVIRONMENTAL AND LEGAL MATTERS (A) ENVIRONMENTAL MATTERS We have an established environmental reserve of approximately $18 million, excluding any cost of remediation described below, at December 31, 2001 to address remediation issues associated with approximately 35 projects. After consideration of reserves established, we believe that costs for environmental remediation and ongoing compliance with these regulations will not have a material adverse effect on our cash flows, financial position or results of operations or diminish our ability to operate our businesses. However, there can be no assurances that future events, such as changes in existing laws, the promulgation of new laws, or the development of new facts or conditions will not cause us to incur significant costs. (B) LITIGATION MATTERS K N TransColorado, Inc. v. TransColorado Gas Transmission Company, et. al, Case No. 00-CV-129, District Court, County of Garfield, State of Colorado. On June 15, 2000, K N TransColorado filed suit against Questar TransColorado, its parent Questar Pipeline Company, and other affiliated Questar entities, asserting claims for breach of fiduciary duties, breach of contract, constructive trust, rescission of the partnership agreement, breach of good faith and fair dealing, tortious concealment, misrepresentation, aiding and abetting a breach of fiduciary duty, dissolution of the TransColorado partnership, and seeking a declaratory judgment, among other claims. The TransColorado partnership has been made a defendant for purposes of an accounting. The lawsuit alleges, among other things, Questar breached its fiduciary duties as a partner. K N TransColorado seeks to recover damages in excess of $152 million due to Questar's breaches and, in addition, seeks punitive damages. In response to the complaint, on July 28, 2000, the Questar entities filed a counterclaim and third party claims against Kinder Morgan and certain of its affiliates for claims arising out of the construction and operation of the TransColorado pipeline project. The claims allege, among other things, that the Kinder Morgan entities interfered with and delayed construction of the pipeline and made misrepresentations about marketing of capacity. The Questar entities seek to recover damages in excess of $185 million for an alleged breach of fiduciary duty and other claims. The parties agreed to stay the exercise of a contractual provision purportedly requiring K N TransColorado to purchase Questar's interest in the pipeline and to investigate the appointment of an independent operator for the pipeline during the litigation. The Court dismissed Questar's counterclaims for breach of duty of good faith and fair dealing and for indemnity and contribution and dismissed Questar's Third Party Complaint. On July 19, 2001, the Court granted K N TransColorado's motion for summary judgment that: a) fiduciary duties existed between the partners; b) these fiduciary duties were not modified or waived; and c) the affiliates and directors of Questar Pipeline Company and Questar TransColorado acting in their dual capacity had fiduciary obligations which required those individuals to disclose, to the partnership and the partners, information that affected the fundamental business purpose of the partnership. On August 14, 2001, the Court granted leave to Questar to file its First Amended Answer and Counterclaim, once again naming Kinder Morgan, Inc. as a counterclaim defendant, and making similar allegations against us as set forth above. Fact discovery and expert discovery have closed. The case is set for trial on April 1, 2002. Jack J. Grynberg, individually and as general partner for the Greater Green River Basin Drilling Program: 72-73 v. Rocky Mountain Natural Gas Company and K N Energy, Inc., Case No. 90-CV-3686. On June 5, 1990, Jack J. Grynberg filed suit, which is presently pending in Jefferson County District Court for Colorado, against Rocky Mountain Natural Gas Company and us alleging breach of contract and fraud. In essence, Grynberg asserts claims that the named companies failed to pay Grynberg the proper price, impeded the flow of natural gas, mismeasured natural gas, delayed his development of natural gas reserves, and other claims arising out of a contract to purchase natural gas from a field in northwest Colorado. On February 13, 1997, the trial judge entered partial summary judgment for Grynberg on his contract claim that he failed to receive the proper price for his natural gas. This ruling followed an appellate decision that was adverse to us on the contract interpretation of the price issue, but which did 68 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) not address the question of whether Grynberg could legally receive the price he claimed or whether he had illegally diverted natural gas from a prior purchase. Grynberg has previously claimed damages in excess of $30 million. On August 29, 1997, the trial judge stayed the summary judgment pending resolution of a proceeding at the FERC to determine if Grynberg was entitled to administrative relief from an earlier dedication of the same natural gas to interstate commerce. On March 15, 1999, an Administrative Law Judge for the FERC ruled, after an evidentiary hearing, that Mr. Grynberg had illegally diverted the natural gas when he entered the contract with the named companies and was not entitled to relief. Grynberg filed exceptions to this ruling. In late March 2000, the FERC issued an order affirming in part and denying in part the motions for rehearing of its Initial Decision. On November 21, 2000, the FERC upheld the Administrative Law Judge's factual findings and denial of retroactive abandonment. On June 14, 2001, Rocky Mountain Natural Gas Company filed a motion for Summary Judgment and To Vacate the February 13, 1997, Partial Summary Judgment, as a result of the conclusion of the FERC proceedings. On August 16, 2001, the Court granted Plaintiff's Motion to Continue the Stay of these proceedings pending the proceedings in federal court. The parties have reached a settlement in principle of this matter and the federal court matter. The settlement is conditioned on certain findings by a Special Master. Jack J. Grynberg v. K N Energy, Inc., Rocky Mountain Natural Gas Company, and GASCO, Inc., Civil Action No. 92-N-2000. On October 9, 1992, Jack J. Grynberg filed suit in the United States District Court for the District of Colorado against us, Rocky Mountain Natural Gas Company and GASCO, Inc. alleging that these entities, the K N Entities, as well as K N Production Company and K N Gas Gathering, Inc., have violated federal and state antitrust laws. In essence, Grynberg asserts that the companies have engaged in an illegal exercise of monopoly power, have illegally denied him economically feasible access to essential facilities to store, transport and distribute gas, and illegally have attempted to monopolize or to enhance or maintain an existing monopoly. Grynberg also asserts certain state causes of action relating to a gas purchase contract. In February 1999, the Federal District Court granted summary judgment for the K N Entities as to some of Grynberg's antitrust and state law claims, while allowing other claims to proceed to trial. Grynberg has previously claimed damages in excess of $50 million. In addition to monetary damages, Grynberg has requested that the K N Entities be ordered to divest all interests in natural gas exploration, development and production properties, all interests in distribution and marketing operations, and all interests in natural gas storage facilities, in order to separate these interests from our natural gas gathering and transportation system in northwest Colorado. The parties have reached a settlement in principle of this matter and the state court matter. The court has ordered that the settlement be finalized by March 15, 2002, or the federal case will proceed to trial. The settlement is conditioned on certain findings by a Special Master. United States of America, ex rel., Jack J. Grynberg v. K N Energy, Civil Action No. 97-D-1233, filed in the U.S. District Court, District of Colorado. This action was filed on June 9, 1997 pursuant to the federal False Claim Act and involves allegations of mismeasurement of natural gas produced from federal and Indian lands. The Department of Justice has decided not to intervene in support of the action. The complaint is part of a larger series of similar complaints filed by Mr. Grynberg against 77 natural gas pipelines (approximately 330 other defendants). An earlier single action making substantially similar allegations against the pipeline industry was dismissed by Judge Hogan of the U.S. District Court for the District of Columbia on grounds of improper joinder and lack of jurisdiction. As a result, Mr. Grynberg filed individual complaints in various courts throughout the country. These cases were recently consolidated by the Judicial Panel for Multidistrict Litigation, and transferred to the District of Wyoming. Motions to Dismiss were filed and an oral argument on the Motion to Dismiss occurred on March 17, 2000. On July 20, 2000 the United States of America filed a motion to dismiss those claims by Grynberg that deal with the manner in which defendants valued gas produced from federal leases. Judge Downes denied the defendant's motion to dismiss on May 18, 2001. The defendants have sought reconsideration of this Order and have requested a status conference. 69 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Quinque Operating Company, et al. v. Gas Pipelines, et. al., Case No. 99-1390-CM, United States District Court for the District of Kansas. This action was originally filed on May 28, 1999 in Kansas state court in Stevens County, Kansas as a class action against approximately 245 pipeline companies and their affiliates, including certain Kinder Morgan entities. The plaintiffs in the case seek to have the Court certify the case as a class action, a class of natural gas producers and fee royalty owners who allege that they have been subject to systematic mismeasurement of natural gas by the defendants for more than 25 years. Among other things, the plaintiffs allege a conspiracy among the pipeline industry to under-measure gas and have asserted joint and several liability against the defendants. Subsequently, one of the defendants removed the action to Kansas Federal District Court. Thereafter, we filed a motion with the Judicial Panel for Multidistrict Litigation to consolidate this action for pretrial purposes with the Grynberg False Claim Act cases referred to above, because of common factual questions. On April 10, 2000, the MDL Panel ordered that this case be consolidated with the Grynberg federal False Claims Act cases. On January 12, 2001, the Federal District Court of Wyoming issued an oral ruling remanding the case back to the State Court in Stevens County, Kansas. A case management conference occurred in State Court in Stevens County, and a briefing schedule was established for preliminary matters. Personal jurisdiction discovery has commenced. Merits discovery has been stayed. Recently, the defendants filed a motion to dismiss on grounds other than personal jurisdiction, and a motion to dismiss for lack of personal jurisdiction for non- resident defendants. K N Energy, Inc., et al. v. James P. Rode and Patrick R. McDonald, Case No. 99CV1239, filed in the District Court, Jefferson County, Division 8, Colorado. The case was filed on May 21, 1999. Defendants counterclaimed and filed third party claims against several of our former officers and/or directors. Messrs. Rode and McDonald are former principal shareholders of Interenergy Corporation. We acquired Interenergy on December 19, 1997 pursuant to a Merger Agreement dated August 25, 1997. Rode and McDonald allege that K N Energy committed securities fraud, common law fraud and negligent misrepresentation as well as breach in contract. Plaintiffs are seeking an unspecified amount of compensatory damages, greater than $2 million, plus unspecified exemplary or punitive damages, attorney's fees and their costs. We filed a motion to dismiss, and on April 21, 2000, the Jefferson County District Court Judge dismissed the case against the individuals and us with prejudice. On April 6, 2001, the Colorado Court of Appeals affirmed the dismissal. Defendants also filed a federal securities fraud action in the United States District Court for the District of Colorado on January 27, 2000 titled: James P. Rode and Patrick R. McDonald v. K N Energy, Inc., et al., Civil Action No. 00-N-190. This case initially raised the identical state law claims contained in the counterclaim and third party complaint in state court. Rode and McDonald filed an amended Complaint, which dropped the state-law claims. On June 20, 2000, the federal district court dismissed this Complaint with prejudice. Rode and McDonald filed notices of appeal of the federal court dismissal. Briefing on this appeal is complete. A third related class action case styled, Adams vs. Kinder Morgan, Inc., et al., Civil Action No. 00-M-516, in the United States District Court for the District of Colorado was served on us on April 10, 2000. As of this date no class has been certified. On February 23, 2001, the federal district court dismissed several claims raised by the plaintiff, with prejudice, and dismissed the remaining claims, without prejudice. On April 27, 2001, the Adams plaintiffs filed their second amended complaint. We have moved to dismiss this complaint and the briefing on the motion is complete. An oral argument on the motion to dismiss is set for March 29, 2002. We believe that we have meritorious defenses to all lawsuits and legal proceedings in which we are defendants and will vigorously defend against them. Based on our evaluation of the above matters, and after consideration of reserves established, we believe that the resolution of such matters will not have a material adverse effect on our businesses, cash flows, financial position or results of operations. 70 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 11. PROPERTY, PLANT AND EQUIPMENT Investments in property, plant and equipment ("PP&E"), at cost, and accumulated depreciation and amortization ("Accumulated D&A") are as follows:
DECEMBER 31, 2001 ------------------------------------------ PROPERTY, PLANT ACCUMULATED AND EQUIPMENT D&A NET --------------- ----------- ---------- (IN THOUSANDS) Natural Gas Pipelines.......................... $5,613,578 $216,302 $5,397,276 Retail Natural Gas Distribution................ 285,674 101,520 184,154 Electric Power Generation...................... 23,087 3,228 19,859 General and Other.............................. 156,495 53,832 102,663 ---------- -------- ---------- PP&E Related to Continuing Operations.......... $6,078,834 $374,882 $5,703,952 ========== ======== ==========
DECEMBER 31, 2000 ------------------------------------------ PROPERTY, PLANT ACCUMULATED AND EQUIPMENT D&A NET --------------- ----------- ---------- (IN THOUSANDS) Natural Gas Pipelines.......................... $5,662,880 $262,073 $5,400,807 Retail Natural Gas Distribution................ 251,660 90,966 160,694 Electric Power Generation...................... 23,070 2,608 20,462 General and Other.............................. 142,773 56,745 86,028 ---------- -------- ---------- PP&E Related to Continuing Operations.......... $6,080,383 $412,392 $5,667,991 ========== ======== ==========
12. INCOME TAXES Components of the income tax provision applicable to continuing operations for federal and state income taxes are as follows:
YEAR ENDED DECEMBER 31, ----------------------------- 2001 2000 1999 -------- -------- ------- (DOLLARS IN THOUSANDS) TAXES CURRENTLY PAYABLE: Federal............................................. $ 3,729 $ 3,212 $19,340 State............................................... 25,917 14,091 13,784 -------- -------- ------- Total............................................... 29,646 17,303 33,124 -------- -------- ------- TAXES DEFERRED: Federal............................................. 128,266 94,688 52,942 State............................................... 10,689 11,026 (6,942) -------- -------- ------- 138,955 105,714 46,000 -------- -------- ------- TOTAL TAX PROVISION................................... $168,601 $123,017 $79,124 ======== ======== ======= EFFECTIVE TAX RATE.................................... 41.4% 40.0% 36.9% ======== ======== =======
71 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The difference between the statutory federal income tax rate and our effective income tax rate is summarized as follows:
YEAR ENDED DECEMBER 31, ----------------------- 2001 2000 1999 ----- ----- ----- FEDERAL INCOME TAX RATE..................................... 35.0% 35.0% 35.0% INCREASE (DECREASE) AS A RESULT OF: State Income Tax, Net of Federal Benefit.................. 5.7% 5.6% 1.9% Kinder Morgan Management minority interest................ 1.4% -- -- Other..................................................... (0.7)% (0.6)% -- ---- ---- ---- EFFECTIVE TAX RATE.......................................... 41.4% 40.0% 36.9% ==== ==== ====
Income taxes included in the financial statements were composed of the following:
YEAR ENDED DECEMBER 31, ------------------------------- 2001 2000 1999 -------- -------- --------- Continuing Operations............................... $168,601 $123,017 $ 79,124 Discontinued Operations............................. -- (21,200) (245,398) Extraordinary Item.................................. (9,044) -- -- Cumulative Effect Transition Adjustment............. (7,922) -- -- Equity Items........................................ 43,866 (30,311) 568 -------- -------- --------- Total............................................... $195,501 $ 71,506 $(165,706) ======== ======== =========
Deferred tax assets and liabilities result from the following:
DECEMBER 31, ----------------------- 2001 2000 ---------- ---------- (DOLLARS IN THOUSANDS) DEFERRED TAX ASSETS: Postretirement Benefits................................... $ 15,133 $ 14,776 Gas Supply Realignment Deferred Receipts.................. 12,154 17,101 State Taxes............................................... 111,828 138,976 Book Accruals............................................. 29,208 39,505 Alternative Minimum Tax Credits........................... 12,283 9,098 Net Operating Loss Carryforwards.......................... 29,540 107,033 Discontinued Operations................................... 2,089 9,584 Capital Loss Carryforwards................................ 28,640 42,914 Other..................................................... 5,020 4,269 Valuation Allowance....................................... (2,462) -- ---------- ---------- TOTAL DEFERRED TAX ASSETS................................... 243,433 383,256 ---------- ---------- DEFERRED TAX LIABILITIES: Property, Plant and Equipment............................. 1,972,881 2,009,086 Investments............................................... 688,224 642,944 Derivatives............................................... 6,580 -- Other..................................................... 4,252 4,403 ---------- ---------- TOTAL DEFERRED TAX LIABILITIES.............................. 2,671,937 2,656,433 ---------- ---------- NET DEFERRED TAX LIABILITIES................................ $2,428,504 $2,273,177 ========== ==========
72 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) At December 31, 2001, we had available net operating loss carryforwards for regular federal income tax purposes of approximately $84.4 million which will expire in the year 2020. We also had available, at December 31, 2001, capital loss carryforwards of $71.6 million of which $49.0 million will expire in the year 2005 and $22.6 million will expire in the year 2006. A valuation allowance of $2.5 million has been provided for the deferred tax benefits related to the portion of capital loss carryforwards that may not be utilized in the future. We also had available, at December 31, 2001, approximately $12.3 million of alternative minimum tax credit carryforwards, which are available indefinitely. 13. FINANCING (A) NOTES PAYABLE At December 31, 2001, we had available a $500 million 364-day facility dated October 23, 2001, and a $400 million amended and restated five-year revolving credit agreement dated January 30, 1998. These bank facilities can be used for general corporate purposes, including backup for our commercial paper program, and include covenants that are common in such arrangements. For example, the $500 million facility requires consolidated debt to be less than 68% of consolidated capitalization. The $400 million facility requires that consolidated debt must be less than 67% of consolidated total capitalization. Both of the bank facilities require the debt of consolidated subsidiaries to be less than 10% of our consolidated debt and require the consolidated debt of each material subsidiary to be less than 65% of our consolidated total capitalization. The $400 million facility requires our consolidated net worth (inclusive of trust preferred securities) be at least $1.236 billion plus 50 percent of consolidated net income earned for each fiscal quarter beginning with the last quarter of 1998. The $500 million facility requires our consolidated net worth (inclusive of trust preferred securities) be at least $1.236 billion plus 50 percent of consolidated net income earned for each fiscal quarter beginning with the last quarter of 1999. Under the bank facilities, we are required to pay a facility fee based on the total commitment, at a rate that varies based on our senior debt investment rating. Facility fees paid in 2001 and 2000 were $1.4 million and $1.6 million, respectively. At December 31, 2001 and 2000, $0 million and $100 million, respectively, was outstanding under the bank facilities. Commercial paper issued by us and supported by the bank facilities are unsecured short-term notes with maturities not to exceed 270 days from the date of issue. During 2001, all commercial paper was redeemed within 92 days, with interest rates ranging from 1.60 percent to 7.50 percent. Commercial paper outstanding at December 31, 2001 was $423.8 million. No commercial paper was outstanding at December 31, 2000. The weighted-average interest rate on short-term borrowings outstanding at December 31, 2001 was 2.87 percent. Average short-term borrowings outstanding during 2001 and 2000 were $447.8 million and $310.6 million, respectively. During 2001 and 2000, the weighted-average interest rates on short-term borrowings outstanding were 3.91 percent and 6.52 percent, respectively. On January 4, 1999, we repaid a short-term note for $1.4 billion which had been payable to Occidental Petroleum Corporation that we had assumed in connection with the early-1998 acquisition of MidCon Corp. The note was repaid using the proceeds of approximately $1.1 billion from the sale of U.S. government securities that had been held as collateral, with the balance of the funds provided by an increase in short-term borrowings. 73 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (B) LONG-TERM DEBT AND PREMIUM EQUITY PARTICIPATING SECURITY UNITS
DECEMBER 31, ----------------------- 2001 2000 ---------- ---------- (IN THOUSANDS) DEBENTURES: 6.50% Series, Due 2013.................................... $ 50,000 $ 50,000 7.85% Series, Due 2022.................................... 24,025 24,943 8.75% Series, Due 2024.................................... 75,000 75,000 7.35% Series, Due 2026.................................... 125,000 125,000 6.67% Series, Due 2027.................................... 150,000 150,000 7.25% Series, Due 2028.................................... 493,000 493,000 7.45% Series, Due 2098.................................... 150,000 150,000 SINKING FUND DEBENTURES: 9.95% Series Due 2020..................................... -- 20,000 9.625% Series Due 2021.................................... -- 45,000 8.35% Series, Due 2022.................................... 35,000 35,000 SENIOR NOTES: 6.45% Series, Due 2001.................................... -- 400,000 7.27% Series, Due 2002.................................... 5,000 10,000 6.45% Series, Due 2003.................................... 500,000 500,000 6.65% Series, Due 2005.................................... 500,000 500,000 6.80% Series, Due 2008.................................... 300,000 300,000 Floating Rate Notes, Due 2002............................... 200,000 -- Reset Put Securities, 6.30% due 2021........................ -- 400,000 Other....................................................... 12,350 13,617 Carrying Value Adjustment for Interest Rate Swaps(1)........ (4,831) -- Unamortized Debt Discount................................... (3,310) (4,410) Current Maturities of Long-term Debt........................ (206,267) (808,167) ---------- ---------- TOTAL LONG-TERM DEBT........................................ $2,404,967 $2,478,983 ========== ==========
- --------------- (1) Adjustment of carrying value of long-term securities subject to interest rate swaps; see Note 15. Maturities of long-term debt (in thousands) for the five years ending December 31, 2006 are $206,267, $501,267, $1,267, $501,267, and $6,017, respectively. The 2013 Debentures and the 2003 and 2005 Senior Notes are not redeemable prior to maturity. The 2022, 2028 and 2098 Debentures and the 2002 and 2008 Senior Notes are redeemable in whole or in part, at our option at any time, at redemption prices defined in the associated prospectus supplements. The 2024, 2026 and 2027 Debentures are redeemable in whole or in part, at our option after October 15, 2002, August 1, 2006, and November 1, 2004, respectively, at redemption prices defined in the associated prospectus supplements. The 2022 Sinking Fund Debentures are redeemable in whole or in part, at our option after September 15, 2002, at redemption prices defined in the associated prospectus supplement. On November 30, 2001, our Premium Equity Participating Security Units matured, which resulted in our receipt of $460 million in cash and our issuance of 13,382,474 shares of additional common stock. We used the cash proceeds to retire the $400 million of 6.45% Series of Senior Notes that became due on the same date and a portion of our short-term borrowings then outstanding. 74 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) On October 10, 2001, we issued $200 million of Floating Rate Notes due October 10, 2002 in an offering made pursuant to Rule 144A of the regulations of the Securities and Exchange Commission. These notes bear interest at the three-month London Interbank Offered Rate (LIBOR) plus 95 basis points, with interest paid quarterly. The proceeds from the offering were used to retire a portion of our short-term borrowings then outstanding. On September 10, 2001, we retired our $45 million of 9.625% Series Sinking Fund Debentures due March 1, 2021, utilizing incremental short-term borrowings. In March 2001, we retired (i) our $400 million of Reset Put Securities due March 1, 2021 and (ii) our $20 million of 9.95% Series Sinking Fund Debentures due 2020, utilizing a combination of cash and incremental short-term borrowings. In conjunction with these early extinguishments of debt, we recorded extraordinary losses of $13.6 million (net of associated tax benefit of $9.0 million). These losses are included under the caption, "Extraordinary Item, Loss on Early Extinguishment of Debt" in the accompanying Consolidated Statements of Operations for 2001. At December 31, 2001 and 2000, the carrying amount of our long-term debt was $2.6 billion and $3.3 billion, respectively. The estimated fair values of our long-term debt at December 31, 2001 and 2000 are shown in Note 19. (C) CAPITAL SECURITIES Our wholly owned business trusts, K N Capital Trust I and K N Capital Trust III, are obligated for $100 million of 8.56% Capital Trust Securities maturing on April 15, 2027 and $175 million of 7.63% Capital Trust Securities maturing on April 15, 2028, respectively. The transactions and balances of K N Capital Trust I and K N Capital Trust III are included in our consolidated financial statements, with the Capital Securities treated as a minority interest, shown in our Consolidated Balance Sheets under the caption "Kinder Morgan-Obligated Mandatorily Redeemable Preferred Capital Trust Securities of Subsidiary Trust Holding Solely Debentures of Kinder Morgan." Periodic payments made to the holders of these securities are classified under "Minority Interests" in the accompanying Consolidated Statements of Operations. See Note 19 for the fair value of these securities. (D) COMMON STOCK On February 14, 2002, we paid a cash dividend on our common stock of $0.05 per share to stockholders of record as of January 31, 2002. On August 14, 2001, we announced a plan to repurchase $300 million of our outstanding common stock under a program expected to be completed by the end of 2002. At the trading price at the time of the announcement, the $300 million represented approximately 5.7 million shares, or about 4.4 percent of the shares outstanding. As of December 31, 2001, we had repurchased under the program approximately $270.4 million (5,294,800 shares) of our outstanding common stock. On February 5, 2002, we announced that our Board of Directors had approved expanding the plan to a total of $400 million. On November 17, 1999, our Board of Directors approved a reduction in the quarterly dividend from $0.20 per share to $0.05 per share. (E) KINDER MORGAN MANAGEMENT, LLC In May 2001, Kinder Morgan Management, one of our indirect subsidiaries, issued and sold its shares in an underwritten initial public offering. The net proceeds from the offering were used by Kinder Morgan Management to buy i-units from Kinder Morgan Energy Partners for $991.9 million. Upon purchase of the i-units, Kinder Morgan Management became a partner in Kinder Morgan Energy Partners and was delegated by Kinder Morgan Energy Partners' general partner the responsibility to manage and control 75 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Kinder Morgan Energy Partners' business and affairs. The i-units are a class of Kinder Morgan Energy Partners' limited partner interests that have been, and will be, issued only to Kinder Morgan Management. In the initial public offering, 10 percent of Kinder Morgan Management's shares were purchased by Kinder Morgan, Inc., with the balance purchased by the public. The equity interest in Kinder Morgan Management (our consolidated subsidiary) purchased by the public created a minority interest on our balance sheet of $892.7 million at the time of the transaction. See Note 2 for additional information regarding these transactions. 14. PREFERRED STOCK We have authorized 200,000 shares of Class A and 2,000,000 shares of Class B preferred stock, all without par value. (A) CLASS A $5.00 CUMULATIVE PREFERRED STOCK On April 13, 1999, we sent notices to holders of our Class A $5.00 Cumulative Preferred Stock of our intent to redeem these shares on May 14, 1999. Holders of 70,000 preferred shares were advised that on April 13, 1999, funds were deposited with the First National Bank of Chicago to pay the redemption price of $105 per share plus accrued but unpaid dividends. Under the terms of our Articles of Incorporation, upon deposit of funds to pay the redemption price, all rights of the preferred stockholders ceased and terminated except the right to receive the redemption price upon surrender of their stock certificates. At December 31, 2001, 2000 and 1999, we did not have any outstanding shares of Class A $5.00 Cumulative Series Preferred Stock. (B) CLASS B PREFERRED STOCK We did not have any outstanding shares of Class B Preferred Stock at December 31, 2001, 2000 or 1999. 15. RISK MANAGEMENT Effective January 1, 2001, we adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 137, Accounting for Derivative Instruments and Hedging Activities -- Deferral of the Effective Date of FASB Statement No. 133 and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, collectively, "Statement 133." Statement 133 established accounting and reporting standards requiring that every derivative financial instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. The accompanying Consolidated Balance Sheet as of December 31, 2001, includes balances of approximately $29.0 million, $0.5 million and $13.2 million in the captions "Current Assets: Other," "Deferred Charges and Other Assets" and "Current Liabilities: Other," respectively, related to these derivative financial instruments. Statement 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. If the derivatives meet those criteria, Statement 133 allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company formally designate a derivative as a hedge and document and assess the effectiveness of derivatives associated with transactions that receive hedge accounting. We enter into derivative contracts solely for the purpose of hedging exposures that accompany our normal business activities. As a result of the adoption of Statement 133, the fair value of our derivative financial instruments utilized for hedging activities as of January 1, 2001 (a loss of $11.9 million) was reported as a cumulative effect transition adjustment within accumulated other comprehensive income. All but an insignificant amount of this transition adjustment was reclassified into earnings during 2001. In 76 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) accordance with the provisions of Statement 133, we designated these instruments as hedges of various exposures as discussed following, and we test the effectiveness of changes in the value of these hedging instruments with the risk being hedged. Hedge ineffectiveness is recognized in income in the period in which it occurs. We enter into these transactions only with counterparties whose debt securities are rated investment grade by the major rating agencies. In general, the risk of default by these counterparties is low. However, we recently experienced a loss as discussed following. During the fourth quarter of 2001, we determined that Enron Corp. was no longer likely to honor the obligations it had to us in conjunction with derivatives we were accounting for as hedges under Statement 133. Upon making that determination, we (i) ceased to account for those derivatives as hedges, (ii) entered into new derivative transactions with other counterparties to replace our position with Enron, (iii) designated the replacement derivative positions as hedges of the exposures that had been hedged with the Enron positions and (iv) recognized a $5.0 million pre-tax loss (included with "General and Administrative Expenses" in the accompanying Consolidated Statement of Operations for 2001) in recognition of the fact that it was unlikely that we would be paid the amounts then owed under the contracts with Enron. While we enter into derivative transactions only with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that additional losses will result from counterparty credit risk in the future. Our businesses require that we purchase, sell and consume natural gas. Specifically, we purchase, sell and/or consume natural gas (i) to serve our regulated natural gas distribution sales customers, (ii) to serve certain of our retail natural gas distribution customers in areas where regulatory restructuring has provided for competition in natural gas supply, for customers who have selected the Company as their supplier of choice under our "Choice Gas" program, (iii) as fuel in our Colorado power generation facilities, (iv) as fuel for compressors located on Natural Gas Pipeline Company of America's pipeline system and (v) for operational sales of gas by Natural Gas Pipeline Company of America. With respect to item (i), we have no commodity risk because the regulated retail gas distribution regulatory structure provides that actual gas cost is "passed-through" to our customers. With respect to item (iii), only one of these power generation facilities is not covered by a long-term, fixed price gas supply agreement at a level sufficient for the current and projected capacity utilization. With respect to item (iv), this fuel is supplied by in-kind fuel recoveries that are part of the transportation tariff. Items (ii), (v) and the one power facility included under item (iii) that is not covered by a long-term fixed-price natural gas supply agreement, give rise to natural gas commodity price risk which we have chosen to substantially mitigate through our risk management program. We provide this mitigation through the use of financial derivative products, and we do not utilize these derivatives for any purpose other than risk mitigation. Under our Choice Gas program, customers in certain areas served by Kinder Morgan Retail are allowed to choose their natural gas supplier from a list of qualified suppliers, although the transportation of the natural gas to the homes and businesses continues to be provided by Kinder Morgan Retail in all cases. When those customers choose an affiliate of Kinder Morgan Retail as their supplier, we enter into agreements providing for sales of gas to these customers during a one-year period at fixed prices per unit, but variable volumes. We mitigate the risk associated with these anticipated sales of gas by purchasing natural gas futures contracts on the New York Mercantile Exchange ("NYMEX") and, as applicable, over-the-counter basis swaps to mitigate the risk associated with the difference in price changes between Henry Hub (NYMEX) basis and the expected physical delivery location. In addition, we mitigate a portion of the volumetric risk through the purchase of over-the-counter natural gas options. The time period covered by this risk management strategy does not extend beyond one year. With respect to the power generation facility described above that is not covered by an adequately sized, fixed-price gas supply contract, we are exposed to changes in the price of natural gas as we purchase 77 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) it to use as fuel for the electricity-generating turbines. In order to mitigate this exposure, we purchase natural gas futures on the NYMEX and, as discussed above, over-the-counter basis swaps on the NYMEX, in amounts representing our expected fuel usage in the near term. In general, we do not hedge this exposure for periods longer than one year. With respect to operational sales of natural gas made by Natural Gas Pipeline Company of America, we are exposed to risk associated with changes in the price of natural gas during the periods in which these sales are made. We mitigate this risk by selling natural gas futures and, as discussed above, over-the-counter basis swaps, on the NYMEX in the periods in which we expect to make these sales. In general, we do not hedge this exposure for periods in excess of 18 months. During 2001, all of our natural gas derivative activities were designated and qualified as cash flow hedges. We recognized approximately $5,000 of pre-tax loss during 2001 as a result of ineffectiveness of these hedges, which amount is reported within the caption "Gas Purchases and Other Costs of Sales" in the accompanying Consolidated Statement of Operations for the year ended December 31, 2001. There was no component of the derivative instruments' gain or loss excluded from the assessment of hedge effectiveness. As the hedged sales and purchases take place and we record them into earnings, we will also reclassify the gains and losses included in accumulated other comprehensive income into earnings. We expect to reclassify into earnings, during 2002, substantially all of the accumulated other comprehensive income balance of $9.9 million at December 31, 2001, representing unrecognized net gains on derivative activities. During 2001, we reclassified no gains or losses into earnings as a result of the discontinuance of cash flow hedges due to a determination that the forecasted transactions would no longer occur by the end of the originally specified time period. We also provide certain administrative risk management services to Kinder Morgan Energy Partners, although Kinder Morgan Energy Partners retains the obligations and rights arising from all derivative transactions entered into on its behalf. In order to maintain a cost effective capital structure, it is our policy to borrow funds utilizing a mixture of fixed-interest-rate and floating-interest-rate debt. In August 2001, in order to move closer to a mix of 50% fixed, 50% floating, we entered into fixed-to-floating interest rate swap agreements with a notional principal amount of $1.0 billion. These agreements effectively converted the interest expense associated with our 6.65% senior notes and our 7.25% debentures from fixed rates to floating rates based on three-month LIBOR plus a credit spread. These swaps have been designated as fair value hedges as defined by Statement 133. These swaps meet the conditions required to assume no ineffectiveness under Statement 133 and, therefore, we have accounted for them utilizing the "shortcut" method prescribed for fair value hedges. Accordingly, the carrying value of the swap is adjusted to its fair value as of each reporting period, with an offsetting entry to adjust the carrying value of the debt whose fair value is being hedged. We record interest expense equal to the floating rate payments, which is accrued monthly and paid semi-annually. Based on short-term borrowings outstanding and the long-term debt effectively converted to floating rate debt as a result of the swap discussed above, at December 31, 2001, the market risk related to a one percent change in interest rates would result in a $16.5 million annual impact on pre-tax income. 78 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Following is selected information concerning our natural gas risk management activities:
DECEMBER 31, 2001 ---------------------------------------- COMMODITY OVER-THE-COUNTER CONTRACTS SWAPS AND OPTIONS TOTAL --------- ----------------- -------- (DOLLARS IN THOUSANDS) Deferred Net (Loss) Gain....................... $(6,525) $ 22,751 $ 16,226 Contract Amounts -- Gross...................... $52,902 $124,145 $177,047 Contract Amounts -- Net........................ $(3,163) $(84,099) $(87,262) (NUMBER OF CONTRACTS(1)) Notional Volumetric Positions: Long............ 556 717 Notional Volumetric Positions: Short........... (907) (2,776) Net Notional Totals To Occur in 2002........... (351) (1,919) Net Notional Totals To Occur in 2003 and Beyond....................................... -- (140)
- --------------- (1) A term of reference describing a volumetric unit of commodity trading. One natural gas contract equals 10,000 MMBtus. Our over-the-counter swaps and options are with a number of parties, each of which is an investment grade credit. We both owe money and are owed money under these financial instruments and, at December 31, 2001, if all parties owing us failed to pay us amounts due at that date under these arrangements, our pre-tax credit loss would have been $12.2 million. At December 31, 2001, the largest credit exposure to a single counterparty was $5.3 million. 16. EMPLOYEE BENEFITS (A) RETIREMENT PLANS We have defined benefit pension plans covering eligible full-time employees. These plans provide pension benefits that are based on the employees' compensation during the period of employment, age and years of service. These plans are tax-qualified subject to the minimum funding requirements of the Employee Retirement Income Security Act of 1974, as amended. Our funding policy is to contribute annually the recommended contribution using the actuarial cost method and assumptions used for determining annual funding requirements. Plan assets consist primarily of pooled fixed income, equity, bond and money market funds. Plan assets included our common stock valued at $12.3 million and $11.5 million as of December 31, 2001 and 2000, respectively. Net periodic pension cost includes the following components:
YEAR ENDED DECEMBER 31, ------------------------------ 2001 2000 1999 -------- -------- -------- (IN THOUSANDS) Service Cost......................................... $ 5,329 $ 7,306 $ 9,977 Interest Cost........................................ 9,421 8,600 8,170 Expected Return on Assets............................ (15,145) (14,034) (13,381) Net Amortization and Deferral........................ (1,282) (1,257) (210) Recognition of Curtailment Gain...................... -- -- (9) -------- -------- -------- Net Periodic Pension (Benefit) Cost.................. $ (1,677) $ 615 $ 4,547 ======== ======== ========
79 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The following table sets forth the reconciliation of the beginning and ending balances of the pension benefit obligation:
2001 2000 --------- --------- (IN THOUSANDS) Benefit Obligation at Beginning of Year.................... $(125,091)(1) $(118,038) Service Cost............................................... (5,329) (7,306) Interest Cost.............................................. (9,421) (8,600) Actuarial (Gain) Loss...................................... (7,447) 3,922 Benefits Paid.............................................. 7,512 6,915 Plan Amendments............................................ (991) -- --------- --------- Benefit Obligation at End of Year.......................... $(140,767) $(123,107) ========= =========
- --------------- (1) Includes benefit obligation of Hall-Buck Plan, as described below. The following table sets forth the reconciliation of the beginning and ending balances of the fair value of the plans' assets, the plans' funded status and prepaid pension cost. Prepaid pension cost is recognized under the caption "Other Current Assets" in our Consolidated Balance Sheets:
DECEMBER 31, ------------------------ 2001 2000 --------- --------- (IN THOUSANDS) Fair Value of Plan Assets at Beginning of Year............. $ 163,096(1) $ 150,900 Actual Return on Plan Assets During the Year............... (6,211) 17,294 Contributions by Employer.................................. 104 -- Benefits Paid During the Year.............................. (7,512) (6,915) --------- --------- Fair Value of Plan Assets at End of Year................... 149,477 161,279 Benefit Obligation at End of Year.......................... (140,767) (123,107) --------- --------- Plan Assets in Excess of Projected Benefit Obligation...... 8,710 38,172 Unrecognized Net Gain...................................... (2,770) (33,134) Prior Service Cost Not Yet Recognized in Net Periodic Pension Costs............................................ 993 88 Adjustment to Recognize Minimum Liability.................. (207) -- Unrecognized Net Asset at Transition....................... (529) (696) --------- --------- Prepaid Pension Cost....................................... $ 6,197 $ 4,430 ========= =========
- --------------- (1) Includes assets of Hall-Buck Plan, as described below. The rate of increase in future compensation was 3.5 percent for 2001, 2000 and 1999. The expected long-term rate of return on plan assets was 9.5 percent for 2001, 2000 and 1999. The weighted-average discount rate used in determining the actuarial present value of the projected benefit obligation was 7.25 percent for 2001 and 7.75 percent for 2000 and 1999. Effective January 1, 2001, we added a cash balance plan to our retirement plan. Certain collectively bargained employees and "grandfathered" employees will continue to accrue benefits through the defined pension benefit plan described above. All other employees will accrue benefits through a personal retirement account in the new cash balance plan. All employees converting to the cash balance plan were credited with the current fair value of any benefits they have previously accrued through the defined benefit plan. We make contributions on behalf of these employees equal to 3% of eligible compensation 80 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) every pay period. In addition, we may make discretionary contributions to the plan based on our performance. Interest is credited to the personal retirement accounts at the 30-year U.S. Treasury bond rate in effect each year. Employees will be fully vested in the plan after five years, and they may take a lump sum distribution upon termination or retirement. On December 31, 2000, the Hall-Buck Marine Services Company Pension Plan ("Hall-Buck Plan") was merged into our retirement plan. The Hall-Buck Plan's projected benefit obligation of $2.0 million, unrecognized transition obligation of $1.3 million and plan assets of $1.8 million were transferred to our retirement plan, and the Hall-Buck Plan was terminated. Also on December 31, 2000, all employees who were not previously eligible to participate in our retirement plan and were not otherwise covered under a collective bargaining agreement became eligible under the new cash balance plan. Effective December 31, 2001 we merged the Pinney Dock Retirement Plan, the Boswell Oil Company Pension Plan, and the River Transportation Retirement Plan into our retirement plan. As of January 1, 2002, all assets and liabilities of these plans were transferred to our retirement plan. In 2000, we merged the Kinder Morgan Bulk Terminals Retirement Savings Plan and the Kinder Morgan Retirement Savings Plan with the Kinder Morgan Profit Sharing and Savings Plan, a defined contribution plan. The merged plan was renamed the Kinder Morgan, Inc. Savings Plan. On July 2, 2000, we began making regular contributions to the Plan. Contributions are made each pay period in an amount equal to 4% of compensation on behalf of each eligible employee. All contributions are in the form of Company stock, which is immediately convertible into other available investment vehicles at the employee's discretion. On July 25, 2000, our Board of Directors authorized an additional 6 million shares to be issued through the Plan, for a total of 6.7 million shares available. In addition to the above contributions, we may make annual discretionary contributions based on our performance. These contributions are made in the year following the year for which the contribution amount is calculated. The total amount contributed for 2001 and 2000 was $9.5 million and $3.7 million, respectively. No contribution was made to the profit sharing plan for 1999. In January 1998, we acquired the MidCon Retirement Plan as part of our acquisition of MidCon Corp. The MidCon plan was a defined contribution plan. Contributions to the plan were based on age and earnings. Effective January 1, 1999, the MidCon plan was merged into the Profit Sharing Plan and all eligible MidCon employees joined our defined benefit pension plans. In 1999, we contributed $0.7 million to the MidCon plan. (B) OTHER POSTRETIREMENT EMPLOYEE BENEFITS We have a defined benefit postretirement plan providing medical and life insurance benefits upon retirement for eligible employees and their eligible dependents, including former MidCon employees who met the eligibility requirements on the date of acquisition of MidCon Corp. The MidCon postretirement medical and life insurance plans were "grandfathered" as of the acquisition date and no new employees have or will be added to the MidCon plans subsequent to the acquisition date. We fund the future expected postretirement benefit cost under the plan by making payments to Voluntary Employee Benefit Association trusts. Plan assets consist primarily of pooled fixed income funds. Net periodic postretirement benefit cost includes the following components:
YEAR ENDED DECEMBER 31, --------------------------- 2001 2000 1999 ------- ------- ------- (IN THOUSANDS) Service Cost............................................ $ 340 $ 413 $ 450 Interest Cost........................................... 7,266 7,159 6,655 Expected Return on Assets............................... (5,431) (4,790) (3,720) Net Amortization and Deferral........................... 1,501 992 908 ------- ------- ------- Net Periodic Postretirement Benefit Cost................ $ 3,676 $ 3,774 $ 4,293 ======= ======= =======
81 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The following table sets forth the reconciliation of the beginning and ending balances of the accumulated postretirement benefit obligation:
2001 2000 --------- -------- (IN THOUSANDS) Benefit Obligation at Beginning of Year..................... $ (95,178) $(93,080) Service Cost................................................ (340) (413) Interest Cost............................................... (7,266) (7,159) Actuarial Gain (Loss)....................................... (3,209) (8,191) Benefits Paid............................................... 10,504 15,918 Retiree Contributions....................................... (2,529) (2,253) Plan Amendments............................................. (3,045) -- --------- -------- Benefit Obligation at End of Year........................... $(101,063) $(95,178) ========= ========
The following table sets forth the reconciliation of the beginning and ending balances of the fair value of plan assets, the plan's funded status and the amounts included under the caption "Other" in the category "Other Liabilities and Deferred Credits" in our Consolidated Balance Sheets:
DECEMBER 31, -------------------- 2001 2000 --------- -------- (IN THOUSANDS) Fair Value of Plan Assets at Beginning of Year.............. $ 51,156 $ 52,572 Actual Return on Plan Assets................................ 3,496 (2,175) Contributions by Employer................................... 31,683 1,500 Retiree Contributions....................................... 1,852 1,726 Benefits Paid............................................... (8,089) (2,467) --------- -------- Fair Value of Plan Assets at End of Year.................... 80,098 51,156 Benefit Obligation at End of Year........................... (101,063) (95,178) --------- -------- Excess of Projected Benefit Obligation Over Plan Assets..... (20,965) (44,022) Unrecognized Net (Gain) Loss................................ 17,591 12,779 Unrecognized Net Obligations at Transition.................. 10,220 11,149 Unrecognized Prior Service Cost............................. 2,807 -- --------- -------- Accrued Expense............................................. $ 9,653 $(20,094) ========= ========
The weighted-average discount rate used in determining the actuarial present value of the accumulated postretirement benefit obligation was 7.25 percent for 2001 and 7.75 percent for 2000 and 1999. The expected long-term rate of return on plan assets was 9.5 percent for 2001, 2000 and 1999. The assumed health care cost trend rate for 2001 was 3 percent (7 percent for certain collectively bargained employees). The assumed health care cost trend rate for 2000 and 1999 was 7 percent (3 percent for the MidCon plans). A one-percentage-point increase (decrease) in the assumed health care cost trend rate for each future year would have increased (decreased) the aggregate of the service and interest cost components of the 2001 net periodic postretirement benefit cost by approximately $8,089 ($7,424) and would have increased (decreased) the accumulated postretirement benefit obligation as of December 31, 2001 by approximately $111,943 ($102,729). 17. COMMON STOCK OPTION AND PURCHASE PLANS We have the following stock option plans: The 1982 Incentive Stock Option Plan, the 1982 Stock Option Plan for Non-Employee Directors, the 1986 Incentive Stock Option Plan, the 1988 Incentive Stock 82 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Option Plan, the 1992 Non-Qualified Stock Option Plan for Non-Employee Directors, the 1994 Kinder Morgan, Inc. Long-term Incentive Plan (which also provides for the issuance of restricted stock), the American Oil and Gas Corporation Stock Incentive Plan ("AOG Plan") and the Kinder Morgan, Inc. Amended and Restated 1999 Stock Option Plan. We also have an employee stock purchase plan. On October 8, 1999, our Board of Directors approved the creation of our 1999 stock option plan, a broadly based non-qualified stock option plan. Under the plan, options may be granted to individuals who are regular full-time employees, including officers and directors who are employees. Options under the plan vest in 25 percent increments on the anniversary of the grant over a four-year period from the date of grant. All options granted under the plan have a 10-year life, and must be granted at not less than the fair market value of Kinder Morgan, Inc. common stock at the close of trading on the date of grant. On January 17, 2001, our Board of Directors approved an additional 5 million shares for future grants to participants in the 1999 Stock Option Plan, which brings the aggregate number of shares subject to the plan to 10.5 million. The Board also recommended, and our shareholders approved at our May 8, 2001 annual meeting, an additional 0.5 million shares for future grants to participants in the 1992 Directors' Plan, which brings the aggregate number of shares subject to that plan to 1.03 million. Under all plans, except the Long-term Incentive Plan and the AOG Plan, options are granted at not less than 100 percent of the market value of the stock at the date of grant. Under the Long-term Incentive Plan options may be granted at less than 100 percent of the market value of the stock at the date of grant. Compensation expense was recorded totaling $0.6 million, $0, and $8.6 million for 2001, 2000, and 1999, respectively, relating to restricted stock grants awarded under the plans.
OPTION SHARES GRANTED THROUGH SHARES SUBJECT DECEMBER 31, VESTING EXPIRATION PLAN NAME TO THE PLAN 2001 PERIOD PERIOD - --------- -------------- --------------- ------------ ------------ 1982 Plan............................ 1,332,788 1,332,788 Immediate 10 Years 1982 Directors' Plan................. 186,590 186,590 3 Years 10 Years 1986 Plan............................ 618,750 618,750 Immediate 10 Years 1988 Plan............................ 618,750 618,750 Immediate 10 Years 1992 Directors' Plan................. 1,025,000 457,875 0 - 6 Months 10 Years Long-term Incentive Plan............. 5,700,000 2,775,763 0 - 5 Years 5 - 10 Years AOG Plan............................. 775,500 775,500 3 Years 10 Years 1999 Plan............................ 10,500,000 6,776,613 4 Years 10 Years
A summary of the status of our stock option plans at December 31, 2001, 2000 and 1999, and changes during the years then ended is presented in the table and narrative below:
2001 2000 1999 -------------------- --------------------- -------------------- WTD. AVG WTD. AVG WTD. AVG EXERCISE EXERCISE EXERCISE SHARES PRICE SHARES PRICE SHARES PRICE --------- -------- ---------- -------- --------- -------- Outstanding at Beginning of Year........................ 6,093,819 $26.05 7,542,898 $24.92 4,218,191 $24.38 Granted....................... 2,140,200 $51.17 1,364,500 $30.42 4,837,656 $23.81 Exercised..................... (899,664) $25.36 (537,400) $19.26 (602,928) $ 8.00 Forfeited..................... (358,638) $35.14 (2,276,179) $25.69 (910,021) $27.79 --------- ---------- --------- Outstanding at End of Year.... 6,975,717 $33.12 6,093,819 $26.05 7,542,898 $24.92 ========= ====== ========== ====== ========= ====== Exercisable at End of Year.... 2,922,471 $29.93 2,056,771 $27.03 1,918,868 $26.54 ========= ====== ========== ====== ========= ====== Weighted-Average Fair Value of Options Granted............. $21.31 $10.51 $ 5.83 ====== ====== ======
83 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The weighted-average fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following assumptions:
YEAR ENDED DECEMBER 31, ------------------------------------ 2001 2000 1999 ---------- --------- --------- Risk-free Interest Rate (%)...................... 4.30 4.97 5.50 Expected Weighted-average Life................... 6.5 years 4.5 years 4.0 years Volatility....................................... 0.34(1) 0.34 0.31 Expected Dividend Yield (%)...................... 0.36 0.38 3.20
- --------------- (1) The volatility assumption for the options issued under the 1992 Directors' Plan was 0.44. We account for these plans under Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees. Had compensation cost for these plans been determined consistent with SFAS No. 123, Accounting for Stock-Based Compensation ("SFAS 123"), net income and diluted earnings per share would have been reduced to the pro forma amounts shown in the table below. Because the SFAS 123 method of accounting has not been applied to options granted prior to January 1, 1995, the resulting pro forma compensation cost may not be representative of that to be expected in future years. Additionally, the pro forma amounts include $1.0 million, $0.8 million and $1.0 million related to the purchase discount offered under the ESP Plan for 2001, 2000 and 1999, respectively.
YEAR ENDED DECEMBER 31, ---------------------------------------- 2001 2000 1999 ----------- ----------- ------------ (IN THOUSANDS EXCEPT PER SHARE AMOUNTS) NET INCOME (LOSS): As Reported....................................... $225,070 $152,415 $(259,892) ======== ======== ========= Pro Forma......................................... $209,799 $144,960 $(264,744) ======== ======== ========= EARNINGS (LOSS) PER DILUTED SHARE: As Reported....................................... $ 1.86 $ 1.33 $ (3.24) ======== ======== ========= Pro Forma......................................... $ 1.73 $ 1.27 $ (3.30) ======== ======== =========
The following table sets forth our December 31, 2001, common stock options outstanding, weighted-average exercise prices, weighted-average remaining contractual lives, common stock options exercisable and the exercisable weighted-average exercise price:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE - ------------------------------------------------------------------------ ----------------------- WTD. AVG. WTD. AVG. WTD. AVG. NUMBER EXERCISE REMAINING NUMBER EXERCISE PRICE RANGE OUTSTANDING PRICE CONTRACTUAL LIFE EXERCISABLE PRICE - ----------- ----------- --------- ---------------- ----------- --------- $00.00 - $23.72............. 125,752 $20.91 5.08 years 123,778 $20.87 $23.81 - $23.81............. 3,232,886 $23.81 7.77 years 1,457,226 $23.81 $24.04 - $38.88............. 1,474,114 $29.70 7.69 years 795,903 $30.79 $34.67 - $52.10............. 1,534,015 $49.04 8.93 years 545,564 $47.08 $53.20 - $53.60............. 608,950 $53.22 9.26 years -- $ -- --------- --------- 6,975,717 $33.12 8.09 years 2,922,471 $29.93 ========= =========
Under the employee stock purchase plan, we may sell up to 2,400,000 shares of common stock to eligible employees. Employees purchase shares through voluntary payroll deductions. Prior to the 2000 plan year, shares were purchased annually at a 15 percent discount from the market value of the common stock, as defined in the plan, and issued in the month following the end of the plan year. Beginning with 84 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) the 2000 plan year, shares are purchased quarterly at a 15 percent discount from the closing price of the common stock on the last trading day of each calendar quarter. Employees purchased 88,333 shares, 86,630 shares and 187,567 shares for plan years 2001, 2000 and 1999, respectively. Using the Black-Scholes model to assign value to the option inherent in the right to purchase stock under the provisions of the employee stock purchase plan, the weighted-average fair value per share of purchase rights granted in 2001, 2000 and 1999 was $10.66, $6.60 and $6.41, respectively. 18. COMMITMENTS AND CONTINGENT LIABILITIES (A) LEASES Expenses incurred under operating leases were $7.1 million in 2001, $47.1 million in 2000, and $57.8 million in 1999. Future minimum commitments under major operating leases as of December 31, 2001 are as follows:
YEAR AMOUNT - ---- -------------- (IN THOUSANDS) 2002........................................................ $ 9,697 2003........................................................ 9,108 2004........................................................ 9,396 2005........................................................ 9,529 2006........................................................ 8,571 Thereafter.................................................. 15,754 ------- Total....................................................... $62,055 =======
As a result of our December 1999 sale of assets to ONEOK, ONEOK assumed our obligation for the lease of the Bushton gas processing facility. We remain secondarily liable for the lease, which had a remaining minimum obligation of approximately $247 million at December 31, 2001, with payments that average approximately $23 million per year through 2012. (B) CAPITAL EXPENDITURES BUDGET Approximately $16.9 million of our consolidated capital expenditure budget for 2002 had been committed for the purchase of plant and equipment at December 31, 2001. (C) COMMITMENT TO PURCHASE ASSETS We were committed, during a specified period, to purchase, at the option of the other party, an incremental 50% interest in a joint venture pipeline, although the ability of the other party to cause the purchase is currently stayed: see Notes 6 and 10. (D) COMMITMENTS FOR INCREMENTAL INVESTMENT We are obligated to invest approximately an additional $118 million in power generation facilities in the form of preferred equity and could be obligated (i) based on operational performance of the equipment at one facility to invest up to an additional $3 to 8 million per year for the next 16 years and (ii) based on cash flows generated by the facility, to invest up to an additional $25 million beginning in year 17, in each case in the form of an incremental preferred interest. 85 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (E) CONTINGENT OBLIGATION FOR DEBT In the event that long-term bond financing in the amount of approximately $250 million for a power facility currently financed by bank debt is not obtained prior to March 29, 2002, we are obligated to repurchase the debt from the banks. 19. FAIR VALUE The following fair values of Long-term Debt and Capital Securities were estimated based on an evaluation made by an independent securities analyst. Fair values of "Energy Financial Instruments, Net" reflect the estimated amounts that we would receive or pay to terminate the contracts at the reporting date, thereby taking into account the current unrealized gains or losses on open contracts. Market quotes are available for substantially all instruments we use.
DECEMBER 31, ----------------------------------------------- 2001 2000 --------------------- --------------------- CARRYING FAIR CARRYING VALUE VALUE VALUE FAIR VALUE -------- -------- -------- ---------- (IN MILLIONS) FINANCIAL LIABILITIES: Long-term Debt................................ $2,614.5(1) $2,624.5(1) $3,291.6 $3,251.1 Capital Securities............................ $ 275.0 $ 279.7 $ 275.0 $ 278.7 Energy Financial Instruments, Net............. $ 16.2 $ 16.2 $ 14.4 $ 14.4 Interest Rate Swaps........................... $ 4.8 $ 4.8 $ -- $ --
- --------------- (1) Includes an adjustment offsetting the value of the interest rate swaps. See Note 15. 20. SUMMARIZED FINANCIAL INFORMATION FOR KINDER MORGAN ENERGY PARTNERS, L.P. Following is summarized financial information for Kinder Morgan Energy Partners, a publicly traded limited partnership in which Kinder Morgan, Inc. owns, through a wholly owned subsidiary, the general partner interest. In addition, Kinder Morgan, Inc. owns, directly and through consolidated subsidiaries, a limited partner interest in the form of Kinder Morgan Energy Partners common units, i-units and Class B units. This investment, which is accounted for under the equity method of accounting, is described in more detail in Note 3. Additional information on Kinder Morgan Energy Partners' results of operations and financial position are contained in its 2001 Form 10-K.
SUMMARIZED INCOME STATEMENT INFORMATION YEAR ENDED DECEMBER 31, -------------------------------- 2001 2000 1999 ---------- -------- -------- (IN THOUSANDS) Operating Revenues.................................. $2,946,676 $816,442 $428,749 Operating Expenses.................................. 2,382,848 500,881 241,342 ---------- -------- -------- Operating Income.................................... $ 563,828 $315,561 $187,407 ========== ======== ======== Net Income.......................................... $ 442,343 $278,348 $182,302 ========== ======== ========
86 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
SUMMARIZED BALANCE SHEET INFORMATION AS OF DECEMBER 31, ------------------------- 2001 2000 ----------- ----------- (IN THOUSANDS) Current Assets.............................................. $ 568,043 $ 511,261 ========== ========== Noncurrent Assets........................................... $6,164,623 $4,113,949 ========== ========== Current Liabilities......................................... $ 962,704 $1,098,956 ========== ========== Noncurrent Liabilities...................................... $2,545,692 $1,351,018 ========== ========== Minority Interest........................................... $ 65,236 $ 58,169 ========== ==========
21. BUSINESS SEGMENT INFORMATION In accordance with the manner in which we manage our businesses, including the allocation of capital and evaluation of business segment performance, we report our operations in the following segments: (1) Natural Gas Pipeline Company of America and certain affiliates, referred to as Natural Gas Pipeline Company of America, a major interstate natural gas pipeline and storage system; (2) Kinder Morgan Retail, the regulated sale and transportation of natural gas to residential, commercial and industrial customers and the non-regulated sales of natural gas to certain utility customers under the Choice Gas Program and (3) Power and Other, the construction and operation of natural gas-fired electric generation facilities, together with various other activities not constituting separately managed or reportable business segments. In previous periods, we owned and operated other lines of business that we discontinued during 1999. In addition, our direct investment in the natural gas transmission and storage business has significantly decreased as a result of (i) the December 2000 transfer of Kinder Morgan Texas Pipeline, L.P. to Kinder Morgan Energy Partners and (ii) the December 31, 1999 transfer of Kinder Morgan Interstate Gas Transmission LLC to Kinder Morgan Energy Partners. The results of operations of these two businesses are included in our financial statements until their disposition, which is discussed in Note 6. The accounting policies we apply in the generation of business segment information are generally the same as those described in Note 1 to the accompanying Consolidated Financial Statements, except that certain items below the "Operating Income" line are either not allocated to business segments or are not considered by management in its evaluation of business unit performance. An exception to this is that Kinder Morgan Power, which routinely conducts its business activities in the form of joint operations with other parties that are accounted for under the equity method of accounting, includes its equity in earnings of these investees in its operating results. These equity method earnings are included in "Other Income and (Expenses)" in our Consolidated Statements of Operations. In addition, (i) certain items included in operating income (such as merger-related and severance costs and general and administrative expenses) are not allocated to individual business segments and (ii) gains and losses from incidental sales of assets are included in segment earnings. With adjustment for these items, we currently evaluate business segment performance primarily based on operating income in relation to the level of capital employed. We account for intersegment sales at market prices, while we account for asset transfers at either market value or, in some instances, book value. As necessary for comparative purposes, we have reclassified prior period results and balances to conform to the current presentation. Natural Gas Pipeline Company of America's principal delivery market area encompasses the states of Illinois, Indiana, Iowa and portions of Wisconsin, Nebraska, Kansas, Missouri and Arkansas. Natural Gas Pipeline Company of America is the largest transporter of natural gas to the Chicago, Illinois area, its largest market. During 2001, approximately 45% of Natural Gas Pipeline Company of America's transportation represented deliveries to this market. Natural Gas Pipeline Company of America's storage capacity is largely located near its transportation delivery markets, effectively serving the same customer 87 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) base. Natural Gas Pipeline Company of America has a number of individually significant customers, including local gas distribution companies in the greater Chicago area and major natural gas marketers and, during 2001, approximately 50% of its operating revenues were attributable to its six largest customers. Kinder Morgan Retail's markets are represented by residential, commercial and industrial customers located in Colorado, Nebraska and Wyoming. These markets represent varied types of customers in many industries, but a significant amount of Kinder Morgan Retail's load is represented by the use of natural gas for space heating, grain drying and irrigation. The latter two groups of customers are concentrated in the agricultural industry, and all markets are affected by the weather. Power's current principal market is represented by the local electric utilities in Colorado, which purchase the power output from its generation facilities. Its market will expand geographically as a result of power generation facilities planned or under construction and it is expected that future customers may include wholesale power marketers. During 2001, we did not have revenues from any single customer that exceeded 10 percent of our consolidated operating revenues. In 2000, we had revenues from a single customer of $740.5 million, an amount in excess of 10% of consolidated operating revenues for that year. Both Natural Gas Pipeline Company of America and Kinder Morgan Texas Pipeline made sales to this customer. Sales to this customer did not exceed 10% of consolidated operating revenues in 2001 because we transferred Kinder Morgan Texas Pipeline to Kinder Morgan Energy Partners effective December 31, 2000. BUSINESS SEGMENT INFORMATION
DECEMBER 31, YEAR ENDED DECEMBER 31, 2001 2001 ------------------------------------------------------------------------ ------------ INCOME FROM REVENUES FROM DEPRECIATION CONTINUING EXTERNAL INTERSEGMENT AND CAPITAL SEGMENT OPERATIONS CUSTOMERS REVENUES AMORTIZATION EXPENDITURES ASSETS ----------- ------------- ------------ ------------ ------------ ------------ (IN THOUSANDS) Natural Gas Pipeline Company of America... $346,569 $ 646,804 $ -- $ 85,843 $ 88,429 $5,599,766 Kinder Morgan Retail... 56,398 285,098 44 12,328 10,225 356,378 Power and Other........ 63,348 123,016 2,029 10,119 25,517 3,576,941(1) -------- ---------- ------ -------- -------- ---------- Consolidated......... 466,315 $1,054,918 $2,073 $108,290 $124,171 $9,533,085 ========== ====== ======== ======== ========== General and Administrative Expenses............. (70,386) Other Income and (Expenses)........... 11,307 -------- Income from Continuing Operations Before Income Taxes......... $407,236 ========
88 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
DECEMBER 31, YEAR ENDED DECEMBER 31, 2000 2000 ------------------------------------------------------------------------ ------------ INCOME FROM REVENUES FROM DEPRECIATION CONTINUING EXTERNAL INTERSEGMENT AND CAPITAL SEGMENT OPERATIONS CUSTOMERS REVENUES AMORTIZATION EXPENDITURES ASSETS ----------- ------------- ------------ ------------ ------------ ------------ (IN THOUSANDS) Natural Gas Pipeline Company of America... $344,405 $ 622,020 $(18) $ 84,975 $38,722 $5,478,183 Kinder Morgan Retail... 49,755 229,510 (1) 11,776 13,513 350,042 Kinder Morgan Texas Pipeline(2).......... 29,318 1,747,499 -- 2,211 16,734 -- Power and Other........ 33,460 80,693 4 9,203 16,685 2,558,764(1) Discontinued Operations........... -- -- -- -- 3,185 -- -------- ---------- ---- -------- ------- ---------- Consolidated......... 456,938 $2,679,722 $(15) $108,165 $88,839 $8,386,989 ========== ==== ======== ======= ========== General and Administrative Expenses............. (58,087) Other Income and (Expenses)........... (91,685) -------- Income from Continuing Operations Before Income Taxes......... $307,166 ========
DECEMBER 31, YEAR ENDED DECEMBER 31, 1999 1999 ------------------------------------------------------------------------ ------------ INCOME FROM REVENUES FROM DEPRECIATION CONTINUING EXTERNAL INTERSEGMENT AND CAPITAL SEGMENT OPERATIONS CUSTOMERS REVENUES AMORTIZATION EXPENDITURES ASSETS ----------- ------------- ------------ ------------ ------------ ------------ (IN THOUSANDS) Natural Gas Pipeline Company of America... $306,695 $ 625,705 $ 1,183 $109,346 $ 41,716 $5,469,050 Kinder Morgan Interstate(3)........ 53,630 96,531 16,676 16,985 20,743 -- Kinder Morgan Retail... 20,055 182,861 51 11,382 11,749 332,618 Kinder Morgan Texas Pipeline(2).......... 16,554 872,161 -- 2,466 4,567 255,200 Power and Other........ 34,379 59,110 195 7,754 14,066 2,618,739(1) Discontinued Operations........... -- -- -- -- 28,363 718,227 -------- ---------- ------- -------- -------- ---------- Consolidated......... 431,313 $1,836,368 $18,105 $147,933 $121,204 $9,393,834 ========== ======= ======== ======== ========== General and Administrative Expenses............. (85,591) Merger-related and Severance Costs...... (37,443) Other Income and (Expenses)........... (93,728) -------- Income from Continuing Operations Before Income Taxes......... $214,551 ========
- --------------- (1) Principally the investment in Kinder Morgan Energy Partners, investments in electric power generating facilities and corporate cash and receivables. (2) Kinder Morgan Texas Pipeline was transferred to Kinder Morgan Energy Partners effective December 31, 2000. 89 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (3) Kinder Morgan Interstate was transferred to Kinder Morgan Energy Partners effective December 31, 1999. GEOGRAPHIC INFORMATION All but an insignificant amount of our assets and operations are located in the continental United States. 22. RECENT ACCOUNTING PRONOUNCEMENTS Statement of Financial Accounting Standards No. 141 supercedes Accounting Principles Board Opinion No. 16 and requires that all transactions fitting the description of a business combination be accounted for using the purchase method and prohibits the use of the pooling of interests for all business combinations initiated after June 30, 2001. The Statement also modifies the accounting for the excess of fair value of net assets acquired as well as intangible assets acquired in a business combination. The provisions of this statement apply to all business combinations initiated after June 30, 2001, and all business combinations accounted for by the purchase method that are completed after July 1, 2001. This Statement requires disclosure of the primary reasons for a business combination and the allocation of the purchase price paid to the assets acquired and liabilities assumed by major balance sheet caption. In June 2001, the FASB issued SFAS No. 142, Goodwill and Other Intangible Assets. This Statement addresses financial accounting and reporting for (i) intangible assets acquired individually or with a group of other assets (but not those acquired in a business combination) at acquisition and (ii) goodwill and other intangible assets subsequent to their acquisition. This Statement supersedes APB Opinion No. 17, Intangible Assets. Under the provisions of this Statement, if an intangible asset is determined to have an indefinite useful life, it shall not be amortized until its useful life is determined to be no longer indefinite. An intangible asset that is not subject to amortization shall be tested for impairment annually, or more frequently if events or changes in circumstances indicate that the asset might be impaired. Goodwill will not be amortized. Goodwill will be tested for impairment on an annual basis and between annual tests in certain circumstances at a level of reporting referred to as a reporting unit. This Statement is required to be applied starting with fiscal years beginning after December 15, 2001. Goodwill and intangible assets acquired after June 30, 2001 will be subject immediately to the nonamortization and amortization provisions of this Statement. At December 31, 2001, we had approximately $25 million of goodwill recorded in conjunction with the 1998 acquisition of the Thermo Companies. In accordance with the provisions of SFAS No. 142, we will complete our analysis of that goodwill balance for impairment no later than June 30, 2002 and will record any indicated impairment during 2002. In addition, we have a significant amount of "excess investment" or "equity method goodwill," principally as a result of our investment in Kinder Morgan Energy Partners. As provided in SFAS No. 142, this type of investment will continue to be tested for impairment in accordance with the provisions of Accounting Principles Board Opinion No. 18, The Equity Method of Accounting for Investments in Common Stock. We estimate that the reduction in amortization expense resulting from the cessation of amortization of both the goodwill and the equity method goodwill will result in a $0.13 increase in earnings per diluted common share in 2002. In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations. This Statement addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. This Statement requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. This Statement contains disclosure requirements that provide descriptions of asset retirement obligations and reconciliations of changes in the components of those obligations. This Statement is effective for financial statements issued for fiscal years beginning after 90 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) June 15, 2002. Earlier applications are encouraged. We have not yet quantified the impacts of adopting this Statement on our financial position or results of operations. In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. This Statement addresses financial accounting and reporting for the impairment or disposal of long-lived assets. This Statement retains the requirements to (a) recognize an impairment loss only if the carrying amount of a long-lived asset is not recoverable from its undiscounted cash flows and (b) measure an impairment loss as the difference between the carrying amount and fair value of the asset. This Statement removes goodwill from its scope, eliminating the requirement to allocate goodwill to long-lived assets to be tested for impairment. This Statement requires that a long-lived asset to be abandoned, exchanged for a similar productive asset, or distributed to owners in a spin-off be considered held and used until it is disposed of. This Statement requires the accounting model for long-lived assets to be disposed of by sale be used for all long-lived assets, whether previously held and used or newly acquired. Discontinued operations are no longer measured on a net realizable value basis, and future operating losses are no longer recognized before they occur. This Statement broadens the presentation of discontinued operations in the income statement to include a component of an entity (rather than a segment of a business). A component of an entity comprises operations and cash flows that can be clearly distinguished, operationally and for financial reporting purposes, from the rest of the entity. The provisions of this Statement are effective for financial statements issued for fiscal years beginning after December 15, 2001, and interim periods within those fiscal years, with early application encouraged. The provisions of this Statement generally are to be applied prospectively. 91 SELECTED QUARTERLY FINANCIAL DATA KINDER MORGAN, INC. AND SUBSIDIARIES QUARTERLY OPERATING RESULTS FOR 2001 AND 2000
2001 - THREE MONTHS ENDED ------------------------- MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 -------- --------- ------------- ----------- (IN THOUSANDS EXCEPT PER SHARE AMOUNTS) (UNAUDITED) Operating Revenues............................. $325,232 $218,845 $227,026 $283,815 Gas Purchases and Other Costs of Sales......... 133,328 59,301 53,492 93,232 -------- -------- -------- -------- Gross Margin................................... 191,904 159,544 173,534 190,583 Other Operating Expenses....................... 79,482 78,719 82,138 90,907 -------- -------- -------- -------- Operating Income............................... 112,422 80,825 91,396 99,676 Other Income and (Expenses).................... (17,752) 4,259 11,718 24,692 -------- -------- -------- -------- Income Before Income Taxes and Extraordinary Item......................................... 94,670 85,084 103,114 124,368 Income Taxes................................... 37,868 35,184 43,443 52,106 -------- -------- -------- -------- Income Before Extraordinary Item............... 56,802 49,900 59,671 72,262 Extraordinary Item -- Loss on Early Extinguishment of Debt, Net of Income Tax Benefits of $8,080 and $964.................. (12,119) -- (1,446) -- -------- -------- -------- -------- Net Income..................................... $ 44,683 $ 49,900 $ 58,225 $ 72,262 ======== ======== ======== ======== BASIC EARNINGS PER COMMON SHARE: Income Before Extraordinary Item............... $ 0.50 $ 0.43 $ 0.52 $ 0.62 Extraordinary Item -- Loss on Early Extinguishment of Debt....................... (0.11) -- (0.01) -- -------- -------- -------- -------- Total Basic Earnings Per Common Share.......... $ 0.39 $ 0.43 $ 0.51 $ 0.62 ======== ======== ======== ======== Number of Shares Used in Computing Basic Earnings Per Share........................... 114,844 115,258 114,980 115,892 ======== ======== ======== ======== DILUTED EARNINGS PER COMMON SHARE: Income Before Extraordinary Item............... $ 0.47 $ 0.41 $ 0.49 $ 0.60 Extraordinary Item -- Loss on Early Extinguishment of Debt....................... (0.10) -- (0.01) -- -------- -------- -------- -------- Total Diluted Earnings Per Common Share........ $ 0.37 $ 0.41 $ 0.48 $ 0.60 ======== ======== ======== ======== Number of Shares Used in Computing Diluted Earnings Per Share........................... 121,320 122,359 121,446 120,298 ======== ======== ======== ========
92 SELECTED QUARTERLY FINANCIAL DATA KINDER MORGAN, INC. AND SUBSIDIARIES QUARTERLY OPERATING RESULTS FOR 2001 AND 2000
2000 - THREE MONTHS ENDED ------------------------------------------------ MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 -------- -------- ------------ ----------- (IN THOUSANDS EXCEPT PER SHARE AMOUNTS) (UNAUDITED) Operating Revenues............................. $480,586 $552,012 $741,417 $905,707 Gas Purchases and Other Costs of Sales......... 278,016 382,531 568,430 697,091 -------- -------- -------- -------- Gross Margin................................... 202,570 169,481 172,987 208,616 Other Operating Expenses....................... 89,881 87,819 87,517 93,294 -------- -------- -------- -------- Operating Income............................... 112,689 81,662 85,470 115,322 Other Income and (Expenses).................... (35,477) (40,581) (40,624) 28,705(1) -------- -------- -------- -------- Income From Continuing Operations Before Income Taxes........................................ 77,212 41,081 44,846 144,027 Income Taxes................................... 30,887 16,968 18,138 57,024 -------- -------- -------- -------- Income From Continuing Operations.............. 46,325 24,113 26,708 87,003 Loss on Disposal of Discontinued Operations, Net of Tax................................... -- -- -- (31,734)(2) -------- -------- -------- -------- Net Income..................................... $ 46,325 $ 24,113 $ 26,708 $ 55,269 ======== ======== ======== ======== BASIC EARNINGS PER COMMON SHARE: Continuing Operations.......................... $ 0.41 $ 0.21 $ 0.23 $ 0.76 Loss on Disposal of Discontinued Operations.... -- -- -- (0.28) -------- -------- -------- -------- Total Basic Earnings Per Common Share.......... $ 0.41 $ 0.21 $ 0.23 $ 0.48 ======== ======== ======== ======== Number of Shares Used in Computing Basic Earnings Per Share........................... 113,058 114,196 114,461 114,535 ======== ======== ======== ======== DILUTED EARNINGS PER COMMON SHARE: Continuing Operations.......................... $ 0.41 $ 0.21 $ 0.23 $ 0.74 Loss on Disposal of Discontinued Operations.... -- -- -- (0.27) -------- -------- -------- -------- Total Diluted Earnings Per Common Share........ $ 0.41 $ 0.21 $ 0.23 $ 0.47 ======== ======== ======== ======== Number of Shares Used in Computing Diluted Earnings Per Share........................... 113,456 114,981 116,177 118,594 ======== ======== ======== ========
- --------------- (1) Includes a $61.6 million pre-tax gain from the sale of certain assets to Kinder Morgan Energy Partners; see Note 6 of the accompanying Notes to Consolidated Financial Statements. (2) See Note 7 of the accompanying Notes to Consolidated Financial Statements. 93 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT. Certain information required by this item is contained in our Proxy Statement related to the 2002 Annual Meeting of Stockholders, to be filed pursuant to Section 14 of the Securities Exchange Act of 1934 and is incorporated herein by reference. For information regarding our current executive officers, see Executive Officers of the Registrant under Part I. ITEM 11. EXECUTIVE COMPENSATION. Information required by this item is contained in our Proxy Statement related to the 2002 Annual Meeting of Stockholders, to be filed pursuant to Section 14 of the Securities Exchange Act of 1934 and is incorporated herein by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT. Information required by this item is contained in our Proxy Statement related to the 2002 Annual Meeting of Stockholders, to be filed pursuant to Section 14 of the Securities Exchange Act of 1934 and is incorporated herein by reference. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. Information required by this item is contained in our Proxy Statement related to the 2002 Annual Meeting of Stockholders, to be filed pursuant to Section 14 of the Securities Exchange Act of 1934 and is incorporated herein by reference. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K. (a)(1) Financial Statements Reference is made to the listings of financial statements and supplementary data under Item 8 in Part II. (2) Financial Statement Schedules 94 KINDER MORGAN, INC. AND SUBSIDIARIES SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
YEAR ENDED DECEMBER 31, 2001 ------------------------------------------------------------------------------ DEDUCTIONS BALANCE AT ADDITIONS WRITE-OFF OF DISCONTINUED BEGINNING OF CHARGED TO COST UNCOLLECTIBLE OPERATIONS BALANCE AT END PERIOD AND EXPENSES ACCOUNTS DEDUCTIONS OF PERIOD ------------ --------------- ------------- ------------ -------------- (IN MILLIONS) Allowance for Doubtful Accounts................... $2.3 $6.7 $(5.6) $-- $3.4
YEAR ENDED DECEMBER 31, 2000 ------------------------------------------------------------------------------ DEDUCTIONS BALANCE AT ADDITIONS WRITE-OFF OF DISCONTINUED BEGINNING OF CHARGED TO COST UNCOLLECTIBLE OPERATIONS BALANCE AT END PERIOD AND EXPENSES ACCOUNTS DEDUCTIONS OF PERIOD ------------ --------------- ------------- ------------ -------------- (IN MILLIONS) Allowance for Doubtful Accounts................... $1.7 $9.9 $(9.3) $-- $2.3
YEAR ENDED DECEMBER 31, 1999 ------------------------------------------------------------------------------ DEDUCTIONS BALANCE AT ADDITIONS WRITE-OFF OF DISCONTINUED BEGINNING OF CHARGED TO COST UNCOLLECTIBLE OPERATIONS BALANCE AT END PERIOD AND EXPENSES ACCOUNTS DEDUCTIONS OF PERIOD ------------ --------------- ------------- ------------ -------------- (IN MILLIONS) Allowance for Doubtful Accounts................... $10.8 $3.6 $(0.6) $(12.1) $1.7
The financial statements, including the notes thereto, of Kinder Morgan Energy Partners, an equity method investee of the Registrant, are incorporated herein by reference from 74 through 137 of Kinder Morgan Energy Partners' Annual Report on Form 10-K for the year ended December 31, 2001. 95 3. Exhibits Any reference made to K N Energy, Inc. in the exhibit listing that follows is a reference to the former name of Kinder Morgan, Inc., a Kansas corporation and the registrant, and is made because the exhibit being listed and incorporated by reference was originally filed before October 7, 1999, the date of the change in the Registrant's name.
EXHIBIT NUMBER DESCRIPTION ------- ----------- Exhibit 2(a) Agreement and Plan of Merger, dated as of July 8, 1999, by and among K N Energy, Inc., Rockies Merger Corp., and Kinder Morgan, Inc., (Annex A-1 of Registration Statement on Form S-4 (File No. 333-85747)) Exhibit 2(b) First Amendment to Agreement and Plan of Merger, dated as of August 20, 1999, by and among K N Energy, Inc., Rockies Merger Corp., and Kinder Morgan, Inc., (Annex A-2 of Registration Statement on Form S-4 (File No. 333-85747)) Exhibit 2(c) Contribution Agreement, dated as of December 30, 1999, by and among Kinder Morgan, Inc., Natural Gas Pipeline Company of America, K N Gas Gathering, Inc., Kinder Morgan G.P., Inc. and Kinder Morgan Energy Partners, L.P. (Exhibit 99.1 to Current Report on Form 8-K filed on January 14, 2000) Exhibit 3(a) Restated Articles of Incorporation of Kinder Morgan, Inc. (Exhibit 3(a) to the Annual Report on Form 10-K/A, Amendment No. 1 filed on May 22, 2000) Exhibit 3(b) Certificate of Amendment to the Restated Articles of Incorporation of Kinder Morgan, Inc. as filed on October 7, 1999, with the Secretary of State of Kansas (Exhibit 3.1 to Kinder Morgan, Inc.'s Quarterly Report on Form 10-Q for the quarter ended September 30, 1999) Exhibit 3(c) Bylaws of Kinder Morgan, Inc., as amended to October 7, 1999 (Exhibit 3.2 to Kinder Morgan, Inc.'s Quarterly Report on Form 10-Q for the quarter ended September 30, 1999) Exhibit 4(a) Indenture dated as of September 1, 1988, between K N Energy, Inc. and Continental Illinois National Bank and Trust Company of Chicago (Exhibit 4(a) to the Annual Report on Form 10-K/A, Amendment No. 1 filed on May 22, 2000) Exhibit 4(b) First supplemental indenture dated as of January 15, 1992, between K N Energy, Inc. and Continental Illinois National Bank and Trust Company of Chicago (Exhibit 4.2, File No. 33-45091) Exhibit 4(c) Second supplemental indenture dated as of December 15, 1992, between K N Energy, Inc. and Continental Bank, National Association (Exhibit 4(c) to the Annual Report on Form 10-K/A, Amendment No. 1 filed on May 22, 2000) Exhibit 4(d) Indenture dated as of November 20, 1993, between K N Energy, Inc. and Continental Bank, National Association (Exhibit 4.1, File No. 33-51115) (Note -- Copies of instruments relative to long-term debt in authorized amounts that do not exceed 10 percent of the consolidated total assets of Kinder Morgan and its subsidiaries have not been furnished. Kinder Morgan will furnish such instruments to the Commission upon request.) Exhibit 4(e) $500,000,000 364-Day Credit Agreement among Kinder Morgan, Inc., certain banks listed therein and Bank of America, N. A. (Exhibit 4(e) to the Annual Report on Form 10-K for the year ended December 31, 2000) Exhibit 4(f)* Form of Amendment No. 1 to the $500,000,000 364-Day Credit Agreement among Kinder Morgan, Inc., certain banks listed therein and Bank of America, N.A.
96
EXHIBIT NUMBER DESCRIPTION ------- ----------- Exhibit 4(g) $400,000,000 Amended and Restated Five-Year Credit Agreement dated January 30, 1998 among K N Energy, Inc., certain banks listed therein and Morgan Guaranty Trust Company of New York, as Administrative Agent (Exhibit 4(f) to the Annual Report on Form 10-K for the year ended December 31, 1997) Exhibit 4(h) Amendment No. 1 to the $400,000,000 Five-Year Amended and Restated Credit Agreement dated as of November 6, 1998 among K N Energy, Inc., certain banks listed therein and Morgan Guaranty Trust Company of New York, as Administrative Agent (Exhibit 4(j) to the Annual Report on Form 10-K for the year ended December 31, 1998) Exhibit 4(i) Amendment No. 2 to the $400,000,000 Five-Year Amended and Restated Credit Agreement dated as of January 8, 1999 among K N Energy, Inc., certain banks listed therein and Morgan Guaranty Trust Company of New York, as Administrative Agent (Exhibit 4(l) to the Annual Report on Form 10-K for the year ended December 31, 1998) Exhibit 4(j) Rights Agreement between K N Energy, Inc. and the Bank of New York, as Rights Agent, dated as of August 21, 1995 (Exhibit 1 on Form 8-A dated August 21, 1995) Exhibit 4(k) Amendment No. 1 to Rights Agreement between K N Energy, Inc. and the Bank of New York, as Rights Agent, dated as of September 8, 1998 (Exhibit 10(cc) to the Annual Report on Form 10-K for the year ended December 31, 1998) Exhibit 4(l) Amendment No. 2 to Rights Agreement of Kinder Morgan, Inc. dated July 8, 1999, between Kinder Morgan, Inc. and First Chicago Trust Company of New York, as successor-in-interest to the Bank of New York, as Rights Agent (Exhibit 4.1 to Kinder Morgan, Inc.'s Quarterly Report on Form 10-Q for the quarter ended September 30, 1999) Exhibit 4(m)* Form of Amendment No. 3 to Rights Agreement of Kinder Morgan, Inc. dated September 1, 2001, between Kinder Morgan, Inc. and First Chicago Trust Company of New York, as Rights Agent Exhibit 10(a) 1994 Amended and Restated Kinder Morgan, Inc. Long-term Incentive Plan (Appendix A to the Kinder Morgan, Inc. 2000 Proxy Statement on Schedule 14A) Exhibit 10(b) Kinder Morgan, Inc. Amended and Restated 1999 Stock Option Plan (Appendix B to the Kinder Morgan, Inc. 2000 Proxy Statement on Schedule 14A) Exhibit 10(c) Kinder Morgan, Inc. Amended and Restated 1992 Stock Option Plan for Nonemployee Directors (Appendix C to the Kinder Morgan, Inc. 2000 Proxy Statement on Schedule 14A) Exhibit 10(d) 2000 Annual Incentive Plan of Kinder Morgan, Inc. (Appendix D to the Kinder Morgan, Inc. 2000 Proxy Statement on Schedule 14A) Exhibit 10(e) Kinder Morgan, Inc. Employees Stock Purchase Plan (Appendix E to the Kinder Morgan, Inc. 2000 Proxy Statement on Schedule 14A) Exhibit 10(f) Form of Nonqualified Stock Option Agreement (Exhibit 10(f) to the Annual Report on Form 10-K for the year ended December 31, 2000) Exhibit 10(g) Form of Restricted Stock Agreement (Exhibit 10(g) to the Annual Report on Form 10-K for the year ended December 31, 2000) Exhibit 10(h) Directors and Executives Deferred Compensation Plan effective January 1, 1998 for executive officers and directors of K N Energy, Inc. (Exhibit 10(aa) to the Annual Report on Form 10-K for the year ended December 31, 1998) Exhibit 10(i) Employment Agreement dated October 7, 1999, between the Company and Richard D. Kinder (Exhibit 99.D of the Schedule 13D filed by Mr. Kinder on October 8, 1999) Exhibit 10(j) Employment Agreement dated April 20, 2000, by and among Kinder Morgan, Inc., Kinder Morgan G.P., Inc. and David G. Dehaemers, Jr. (filed as Exhibit 10(a) to Kinder Morgan, Inc.'s Form 10-Q for the quarter ended March 31, 2000)
97
EXHIBIT NUMBER DESCRIPTION ------- ----------- Exhibit 10(k) Employment Agreement dated April 20, 2000, by and among Kinder Morgan, Inc., Kinder Morgan G.P., Inc. and Michael C. Morgan (filed as Exhibit 10(b) to Kinder Morgan, Inc.'s Form 10-Q for the quarter ended March 31, 2000) Exhibit 10(l)* Retention Agreement dated January 17, 2002, by and between Kinder Morgan, Inc. and C. Park Shaper Exhibit 21.1* Subsidiaries of the Registrant Exhibit 23.1* Consent of Independent Accountants Exhibit 99.1* The financial statements of Kinder Morgan Energy Partners, L.P. and subsidiaries included on pages 74 through 137 on the Annual Report on Form 10-K of Kinder Morgan Energy Partners, L.P. for the year ended December 31, 2001
- --------------- * Filed herewith. (b) Reports on Form 8-K (1) Current Report on Form 8-K dated November 9, 2001 was filed on November 9, 2001 pursuant to Item 9. of that form. Pursuant to Item 9. of that form, Kinder Morgan, Inc. announced its intention to make several presentations beginning on November 9, 2001 to institutional investors and others to address various strategic and financial issues relating to the business plans and objectives of Kinder Morgan, Inc., Kinder Morgan Energy Partners, L.P. and Kinder Morgan Management, LLC, and the availability of materials to be presented at the meetings on Kinder Morgan, Inc.'s website. (2) Current Report on Form 8-K dated January 16, 2002 was filed on January 16, 2002 pursuant to Item 9. of that form. Pursuant to Item 9. of that form, Kinder Morgan, Inc. announced its intention to make presentations on January 17, 2002 to analysts and others to address various strategic and financial issues relating to the business plans and objectives of Kinder Morgan, Inc., Kinder Morgan Energy Partners, L.P. and Kinder Morgan Management, LLC, and the availability of materials to be presented at the meetings on Kinder Morgan, Inc.'s website. 98 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. KINDER MORGAN, INC. (Registrant) By /s/ C. PARK SHAPER ------------------------------------ C. Park Shaper Vice President and Chief Financial Officer Date: February 18, 2002 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated. /s/ EDWARD H. AUSTIN, JR. Director - ------------------------------------------------ Edward H. Austin, Jr. /s/ CHARLES W. BATTEY Director - ------------------------------------------------ Charles W. Battey /s/ STEWART A. BLISS Director - ------------------------------------------------ Stewart A. Bliss /s/ TED A. GARDNER Director - ------------------------------------------------ Ted A. Gardner /s/ WILLIAM J. HYBL Director - ------------------------------------------------ William J. Hybl /s/ RICHARD D. KINDER Chairman, Chief Executive Officer and Director - ------------------------------------------------ (Principal Executive Officer) Richard D. Kinder /s/ WILLIAM V. MORGAN Vice Chairman and Director - ------------------------------------------------ William V. Morgan /s/ EDWARD RANDALL, III Director - ------------------------------------------------ Edward Randall, III Director - ------------------------------------------------ Fayez Sarofim
99 /s/ C. PARK SHAPER Vice President and Chief Financial Officer - ------------------------------------------------ (Principal Financial and Accounting Officer) C. Park Shaper /s/ H. A. TRUE, III Director - ------------------------------------------------ H. A. True, III
100 INDEX TO EXHIBITS
EXHIBIT NUMBER DESCRIPTION ------- ----------- Exhibit 2(a) Agreement and Plan of Merger, dated as of July 8, 1999, by and among K N Energy, Inc., Rockies Merger Corp., and Kinder Morgan, Inc., (Annex A-1 of Registration Statement on Form S-4 (File No. 333-85747)) Exhibit 2(b) First Amendment to Agreement and Plan of Merger, dated as of August 20, 1999, by and among K N Energy, Inc., Rockies Merger Corp., and Kinder Morgan, Inc., (Annex A-2 of Registration Statement on Form S-4 (File No. 333-85747)) Exhibit 2(c) Contribution Agreement, dated as of December 30, 1999, by and among Kinder Morgan, Inc., Natural Gas Pipeline Company of America, K N Gas Gathering, Inc., Kinder Morgan G.P., Inc. and Kinder Morgan Energy Partners, L.P. (Exhibit 99.1 to Current Report on Form 8-K filed on January 14, 2000) Exhibit 3(a) Restated Articles of Incorporation of Kinder Morgan, Inc. (Exhibit 3(a) to the Annual Report on Form 10-K/A, Amendment No. 1 filed on May 22, 2000) Exhibit 3(b) Certificate of Amendment to the Restated Articles of Incorporation of Kinder Morgan, Inc. as filed on October 7, 1999, with the Secretary of State of Kansas (Exhibit 3.1 to Kinder Morgan, Inc.'s Quarterly Report on Form 10-Q for the quarter ended September 30, 1999) Exhibit 3(c) Bylaws of Kinder Morgan, Inc., as amended to October 7, 1999 (Exhibit 3.2 to Kinder Morgan, Inc.'s Quarterly Report on Form 10-Q for the quarter ended September 30, 1999) Exhibit 4(a) Indenture dated as of September 1, 1988, between K N Energy, Inc. and Continental Illinois National Bank and Trust Company of Chicago (Exhibit 4(a) to the Annual Report on Form 10-K/A, Amendment No. 1 filed on May 22, 2000) Exhibit 4(b) First supplemental indenture dated as of January 15, 1992, between K N Energy, Inc. and Continental Illinois National Bank and Trust Company of Chicago (Exhibit 4.2, File No. 33-45091) Exhibit 4(c) Second supplemental indenture dated as of December 15, 1992, between K N Energy, Inc. and Continental Bank, National Association (Exhibit 4(c) to the Annual Report on Form 10-K/A, Amendment No. 1 filed on May 22, 2000) Exhibit 4(d) Indenture dated as of November 20, 1993, between K N Energy, Inc. and Continental Bank, National Association (Exhibit 4.1, File No. 33-51115) (Note -- Copies of instruments relative to long-term debt in authorized amounts that do not exceed 10 percent of the consolidated total assets of Kinder Morgan and its subsidiaries have not been furnished. Kinder Morgan will furnish such instruments to the Commission upon request. Exhibit 4(e) $500,000,000 364-Day Credit Agreement among Kinder Morgan, Inc., certain banks listed therein and Bank of America, N. A. (Exhibit 4(e) to the Annual Report on Form 10-K for the year ended December 31, 2000) Exhibit Form of Amendment No. 1 to the $500,000,000 364-Day Credit 4(f)* Agreement among Kinder Morgan, Inc., certain banks listed therein and Bank of America, N.A. Exhibit 4(g) $400,000,000 Amended and Restated Five-Year Credit Agreement dated January 30, 1998 among K N Energy, Inc., certain banks listed therein and Morgan Guaranty Trust Company of New York, as Administrative Agent (Exhibit 4(f) to the Annual Report on Form 10-K for the year ended December 31, 1997)
EXHIBIT NUMBER DESCRIPTION ------- ----------- Exhibit 4(h) Amendment No. 1 to the $400,000,000 Five-Year Amended and Restated Credit Agreement dated as of November 6, 1998 among K N Energy, Inc., certain banks listed therein and Morgan Guaranty Trust Company of New York, as Administrative Agent (Exhibit 4(j) to the Annual Report on Form 10-K for the year ended December 31, 1998) Exhibit 4(i) Amendment No. 2 to the $400,000,000 Five-Year Amended and Restated Credit Agreement dated as of January 8, 1999 among K N Energy, Inc., certain banks listed therein and Morgan Guaranty Trust Company of New York, as Administrative Agent (Exhibit 4(l) to the Annual Report on Form 10-K for the year ended December 31, 1998) Exhibit 4(j) Rights Agreement between K N Energy, Inc. and the Bank of New York, as Rights Agent, dated as of August 21, 1995 (Exhibit 1 on Form 8-A dated August 21, 1995) Exhibit 4(k) Amendment No. 1 to Rights Agreement between K N Energy, Inc. and the Bank of New York, as Rights Agent, dated as of September 8, 1998 (Exhibit 10(cc) to the Annual Report on Form 10-K for the year ended December 31, 1998) Exhibit 4(l) Amendment No. 2 to Rights Agreement of Kinder Morgan, Inc. dated July 8, 1999, between Kinder Morgan, Inc. and First Chicago Trust Company of New York, as successor-in-interest to the Bank of New York, as Rights Agent (Exhibit 4.1 to Kinder Morgan, Inc.'s Quarterly Report on Form 10-Q for the quarter ended September 30, 1999) Exhibit Form of Amendment No. 3 to Rights Agreement of Kinder 4(m)* Morgan, Inc. dated September 1, 2001, between Kinder Morgan, Inc. and First Chicago Trust Company of New York, as Rights Agent Exhibit 1994 Amended and Restated Kinder Morgan, Inc. Long-term 10(a) Incentive Plan (Appendix A to the Kinder Morgan, Inc. 2000 Proxy Statement on Schedule 14A) Exhibit Kinder Morgan, Inc. Amended and Restated 1999 Stock Option 10(b) Plan (Appendix B to the Kinder Morgan, Inc. 2000 Proxy Statement on Schedule 14A) Exhibit Kinder Morgan, Inc. Amended and Restated 1992 Stock Option 10(c) Plan for Nonemployee Directors (Appendix C to the Kinder Morgan, Inc. 2000 Proxy Statement on Schedule 14A) Exhibit 2000 Annual Incentive Plan of Kinder Morgan, Inc. (Appendix 10(d) D to the Kinder Morgan, Inc. 2000 Proxy Statement on Schedule 14A) Exhibit Kinder Morgan, Inc. Employees Stock Purchase Plan (Appendix 10(e) E to the Kinder Morgan, Inc. 2000 Proxy Statement on Schedule 14A) Exhibit Form of Nonqualified Stock Option Agreement (Exhibit 10(f) 10(f) to the Annual Report on Form 10-K for the year ended December 31, 2000) Exhibit Form of Restricted Stock Agreement (Exhibit 10(g) to the 10(g) Annual Report on Form 10-K for the year ended December 31, 2000) Exhibit Directors and Executives Deferred Compensation Plan 10(h) effective January 1, 1998 for executive officers and directors of K N Energy, Inc. (Exhibit 10(aa) to the Annual Report on Form 10-K for the year ended December 31, 1998) Exhibit Employment Agreement dated October 7, 1999, between the 10(i) Company and Richard D. Kinder (Exhibit 99.D of the Schedule 13D filed by Mr. Kinder on October 8, 1999) Exhibit Employment Agreement dated April 20, 2000, by and among 10(j) Kinder Morgan, Inc., Kinder Morgan G.P., Inc. and David G. Dehaemers, Jr. (filed as Exhibit 10(a) to Kinder Morgan, Inc.'s Form 10-Q for the quarter ended March 31, 2000) Exhibit Employment Agreement dated April 20, 2000, by and among 10(k) Kinder Morgan, Inc., Kinder Morgan G.P., Inc. and Michael C. Morgan (filed as Exhibit 10(b) to Kinder Morgan, Inc.'s Form 10-Q for the quarter ended March 31, 2000)
EXHIBIT NUMBER DESCRIPTION ------- ----------- Exhibit Retention Agreement dated January 17, 2002, by and between 10(l)* Kinder Morgan, Inc. and C. Park Shaper Exhibit Subsidiaries of the Registrant 21.1* Exhibit Consent of Independent Accountants 23.1* Exhibit The financial statements of Kinder Morgan Energy Partners, 99.1* L.P. and subsidiaries included on pages 74 through 137 on the Annual Report on Form 10-K of Kinder Morgan Energy Partners, L.P. for the year ended December 31, 2001
- --------------- * Filed herewith. EX-4.F 3 h94310ex4-f.txt AMEND. #1 TO $500,000,000 364-DAY CREDIT AGMT. EXHIBIT 4(f) [JP MORGAN LOGO APPEARS HERE] FIRST AMENDMENT TO 364-DAY CREDIT AGREEMENT dated as of October 23, 2001 among KINDER MORGAN, INC. The Banks Party Hereto and THE CHASE MANHATTAN BANK, as Administrative Agent FIRST UNION NATIONAL BANK, as Syndication Agent COMMERZBANK AG, NEW YORK AND GRAND CAYMAN BRANCHES, THE BANK OF NOVA SCOTIA, CREDIT LYONNAIS as Co-Documentation Agents J.P. MORGAN SECURITIES, INC., FIRST UNION SECURITIES, INC. as Joint Book Runners/Co-Lead Arrangers FIRST AMENDMENT TO 364-DAY CREDIT AGREEMENT THIS FIRST AMENDMENT TO 364-DAY CREDIT AGREEMENT ("First Amendment") is dated as of October 23, 2001 by and among KINDER MORGAN, INC., a Kansas corporation (the "Borrower"), THE CHASE MANHATTAN BANK, a New York banking corporation ("Chase"), as Administrative Agent, FIRST UNION NATIONAL BANK, a national banking association ("First Union"), as Syndication Agent and the Banks party hereto and shall amend the 364-DAY CREDIT AGREEMENT (the "Credit Agreement"), dated as of October 25, 2000 among the Borrower, Bank One, N.A., as Documentation Agent, First Union, as Syndication Agent, Bank of America, N.A., as Administrative Agent, and the Banks party thereto. WHEREAS, the Borrower desires to extend the term of the Credit Agreement; WHEREAS, Chase has succeeded Bank of America, N.A. as Administrative Agent under the Credit Agreement; WHEREAS, Bank One N.A. has ceased to be the Documentation Agent and Bank of Nova Scotia, Commerzbank AG, New York and Grand Cayman Branches, and Credit Lyonnais have replaced Bank One, N.A. as Co-Documentation Agents; WHEREAS, Bank of America, N.A. and The Sumitomo Bank, Limited have elected not to renew their Commitments and, therefore, have ceased to be Banks under the Credit Agreement; WHEREAS, by their execution of this First Amendment, certain new banks have agreed to become Banks under the Credit Agreement; WHEREAS, the Borrower desires to correct and clarify certain other matters related to the Credit Agreement; WHEREAS, the Borrower has requested that the Banks modify and amend the Credit Agreement as described more fully herein; WHEREAS, the Banks are willing to agree to the amendments being requested by the Borrower, but only on the terms and subject to the conditions set forth in this First Amendment; and WHEREAS, each of the signatories hereto is a party to the Credit Agreement; NOW, THEREFORE, in consideration of the premises and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Borrower, the Administrative Agent, the Banks, and each of the other signatories hereto hereby agree as follows: SECTION 1. Terms Defined in the Credit Agreement. Each term defined in the Credit Agreement (as amended hereby) and not otherwise defined herein shall have the meaning assigned to such term in the Credit Agreement. Unless otherwise indicated, all section and article references in this First Amendment refer to the Credit Agreement. SECTION 2. Amendments to the Credit Agreement. (a) Amendment to the Definitions Section. (i) Section 1.01 of the Credit Agreement is hereby amended by amending and restating in their entirety the following definitions: "ADMINISTRATIVE AGENT" means The Chase Manhattan Bank, in its capacity as administrative agent for the Banks under this Agreement, and its successor in such capacity. "BANK" means each bank listed on the signature pages of the First Amendment, each Assignee which becomes a Bank pursuant to SECTION 9.06(c), and their respective successors. "BORROWER'S LATEST FORM 10-Q" means the Borrower's quarterly report on Form 10-Q for the quarter ended June 30, 2001 as filed with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934. "DOCUMENTATION AGENT" means, collectively, the Co-Documentation Agents. "REQUIRED BANKS" means at any time the Banks having at least 51% of the aggregate amount of the Commitments or, if the Commitments shall have been terminated, holding Loans evidencing at least 51% of the aggregate unpaid principal amount of the Loans. "REVOLVING TERMINATION DATE" means the earlier of (i) October 22, 2002 (or such later date to which the Revolving Termination Date may be extended pursuant to Section 2.16 hereof) or (ii) the effective date of any other termination, cancellation, or acceleration of all commitments to lend hereunder. (ii) Section 1.01 of the Credit Agreement is hereby amended by deleting the definition of "Borrower's 1999 Form 10-K" and replacing it with the following definition: "BORROWER'S 2000 FORM 10-K" means the Borrower's annual report on Form 10-K for 2000, as filed with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934. (iii) Section 1.01 of the Credit Agreement is hereby amended by adding the following definitions in their proper alphabetical order: "CO-DOCUMENTATION AGENTS" means Commerzbank AG, New York and Grand Cayman Branches, The Bank of Nova Scotia, and Credit Lyonnais." "FIRST AMENDMENT" means the First Amendment to Credit Agreement dated as of October 23, 2001, among the Borrower, the Banks listed on the signature pages thereof, Chase as Administrative Agent and the Syndication Agent and Co-Documentation Agents. (b) Amendment to Financial Information Representation and Warranty. (i) Section 4.04(a) of the Credit Agreement is hereby amended by deleting the year "1999" from the date in the second line and replacing it with the year "2000." Section 4.04(a) of the Credit Agreement is further amended by deleting the term "Borrower's 1999 Form 10-K" and replacing it with the term "Borrower's 2000 Form 10-K." (ii) Section 4.04(b) of the Credit Agreement is hereby amended by deleting the year "2000" from the date in the second line and replacing it with the year "2001." (iii) Section 4.04(c) of the Credit Agreement is hereby amended by deleting the year "2000" from the date in the first line and replacing it with the year "2001." (c) Amendment to The Agents Section. Section 7.02 is hereby amended by replacing the words "Bank of America, N.A." with "The Chase Manhattan Bank." (d) Amended and Restated Schedule 1.01. Schedule 1.01 to the Credit Agreement is hereby amended, restated, and replaced in its entirety by the Schedule 1.01 attached to this First Amendment. SECTION 3. Limitations. The amendments set forth herein are limited precisely as written and shall not (a) be deemed to be a waiver or modification of any other term or condition of the Credit Agreement or (b) except as expressly set forth herein, prejudice any right or rights which the Banks may now have or may have in the future under or in connection with the Credit Agreement or any of the other documents or instruments referred to therein. Except as expressly modified hereby or by express written amendments thereof, the Credit Agreement and each of the other documents and instruments executed in connection with any of the foregoing are and shall remain in full force and effect. In the event of a conflict between this First Amendment and any of the foregoing documents, the terms of this First Amendment shall be controlling. SECTION 5. Effectiveness. This First Amendment shall not be effective unless and until the Administrative Agent shall have received this First Amendment, executed and delivered by the Borrower, the Administrative Agent and the Required Banks. SECTION 6. Representations and Warranties. The Borrower hereby represents and warrants to the Administrative Agent and each of the Banks that (a) each of the representations and warranties made by the Borrower in or pursuant to the Credit Agreement is true and correct in all material respects as of the date hereof, as if made (after giving effect to this First Amendment) on and as of such date, except for any representations and warranties made as of a specified date, which are true and correct in all material respects as of such specified date and (b) after giving effect to this First Amendment, no Default or Event of Default has occurred and is continuing as of the date hereof. SECTION 7. Adoption, Ratification and Confirmation of Credit Agreement. The Borrower hereby adopts, ratifies and confirms the Credit Agreement, as amended hereby, and acknowledges and agrees that the Credit Agreement, as amended hereby, is and remains in full force and effect. SECTION 8. Governing Law. THIS FIRST AMENDMENT AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES HEREUNDER SHALL BE CONSTRUED IN ACCORDANCE WITH AND BE GOVERNED BY THE LAWS OF THE STATE OF NEW YORK. SECTION 9. Descriptive Headings, Etc. The descriptive headings of the several sections of this First Amendment are inserted for convenience only and shall not be deemed to affect the meaning or construction of any of the provisions hereof. SECTION 10. Entire Agreement. This First Amendment and the documents referred to herein represent the entire understanding of the parties hereto regarding the subject matter hereof and supersede all prior and contemporaneous oral and written agreements of the parties hereto with respect to the subject matter hereof. SECTION 11. Counterparts. This First Amendment may be executed in any number of counterparts (including by telecopy) and by different parties on separate counterparts and all of such counterparts shall together constitute one and the same instrument. SECTION 12. Successors. The execution and delivery of this First Amendment by any Bank shall be binding upon each of its successors and assigns (including transferees of its Commitment and Loans in whole or in part prior to the effectiveness hereof) and binding in respect of all of its Commitment and Loans. [signatures begin on the next page] IN WITNESS WHEREOF, the parties hereto have caused this First Amendment to be duly executed by their respective authorized officers as of the day and year first above written. KINDER MORGAN, INC. By:_____________________________________ Name:________________________________ Title:_______________________________ THE CHASE MANHATTAN BANK, as Administrative Agent and as a Bank By:_____________________________________ Name: Title: FIRST UNION NATIONAL BANK, as Syndication Agent and as a Bank By:_____________________________________ Name:________________________________ Title:_______________________________ BANK ONE, NA By:_____________________________________ Name:________________________________ Title:_______________________________ THE BANK OF NOVA SCOTIA By:_____________________________________ Name:________________________________ Title:_______________________________ CITIBANK, N.A. By:_____________________________________ Name:________________________________ Title:_______________________________ COMMERZBANK AG, NEW YORK AND GRAND CAYMAN BRANCHES By:_____________________________________ Name:________________________________ Title:_______________________________ By:_____________________________________ Name:________________________________ Title:_______________________________ CREDIT LYONNAIS NEW YORK BRANCH By:_____________________________________ Name:________________________________ Title:_______________________________ TORONTO DOMINION (TEXAS), INC. By:_____________________________________ Name:________________________________ Title:_______________________________ U.S. BANK NATIONAL ASSOCIATION By:_____________________________________ Name:________________________________ Title:_______________________________ ABN AMRO BANK N.V. By:_____________________________________ Name:________________________________ Title:_______________________________ ARAB BANKING CORPORATION By:_____________________________________ Name:________________________________ Title:_______________________________ THE BANK OF TOKYO-MITSUBISHI, LTD., HOUSTON AGENCY By:_____________________________________ Name:________________________________ Title:_______________________________ MORGAN GUARANTY TRUST COMPANY OF NEW YORK By:_____________________________________ Name:________________________________ Title:_______________________________ WELLS FARGO BANK TEXAS, N.A. By:_____________________________________ Name:________________________________ Title:_______________________________ EX-4.M 4 h94310ex4-m.txt AMENDMENT NO.3 TO RIGHT AGREEMENT EXHIBIT 4(m) AMENDMENT NO. 3 TO RIGHTS AGREEMENT 1. GENERAL BACKGROUND. In accordance with Section 22 of the Rights Agreement between FIRST CHICAGO TRUST COMPANY OF NEW YORK (the "Rights Agent") and KINDER MORGAN INC. ( F/K/A K N ENERGY, INC.) ("KMI") dated July 8, 1999 (the "Agreement"), the Rights Agent and KMI desire to amend the Agreement to appoint EquiServe Trust Company, N.A. 2. EFFECTIVENESS. This Amendment shall be effective as of September 1, 2001 (the "Amendment") and all defined terms and definitions in the Agreement shall be the same in the Amendment except as specifically revised by the Amendment. 3. REVISION. The section in the Agreement entitled "Change of Rights Agent" is hereby deleted in its entirety and replaced with the following: Change of Rights Agent. The Rights Agent or any successor Rights Agent may resign and be discharged from its duties under this Agreement upon 30 days' notice in writing mailed to the Company and to each transfer agent of the Common Shares or Preferred shares by registered or certified mail and to the holders of the Right Certificates by first-class mail. The Company may remove the Rights Agent or any successor Rights Agent upon 30 days' notice in writing mailed to the Rights Agent or successor Rights Agent, as the case may be, and to each transfer agent of the Common Shares or Preferred Shares by registered or certified mail, and to the holders of the Right Certificates by first-class mail. If the Rights Agent shall resign or be removed or shall otherwise become incapable of acting, the Company shall appoint a successor to the Rights Agent. If the Company shall fail to make such appointment within a period of 30 days after giving notice of such removal or after it has been notified in writing of such resignation or incapacity by the resigning or incapacitated rights Agent or by the holder of a Right Certificate (who shall, with such notice, submit such holder's Right Certificate for inspection by the company), then the registered holder of any Right Certificate may apply to any court of competent jurisdiction for the appointment of a new Rights Agent. Any successor Rights Agent, whether appointed by the Company or by such a court, shall be a corporation or trust company organized and doing business under the laws of the United States, in good standing, which is authorized under such laws to exercise corporate trust or stock transfer powers and is subject to supervision or examination by federal or state authority and which has individually or combined with an affiliate at the time of its appointment as Rights Agent a combined capital and surplus of at least $100 million dollars. After appointment, the successor Rights Agent shall be vested with the same powers, rights, duties and responsibilities as if it had been originally named as Rights Agent without further act or deed; but the predecessor Rights Agent shall deliver and transfer to the successor Rights Agent any property at the time held by it hereunder, and execute and deliver any further assurance, conveyance, act or deed necessary for the purpose. Not later than the effective date of any such appointment the Company shall file notice thereof in writing with the predecessor Rights Agent and each transfer agent of the Common Shares or Preferred Shares, and mail a notice thereof in writing to the registered holders of the Right Certificates. Failure to give any notice provided for in this Section , however, or any defect therein, shall not affect the legality or validity of the resignation or removal of the Rights Agent or the appointment of the successor Rights Agent, as the case may be. 4. Except as amended hereby, the Agreement and all schedules or exhibits thereto shall remain in full force and effect. IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be executed in their names and on their behalf by and through their duly authorized officers, as of this 1st day of September, 2001. KINDER MORGAN INC. FIRST CHICAGO TRUST CO. OF NEW YORK /s/ JOSEPH LISTENGART /s/ M.J. FOLEY - -------------------------------- ------------------------------------ By: Joseph Listengart By: M.J. Foley Title: Vice President Title: Chief Marketing Officer EX-10.L 5 h94310ex10-l.txt RETENTION AGREEMENT - C. PARK SHAPER EXHIBIT 10(l) KINDER MORGAN, INC. RETENTION AGREEMENT THIS RETENTION AGREEMENT (the "Agreement"), dated as of January 17th, 2002 ("Effective Date"), is by and between Kinder Morgan, Inc., a Kansas corporation (the "Company"), and C. Park Shaper (the "Executive"). WHEREAS, Executive is an employee of the Company; and WHEREAS, effective January 17th, 2002, Executive has obtained a loan from First Union National (the "Lender") in the principal amount of $5,000,000 (the "Loan"), the proceeds of which will be used by Executive to purchase shares of common stock of the Company and/or limited partnership interests in Kinder Morgan Energy Partners, L.P. (collectively, the "Shares") and the terms of which are set forth in a promissory note. NOW, THEREFORE, for and in consideration of the mutual covenants and promises contained herein and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows: 1. Loan Repayment. In addition to the base compensation, equity based compensation and other benefits provided to Executive by the Company in consideration of Executive's employment, the Company shall pay the Lender a portion or all of the principal amount of the Loan on behalf of Executive in accordance with the following provisions: (a) Except as provided otherwise herein, beginning with the fifth anniversary of the Effective Date and continuing on the sixth, seventh, eighth and ninth anniversaries of the Effective Date, the Company shall pay the Lender $1,000,000 of the principal amount of the Loan on behalf of Executive on each such anniversary. (b) If, prior to the fifth anniversary of the Effective Date, Executive's employment is terminated by the Company "for cause" (as defined below), the Agreement shall immediately terminate, and the Company shall have no further obligations hereunder, including the payment of any portion of the Loan. As used in this Agreement, the term "for cause" means (i) willful misconduct by Executive of his duties as an employee, officer or director of the Company, (ii) gross neglect by Executive of his duties as an employee, officer or director of the Company, which continues for more than thirty (30) days after Executive's receipt of written notice from the Board of Directors of the Company (the "Board") to Executive specifically identifying the gross neglect of Executive and directing Executive to discontinue the same, (iii) the conviction of Executive of a crime constituting a felony, or (iv) the commission by Executive of an act or making by Executive of an omission, other than an act taken or omission made in good faith within the course and scope of Executive's employment, which the Board determines is directly detrimental to the Company and exposes the Company to material liability. (c) Subject to Sections 2(e) and 2(f), if, prior to the fifth anniversary of the Effective Date, Executive voluntarily terminates his employment with the Company, the Agreement shall immediately terminate, and the Company shall have no further obligations hereunder, including the payment of any portion of the Loan. (d) If, prior to the fifth anniversary of the Effective Date, Executive's employment is terminated because of Executive's death or disability, or the Company terminates Executive's employment for any reason other than (i) "for cause" or (ii) pursuant to Section 2(e) below, the Company shall pay the Lender, on behalf of the Executive, principal on the Loan in an amount in one lump sum equal to $5,000,000 multiplied by a fraction, the numerator of which is the number of years (rounded to the nearest whole year) that have elapsed from the Effective Date to the date of termination, and the denominator of which is five (5). Upon such payment by the Company, the Agreement shall immediately terminate, and the Company shall have no further obligations hereunder. (e) If Executive's employment is terminated for any reason other than "for cause" after a "Change of Control" (as defined below), the Company shall pay the Lender, on behalf of the Executive, principal on the Loan in an amount equal to the lesser of (i) $5,000,000, or (ii) the unpaid principal amount of the Loan at the time of such termination in one lump sum. Upon such payment by the Company, the Agreement shall immediately terminate, and the Company shall have no further obligations hereunder. For purposes of this Agreement, a "Change of Control" shall occur if: (A) (i) any "person," as such term is used in Sections 13(d) and 14(d) of the Securities Exchange Act of 1934, as amended (the "1934 Act") (other than the Company, any trustee or other fiduciary holding securities under an employee benefit plan of the Company or any corporation owned, directly or indirectly, by the shareholders of the Company in substantially the same proportions as their ownership of stock of the Company), is or becomes the "beneficial owner" (as defined in Rule 13d-3 under the 1934 Act), directly or indirectly, of securities of the Company representing fifty percent (50%) or more of the combined voting power of the Company's then outstanding securities, (ii) during any period of two consecutive years (not including any period prior to the Effective Date), individuals who at the beginning of such period constitute the Board, and any new director (other than a director designated by a person who has entered into an agreement with the Company to effect a transaction described in (i), (iii) or (iv) of this paragraph) whose election -2- by the Board or nomination for election by the Company's shareholders was approved by a vote of at least two-thirds (2/3) of the directors then still in office who either were directors at the beginning of the period or whose election or nomination for election was previously so approved, cease for any reason other than normal retirement, death or disability to constitute at least a majority thereof, (iii) the shareholders of the Company approve a merger or consolidation of the Company with any other person, other than (1) a merger or consolidation which would result in the voting securities of the Company outstanding immediately prior thereto continuing to represent (either by remaining outstanding or being converted into voting securities for the surviving entity) more than fifty percent (50%) of the combined voting power of the voting securities of the Company or such surviving entity outstanding immediately after such merger or consolidation, or (2) a merger in which the Company is the surviving entity but no "person" (as defined above) acquires more than fifty percent (50%) of the combined voting power of the Company's then outstanding securities, or (iv) the shareholders of the Company approve a plan of complete liquidation of the Company or an agreement for the sale or disposition by the Company of all or substantially all of the Company's assets (or any transaction having a similar effect), and (B) in connection with or as a result of an event described in clause (A), neither William V. Morgan nor Richard D. Kinder holds or continues to hold the office of Chairman or Vice Chairman of the Company. (f) If (i) at any time after a Change of Control and before the date on which the Loan matures, the Executive is (A) assigned to a position other than the position the Executive held at the time of the Change of Control; (B) assigned duties materially inconsistent with his duties at the time of the Change of Control; or (C) required, as a condition to continued employment, to move to a location more than 50 miles from Houston, Texas, in any case, without the Executive's consent, and (ii) the Executive voluntarily terminates his employment with the Company during the period beginning ninety (90) days after the Change of Control and ending on the date on which the Loan matures, the Company shall pay the Lender an amount equal to the lesser of (A) $5,000,000, or (B) the unpaid principal amount of the Loan at the time of such termination of employment in one lump sum. Upon such payment by the Company, the Agreement shall immediately terminate, and the Company shall have no further obligations hereunder. 2. No Funding Requirement. Nothing contained in this Agreement and no action taken pursuant to the provisions of this Agreement shall create or be construed to create a trust of any kind, or a fiduciary relationship between the Company and Executive or any other person. Any funds which may be used to repay the Loan under the provisions of this Agreement shall continue for all purposes to be a part of the general funds of the Company until paid, and no person other than the Company shall by virtue -3- of the provisions of this Agreement have any interest in such funds. To the extent that any person acquires a right to receive payments from the Company under this Agreement or to have payments made by the Company on such person's behalf, such right shall be no greater than the right of any unsecured general creditor of the Company. 3. Non-Alienation. The right of Executive or any other person to the payments by the Company toward the Loan or other benefits under this Agreement may not be assigned, transferred, pledged or encumbered except by will or by the laws of descent and distribution. 4. Arbitration. Any controversy or claim arising out of or relating to this Agreement shall be settled by arbitration in accordance with the National Rules for the Resolution of Employment Disputes of the American Arbitration Association, as amended from time to time, before a panel of three neutral arbitrators. Each party shall appoint one arbitrator within 30 days after demand for arbitration is made and the two appointed arbitrators shall appoint a third arbitrator within 30 days of their appointment. The arbitration proceedings shall take place in Houston, Texas as soon as administratively possible after the appointment of the third arbitrator and thereafter shall be conducted as expeditiously as reasonably possible. The award rendered by the arbitrator shall be final and binding on the parties, and judgment may be entered upon it in accordance with Texas law in a Harris County court having jurisdiction of it. A demand for arbitration shall be filed in writing with the other party to this Agreement. A demand for arbitration shall be made within a reasonable time after the claim, dispute or other matter in question has arisen. In no event shall the demand for arbitration be made after the date when institution of legal or equitable proceedings based upon the claim, dispute or other matter in question would be barred by applicable statutes of limitations. The parties to this Agreement will share the cost of the arbitrators and any costs related to the location used for the arbitration. 5. Miscellaneous. (a) Nothing contained herein shall be construed as conferring upon Executive the right to continue in the employ of the Company as an executive or in any other capacity. (b) The amounts payable under this Agreement shall not be deemed salary or other compensation to Executive for the purpose of computing benefits to which he may be entitled under any pension plan or other arrangement of the Company for the benefit of its employees. (c) The Board shall have full power and authority to interpret, construe, and administer this Agreement and the Board's interpretations and construction thereof shall be binding and conclusive on all persons for all purposes. No member of the Board shall be liable to any person for any action taken or omitted in connection with the interpretation and administration of this Agreement unless attributable to his own willful misconduct or lack of good faith. -4- (d) Any questions as to whether and when there has been a termination of Executive's employment and the cause of such termination shall be determined by the Board, and its determination shall be final. (e) This Agreement shall be binding upon and inure to the benefit of the Company, its successors and assigns, and Executive and his heirs, executors, administrators, and legal representatives. (f) This Agreement shall be construed in accordance with and governed by the law of the State of Texas unless otherwise pre-empted by federal law. -5- IN WITNESS WHEREOF, the Company has executed this Agreement by its officer thereto duly authorized, and Executive has executed this Agreement, all effective as of the day and year first above written. KINDER MORGAN, INC. By: /s/ James E. Street ------------------------------ Print Name: James E. Street ---------------------- Title: Vice President - Human Resources -------------------------- EXECUTIVE /s/ C. Park Shaper --------------------------------- -6- EX-21.1 6 h94310ex21-1.txt SUBSIDIARIES OF THE REGISTRANT EXHIBIT 21.1 KINDER MORGAN, INC. AND SUBSIDIARIES NAME OF COMPANY KN Cogeneration, Inc. Thermo Gas Marketing, Inc. Thermo Project Management, Inc. Valley Operating, Inc. KN Thermo, L.L.C. Kinder Morgan Ft. Lupton Operator LLC Thermo Cogeneration Partnership, L.P. Thermo Greeley, LLC KN Telecommunications, Inc. KN Gas Supply Services, Inc. KN Natural Gas, Inc. Red Rock Energy, LLC Kinder Morgan Power Company KN TransColorado, Inc. Northern Gas Company Rocky Mountain Natural Gas Company Kinder Morgan Foundation (nonprofit) Western Slope Energy Services, LLC KN Gas Gathering, Inc. MidCon Corp. MidCon Gas Services Corp. MCN Gulf Processing Corp. Natural Gas Pipeline Company of America NGPL Overthrust, Inc. NGPL Canyon Compression Co. Canyon Creek Compression Company Horizon Pipeline Company, LLC KN Management Corp. MidCon Mexico Pipeline Corp. Kinder Morgan Gas Natural de Mexico S. de R.L. de C.V. KN Energy International, Inc. Kinder Morgan Igasamex, Inc. KM International Services, Inc. Lake Power L.L.C. FR Holdings L.L.C. Front Range Energy Associates, LLC Kinder Morgan Michigan LLC Kinder Morgan Illinois LLC Kinder Morgan Missouri LLC Kinder Morgan Power Partners LLC Kinder Morgan Michigan Pipeline LLC Kinder Morgan Arkansas LLC KM Turbine Facility #6 LLC KM Turbine Facility #7 LLC Kinder Morgan Operator LLC Kinder Morgan Michigan Operator LLC Kinder Morgan Michigan Servicer LLC Kinder Morgan Michigan Contractor LLC Kinder Morgan Michigan Developer LLC Triton Power Company LLC Triton Power Michigan LLC KMC Thermo, L.L.C. Administracion y Operacion de Infraestructura, S.A. de C.V. GNN Services, S. de R.L. de C.V. Gas Natural del Noroeste, S.A. de C.V. EX-23.1 7 h94310ex23-1.txt CONSENT OF INDEPENDENT ACCOUNTANTS EXHIBIT 23.1 CONSENT OF INDEPENDENT ACCOUNTANTS We hereby consent to the incorporation by reference in the Registration Statements on (i) Form S-16 (Nos. 2-51894, 2-55664, 2-63470 and 2-75654), (ii) Form S-8 (Nos. 2-77752, 33-10747, 33-24934, 33-33018, 33-54403, 33-54443, 33-54555, 333-08059, 333-08087, 333-60839, 333-42178 and 333-53908) and (iii) Form S-3 (Nos. 2-84910, 33-26314, 33-23880, 33-42698, 33-44871, 33-45091, 33-46999, 33-54317, 33-69432, 333-04385, 333-40869, 333-44421, 333-55921, 333-68257, 333-54896, 333-55866 and 333-91257) of Kinder Morgan, Inc. of our report dated February 15, 2002 relating to the financial statements and financial statement schedule, which appears in this Form 10-K, and of our report dated February 15, 2002 relating to the financial statements and financial statement schedule of Kinder Morgan Energy Partners, L.P., which appears in Kinder Morgan Energy Partners, L.P.'s Annual Report on Form 10-K which is incorporated by reference in this Form 10-K. /s/ PRICEWATERHOUSECOOPERS LLP Houston, Texas February 19, 2002 EX-99.1 8 h94310ex99-1.txt FINANCIAL STATEMENTS EXHIBIT 99.1 INDEX TO FINANCIAL STATEMENTS PAGE ---- KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES Report of Independent Accountants........................... 75 Consolidated Statements of Income for the years ended December 31, 2001, 2000, and 1999......................... 76 Consolidated Statements of Comprehensive Income for the years ended December 31, 2001, 2000, and 1999............. 77 Consolidated Balance Sheets for the years ended December 31, 2001 and 2000............................................. 78 Consolidated Statements of Cash Flows for the years ended December 31, 2001, 2000, and 1999......................... 79 Consolidated Statements of Partners' Capital for the years ended December 31, 2001, 2000, and 1999................... 80 Notes to Consolidated Financial Statements..................
74 REPORT OF INDEPENDENT ACCOUNTANTS To the Partners of Kinder Morgan Energy Partners, L.P. In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Kinder Morgan Energy Partners, L.P. and its subsidiaries (the Partnership) at December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule appearing under Item 14(a)(2) on page 71 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Partnership's management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. As discussed in Note 14 to the consolidated financial statements, the Partnership changed its method of accounting for derivative instruments and hedging activities effective January 1, 2001. /s/ PRICEWATERHOUSECOOPERS LLP Houston, Texas February 15, 2002 75 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME
YEAR ENDED DECEMBER 31, --------------------------------------- 2001 2000 1999 ------------ ----------- ---------- (IN THOUSANDS EXCEPT PER UNIT AMOUNTS) Revenues Natural gas sales........................................ $1,583,817 $ 10,196 $ -- Services................................................. 997,845 643,772 393,131 Product sales and other.................................. 365,014 162,474 35,618 ---------- --------- -------- 2,946,676 816,442 428,749 ---------- --------- -------- Costs and Expenses Gas purchases and other costs of sales................... 1,657,689 124,641 16,241 Operations and maintenance............................... 356,654 164,379 95,121 Fuel and power........................................... 73,188 43,216 31,745 Depreciation and amortization............................ 142,077 82,630 46,469 General and administrative............................... 99,009 60,065 35,612 Taxes, other than income taxes........................... 54,231 25,950 16,154 ---------- --------- -------- 2,382,848 500,881 241,342 ---------- --------- -------- Operating Income........................................... 563,828 315,561 187,407 Other Income (Expense) Earnings from equity investments......................... 84,834 71,603 42,918 Amortization of excess cost of equity investments........ (9,011) (8,195) (4,254) Interest, net............................................ (171,457) (93,284) (52,605) Other, net............................................... 1,962 14,584 14,085 Gain on sale of equity interest, net of special charges............................................... -- -- 10,063 Minority Interest.......................................... (11,440) (7,987) (2,891) ---------- --------- -------- Income Before Income Taxes and Extraordinary Charge........ 458,716 292,282 194,723 Income Taxes............................................... 16,373 13,934 9,826 ---------- --------- -------- Income Before Extraordinary Charge......................... 442,343 278,348 184,897 Extraordinary Charge on Early Extinguishment of Debt....... -- -- (2,595) ---------- --------- -------- Net Income................................................. $ 442,343 $ 278,348 $182,302 ========== ========= ======== Calculation of Limited Partners' Interest in Net Income: Income Before Extraordinary Charge......................... $ 442,343 $ 278,348 $184,897 Less: General Partner's interest in Net Income............. (202,095) (109,470) (56,273) ---------- --------- -------- Limited Partners' net Income before Extraordinary Charge... 240,248 168,878 128,624 Less: Extraordinary Charge on Early Extinguishment of Debt..................................................... -- -- (2,595) ---------- --------- -------- Limited Partners' Net Income............................... $ 240,248 $ 168,878 $126,029 ========== ========= ======== Basic Limited Partners' Net Income per Unit: Income before Extraordinary Charge......................... $ 1.56 $ 1.34 $ 1.31 Extraordinary Charge....................................... -- -- (.02) ---------- --------- -------- Net Income................................................. $ 1.56 $ 1.34 $ 1.29 ========== ========= ======== Weighted Average Units Outstanding......................... 153,901 126,212 97,948 ========== ========= ======== Diluted Limited Partners' Net Income per Unit: Income before Extraordinary Charge......................... $ 1.56 $ 1.34 $ 1.31 Extraordinary Charge....................................... -- -- (.02) ---------- --------- -------- Net Income................................................. $ 1.56 $ 1.34 $ 1.29 ========== ========= ======== Weighted Average Units Outstanding......................... 154,110 126,300 97,986 ========== ========= ========
The accompanying notes are an integral part of these consolidated financial statements. 76 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
YEAR ENDED DECEMBER 31, ------------------------------ 2001 2000 1999 -------- -------- -------- (IN THOUSANDS) Revenues Net Income................................................ $442,343 $278,348 $182,302 Cumulative effect transition adjustment................... (22,797) -- -- Change in fair value of derivatives used for hedging purposes............................................... 35,162 -- -- Reclassification of change in fair value of derivatives to net income............................................. 51,461 -- -- -------- -------- -------- Comprehensive Income...................................... $506,169 $278,348 $182,302 ======== ======== ========
The accompanying notes are an integral part of these consolidated financial statements. 77 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
DECEMBER 31, ----------------------- 2001 2000 ---------- ---------- (IN THOUSANDS) ASSETS Current Assets Cash and cash equivalents................................. $ 62,802 $ 59,319 Accounts and notes receivable Trade.................................................. 215,860 345,065 Related parties........................................ 52,607 3,384 Inventories Products............................................... 2,197 24,137 Materials and supplies................................. 6,212 4,972 Gas imbalances............................................ 15,265 26,878 Gas in underground storage................................ 18,214 27,481 Other current assets...................................... 194,886 20,025 ---------- ---------- 568,043 511,261 ---------- ---------- Property, Plant and Equipment, net.......................... 5,082,612 3,306,305 Investments................................................. 440,518 417,045 Notes receivable............................................ 3,095 9,101 Intangibles, net............................................ 563,397 345,305 Deferred charges and other assets........................... 75,001 36,193 ---------- ---------- TOTAL ASSETS................................................ $6,732,666 $4,625,210 ========== ========== LIABILITIES AND PARTNERS' CAPITAL Current Liabilities Accounts payable Trade.................................................. $ 111,853 $ 293,268 Related parties........................................ 9,235 8,255 Current portion of long-term debt......................... 560,219 648,949 Accrued interest.......................................... 34,099 18,592 Deferred revenues......................................... 2,786 43,978 Gas imbalances............................................ 34,660 48,834 Accrued other liabilities................................. 209,852 37,080 ---------- ---------- 962,704 1,098,956 ---------- ---------- Long-Term Liabilities and Deferred Credits Long-term debt............................................ 2,231,574 1,255,453 Deferred revenues......................................... 29,110 1,503 Deferred income taxes..................................... 38,544 2,487 Other..................................................... 246,464 91,575 ---------- ---------- 2,545,692 1,351,018 ---------- ---------- Commitments and Contingencies (Notes 13 and 16) Minority Interest........................................... 65,236 58,169 ---------- ---------- Partners' Capital Common Units (129,855,018 and 129,716,218 units issued and outstanding at December 31, 2001 and 2000, respectively).......................................... 1,894,677 1,957,357 Class B Units (5,313,400 and 5,313,400 units issued and outstanding at December 31, 2001 and 2000, respectively).......................................... 125,750 125,961 i-Units (30,636,363 and 0 units issued and outstanding at December 31, 2001 and 2000, respectively).............. 1,020,153 -- General Partner........................................... 54,628 33,749 Accumulated other comprehensive income.................... 63,826 -- ---------- ---------- 3,159,034 2,117,067 ---------- ---------- TOTAL LIABILITIES AND PARTNERS' CAPITAL..................... $6,732,666 $4,625,210 ========== ==========
The accompanying notes are an integral part of these consolidated financial statements. 78 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31, ------------------------------------- 2001 2000 1999 ----------- ----------- --------- (DOLLARS IN THOUSANDS) Cash Flows From Operating Activities Net income.................................................. $ 442,343 $ 278,348 $ 182,302 Adjustments to reconcile net income to net cash provided by operating activities: Extraordinary charge on early extinguishment of debt...... -- -- 2,595 Depreciation and amortization............................. 142,077 82,630 46,469 Amortization of excess cost of equity investments......... 9,011 8,195 4,254 Earnings from equity investments.......................... (84,834) (71,603) (42,918) Distributions from equity investments..................... 68,832 47,512 33,686 Gain on sale of equity interest, net of special charges... -- -- (10,063) Changes in components of working capital: Accounts receivable..................................... 174,098 6,791 (12,358) Other current assets.................................... 22,033 (6,872) -- Inventories............................................. 22,535 (1,376) (2,817) Accounts payable........................................ (183,179) (8,374) (9,515) Accrued liabilities..................................... (47,692) 26,479 11,106 Accrued taxes........................................... 8,679 (1,302) 497 Rate refunds settlement................................... (100) (52,467) -- Other, net................................................ 7,358 (6,394) (20,382) ----------- ----------- --------- Net Cash Provided by Operating Activities................... 581,161 301,567 182,856 ----------- ----------- --------- Cash Flows From Investing Activities Acquisitions of assets.................................... (1,523,454) (1,008,648) 5,678 Additions to property, plant and equipment for expansion and maintenance projects................................ (295,088) (125,523) (82,725) Sale of investments, property, plant and equipment, net of removal costs........................................... 9,043 13,412 43,084 Acquisitions of investments............................... -- (79,388) (161,763) Other..................................................... (9,394) 2,581 (800) ----------- ----------- --------- Net Cash Used in Investing Activities....................... (1,818,893) (1,197,566) (196,526) ----------- ----------- --------- Cash Flows From Financing Activities Issuance of debt.......................................... 4,053,734 2,928,304 550,287 Payment of debt........................................... (3,324,161) (1,894,904) (333,971) Loans to related party.................................... (17,100) -- -- Debt issue costs.......................................... (8,008) (4,298) (3,569) Proceeds from issuance of common units.................... 4,113 171,433 68 Proceeds from issuance of i-units......................... 996,869 -- -- Contributions from General Partner........................ 11,716 7,434 146 Distributions to partners Common units............................................ (268,644) (194,691) (135,835) Class B units........................................... (8,501) -- -- General Partner......................................... (181,198) (91,366) (52,674) Minority interest....................................... (14,827) (7,533) (2,316) Other, net................................................ (2,778) 887 (149) ----------- ----------- --------- Net Cash Provided by Financing Activities................... 1,241,215 915,266 21,987 ----------- ----------- --------- Increase in Cash and Cash Equivalents....................... 3,483 19,267 8,317 Cash and Cash Equivalents, beginning of period.............. 59,319 40,052 31,735 ----------- ----------- --------- Cash and Cash Equivalents, end of period.................... $ 62,802 $ 59,319 $ 40,052 =========== =========== ========= Noncash Investing and Financing Activities: Contribution of net assets to partnership investments..... $ -- $ -- $ 20 Assets acquired by the issuance of units.................. -- 179,623 420,850 Assets acquired by the assumption of liabilities.......... 293,871 333,301 111,509 Supplemental disclosures of cash flow information: Cash paid during the year for Interest (net of capitalized interest).................... 165,357 88,821 48,222 Income taxes.............................................. 2,168 1,806 529
The accompanying notes are an integral part of these consolidated financial statements. 79 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
2001 2000 1999 ------------------------ ------------------------ ------------------------ UNITS AMOUNT UNITS AMOUNT UNITS AMOUNT ----------- ---------- ----------- ---------- ----------- ---------- (DOLLARS IN THOUSANDS) Common Units: Beginning Balance.................... 129,716,218 $1,957,357 118,274,274 $1,759,142 97,643,380 $1,348,591 Net income........................... -- 203,559 -- 168,878 -- 126,029 Units issued as consideration in the acquisition of assets or businesses......................... -- -- 2,428,344 53,050 20,640,294 420,610 Units issued for cash................ 138,800 2,405 9,013,600 170,978 4,000 68 Distributions........................ -- (268,644) -- (194,691) -- (135,835) Repurchases.......................... -- -- -- -- (13,400) (321) ----------- ---------- ----------- ---------- ----------- ---------- Ending Balance....................... 129,855,018 1,894,677 129,716,218 1,957,357 118,274,274 1,759,142 Class B Units: Beginning Balance.................... 5,313,400 125,961 -- -- -- -- Net income........................... -- 8,335 -- -- -- -- Units issued as consideration in the acquisition of assets or businesses......................... -- -- 5,313,400 125,961 -- -- Units issued for cash................ -- (44) -- -- -- -- Distributions........................ -- (8,502) -- -- -- -- ----------- ---------- ----------- ---------- ----------- ---------- Ending Balance....................... 5,313,400 125,750 5,313,400 125,961 -- -- i-Units: Beginning Balance.................... -- -- -- -- -- -- Net income........................... -- 28,354 -- -- -- -- Units issued for cash................ 29,750,000 991,799 Distributions........................ 886,363 -- -- -- -- -- Repurchases.......................... -- -- -- -- -- -- ----------- ---------- ----------- ---------- ----------- ---------- Ending Balance....................... 30,636,363 1,020,153 -- -- -- -- General Partner: Beginning Balance.................... -- 33,749 -- 15,656 -- 12,072 Net income........................... -- 202,095 -- 109,470 -- 56,273 Units issued as consideration in the acquisition of assets or businesses......................... -- -- -- (11) -- (15) Units issued for cash................ -- (18) -- -- -- Distributions........................ -- (181,198) -- (91,366) -- (52,674) Repurchases.......................... -- -- -- -- -- -- ----------- ---------- ----------- ---------- ----------- ---------- Ending Balance....................... -- 54,628 -- 33,749 -- 15,656 Accumulated other comprehensive income: Beginning Balance.................... -- -- -- -- -- -- Cumulative effect transition adj. ... -- (22,797) -- -- -- -- Change in fair value of derivatives used for hedging purposes.......... -- 35,162 -- -- -- -- Reclassification of change in fair value of derivatives to net income............................. -- 51,461 -- -- -- -- ----------- ---------- ----------- ---------- ----------- ---------- Ending Balance....................... -- 63,826 -- -- -- -- Total Partners' Capital................ -- $3,159,034 -- $2,117,067 -- $1,774,798 =========== ========== =========== ========== =========== ==========
The accompanying notes are an integral part of these consolidated financial statements. 80 1. ORGANIZATION GENERAL Kinder Morgan Energy Partners, L.P., the "Partnership", is a Delaware limited partnership formed in August 1992. We are a publicly traded limited partnership managing a diversified portfolio of midstream energy assets. We provide services to our customers and increase value for our unitholders primarily through the following activities: - transporting, storing and processing refined petroleum products; - transporting, storing and selling natural gas; - transporting carbon dioxide for use in enhanced oil recovery operations; and - transloading, storing and delivering a wide variety of bulk, petroleum and petrochemical products at terminal facilities located across the United States. We focus on providing fee-based services to customers, avoiding commodity price risks and taking advantage of the low-cost capital available in a limited partnership structure. We trade on the New York Stock Exchange under the symbol "KMP" and presently conduct our business through four reportable business segments: - Products Pipelines; - Natural Gas Pipelines; - CO(2) Pipelines; and - Terminals. On July 18, 2001, we announced a change in the organization of our business segments, effective in the third quarter of 2001. Prior to the third quarter of 2001, we reported Bulk Terminals and Liquids Terminals as separate business segments. As a result of combining our Bulk Terminals and Liquids Terminals businesses under one management team beginning with the third quarter of 2001, we are reporting the combined Bulk Terminals and Liquids Terminals segments as our Terminals segment. Prior period segment results have been restated to conform to our current organization. For more information on our reportable business segments, see Note 15. MERGER OF KMI On October 7, 1999, K N Energy, Inc., a Kansas corporation that provided integrated energy services including the gathering, processing, transportation and storage of natural gas, the marketing of natural gas and natural gas liquids and the generation of electric power, acquired Kinder Morgan (Delaware), Inc., a Delaware corporation. Kinder Morgan (Delaware), Inc. is the sole stockholder of our general partner, Kinder Morgan G.P., Inc. At the time of the closing of the acquisition, K N Energy, Inc. changed its name to Kinder Morgan, Inc. It is referred to as "KMI" in this report. KMI trades on the New York Stock Exchange under the symbol "KMI" and is one of the largest midstream energy companies in the United States, operating, either for themselves or on behalf of us, more than 30,000 miles of natural gas and products pipelines in 26 states. KMI also has significant retail natural gas distribution and electric generation operations. KMI, through its subsidiary Kinder Morgan (Delaware), Inc., is the sole stockholder of our general partner. At December 31, 2001, KMI and its consolidated subsidiaries owned approximately 18.7% of our outstanding limited partner units. KINDER MORGAN MANAGEMENT, LLC Kinder Morgan Management, LLC, a Delaware limited liability company, was formed on February 14, 2001. It is referred to as "KMR" in this report. Our general partner owns all of KMR's voting securities. 81 In May 2001, KMR issued 2,975,000 of its shares representing limited liability company interests to KMI and 26,775,000 of its shares to the public in an initial public offering. KMR's shares were initially issued at a price of $35.21 per share, less commissions and underwriting expenses, and the shares trade on the New York Stock Exchange under the symbol "KMR". Substantially all of the net proceeds from the offering were used to buy i-units from us. The i-units are a new and separate class of limited partner interests in us and are issued only to KMR. When it purchased i-units from us, KMR became a limited partner in us and, pursuant to a delegation of control agreement, manages and controls our business and affairs. Under the delegation of control agreement, our general partner delegated to KMR, to the fullest extent permitted under Delaware law and our partnership agreement, all of its power and authority to manage and control our business and affairs, except that it cannot take certain specified actions without the approval of our general partner. In accordance with its limited liability company agreement, KMR's activities will be restricted to being a limited partner in, and managing and controlling the business and affairs of the Partnership, including our operating partnerships and our subsidiaries. See Note 11 for more information. TWO-FOR-ONE COMMON UNIT SPLIT On July 18, 2001, KMR, the delegate of our general partner, approved a two-for-one unit split of its outstanding shares and our outstanding common units representing limited partner interests in us. The common unit split entitled our common unitholders to one additional common unit for each common unit held. Our partnership agreement provides that when a split of our common units occurs, a unit split on our Class B units and our i-units will be effected to adjust proportionately the number of our Class B units and i-units. The issuance and mailing of split units occurred on August 31, 2001 to unitholders of record on August 17, 2001. All references to the number of KMR shares, the number of our limited partner units and per unit amounts in our consolidated financial statements and related notes, have been restated to reflect the effect of the split for all periods presented. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES BASIS OF PRESENTATION Our consolidated financial statements include our accounts and those of our majority-owned and controlled subsidiaries and our operating partnerships. All significant intercompany items have been eliminated in consolidation. Certain amounts from prior years have been reclassified to conform to the current presentation. CRITICAL ACCOUNTING POLICIES AND ESTIMATES Our consolidated financial statements were prepared in accordance with accounting principles generally accepted in the United States. Certain amounts included in or affecting our financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time the financial statements are prepared. The preparation of our financial statements in conformity with generally accepted accounting principles requires our management to make estimates and assumptions that affect: - the amounts we report for assets and liabilities; - our disclosure of contingent assets and liabilities at the date of the financial statements; and - the amounts we report for revenues and expenses during the reporting period. Therefore, the reported amounts of our assets and liabilities, revenues and expenses and associated disclosures with respect to contingent assets and obligations are necessarily affected by these estimates. We evaluate these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of 82 operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. In preparing our financial statements and related disclosures, we must use estimates in determining the economic useful lives of our assets, provisions for uncollectible accounts receivable, exposures under contractual indemnifications and various other recorded or disclosed amounts. However, we believe that certain accounting policies are of more significance in our financial statement preparation process than others. With respect to our environmental exposure, we utilize both internal staff and external experts to assist us in identifying environmental issues and in estimating the costs and timing of remediation efforts. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in our income in the period in which they are reasonably determinable. Finally, we are subject to litigation as the result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from judgments or settlements. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. CASH EQUIVALENTS We define cash equivalents as all highly liquid short-term investments with original maturities of three months or less. INVENTORIES Our inventories of products consist of natural gas liquids, refined petroleum products, natural gas, carbon dioxide and coal. We report these assets at the lower of weighted-average cost or market. We report materials and supplies at the lower of cost or market. PROPERTY, PLANT AND EQUIPMENT We state property, plant and equipment at its acquisition cost. We expense costs for maintenance and repairs in the period incurred. The cost of property, plant and equipment sold or retired and the related depreciation are removed from our balance sheet in the period of sale or disposition. We compute depreciation using the straight-line method based on estimated economic lives. Generally, we apply composite depreciation rates to functional groups of property having similar economic characteristics. The rates range from 2.0% to 12.5%, excluding certain short-lived assets such as vehicles. Depreciation, depletion and amortization of the capitalized costs of producing carbon dioxide properties, both tangible and intangible, are provided for on a units-of-production basis. Proved developed reserves are used in computing units-of-production rates for drilling and development costs, and total proved reserves are used for depletion of leasehold costs. The basis for units-of-production rate determination is by field. We charge the original cost of property sold or retired to accumulated depreciation and amortization, net of salvage and cost of removal. We do not include retirement gain or loss in income except in the case of significant retirements or sales. We evaluate impairment of our long-lived assets in accordance with Statement of Financial Accounting Standards No. 121 "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." We review for the impairment of long-lived assets whenever events or changes in circumstances indicate that our carrying amount of an asset may not be recoverable. We would recognize an impairment loss when estimated future cash flows expected to result from our use of the asset and its eventual disposition is less than its carrying amount. In practice, the composite life may not be determined with a high degree of precision, and hence the composite life may not reflect the weighted average of the expected useful lives of the asset's principal components. The Financial Accounting Standards Board has issued a proposed Statement of Position entitled "Accounting for Certain Costs and Activities Related to Property, Plant and Equipment". For purposes of the SOP, a project stage or timeline frame works is used and property, plant and equipment 83 assets are to be accounted for at a component level. Costs incurred for property, plant and equipment are to be classified into four stages: - preliminary; - preacquisition; - acquisition-or-construction; and - in-service. Furthermore, a component is a tangible part or portion of property, plant and equipment that: - can be separately identified as an asset and depreciate or amortized over its own expected use life; and - is expected to provide economic benefit for more than one year. If a component has an expected useful life that differs from the expected useful life of the property, plant and equipment asset to which it relates, the cost should be accounted for separately and depreciated or amortized over its expected useful life. We are currently evaluating the effects of this proposed SOP. On January 1, 2002, we adopted SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." This statement retains the requirements of SFAS 121, mentioned above, however, this statement requires that long-lived assets that are to be disposed of by sale be measured at the lower of book value or fair value less the cost to sell it. Furthermore, the scope of discontinued operations is expanded to include all components of an entity with operations of the entity in a disposal transaction. The adoption of SFAS No. 144 has not had an impact on our business, financial position or results of operations. NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED In July 2001, the Financial Accounting Standards Board issued SFAS No. 143, "Accounting for Asset Retirement Obligations". This statement requires companies to record a liability relating to the retirement and removal of assets used in their business. The liability is discounted to its present value, and the relative asset value is increased by the same amount. Over the life of the asset, the liability will be accreted to its future value and eventually extinguished when the asset is taken out of service. The provisions of this statement are effective for fiscal years beginning after June 15, 2002. We do not expect that SFAS No. 143 will have a material impact on our business, financial position or results of operations. EQUITY METHOD OF ACCOUNTING We account for investments in greater than 20% owned affiliates, which we do not control, by the equity method of accounting. Under this method, an investment is carried at our acquisition cost, plus our equity in undistributed earnings or losses since acquisition. EXCESS OF COST OVER FAIR VALUE As of December 31, 2001, we amortized the excess cost over our underlying net asset book value in equity investments using the straight-line method over the estimated remaining useful lives of the assets in accordance with Accounting Principles Board Opinion No. 16. We amortized this excess for undervalued depreciable assets over a period not to exceed 50 years and for intangible assets over a period not to exceed 40 years. For our investments in consolidated affiliates, we reported amortization of excess cost over fair value of net assets (goodwill) as amortization expense in our accompanying consolidated statements of income. For our investments accounted for under the equity method, we reported amortization of excess cost on investments as amortization of excess cost of equity investments in our accompanying consolidated statements of income. Our total unamortized excess cost over fair value of net assets on investments in consolidated affiliates was approximately $546.7 million as of December 31, 2001 and $158.1 million as of December 31, 2000. These amounts are included within intangibles on our accompanying consolidated 84 balance sheet. Our total unamortized excess cost over underlying book value of net assets on investments accounted for under the equity method was approximately $341.2 million as of December 31, 2001 and $350.2 million as of December 31, 2000. These amounts are included within equity investments on our accompanying balance sheet. We periodically reevaluate the amount at which we carry the excess of cost over fair value of net assets of businesses we acquired, as well as the amortization period for such assets, to determine whether current events or circumstances warrant adjustments to our carrying value and/or revised estimates of useful lives. At December 31, 2001, we believed no such impairment had occurred and no reduction in estimated useful lives was warranted. On January 1, 2002, we adopted SFAS No. 141 "Business Combinations". SFAS No. 141 supercedes Accounting Principles Board Opinion No. 16 and requires that all transactions fitting the description of a business combination be accounted for using the purchase method and prohibits the use of the pooling of interests for all business combinations initiated after June 30, 2001. The Statement also modifies the accounting for the excess of fair value of net assets acquired as well as intangible assets acquired in a business combination. The provisions of this statement apply to all business combinations initiated after June 30, 2001, and all business combinations accounted for by the purchase method that are completed after July 1, 2001. This Statement requires disclosure of the primary reasons for a business combination and the allocation of the purchase price paid to the assets acquired and liabilities assumed by major balance sheet caption. After July 1, 2001, we completed four acquisitions and have initiated or announced four additional acquisitions. Refer to Note 3 for more detail about our acquisitions. SFAS No. 142 "Goodwill and Other Intangible Assets" supercedes Accounting Principles Board Opinion No. 17 and requires that goodwill no longer be amortized but should be tested, at least on an annual basis, for impairment. A benchmark assessment of potential impairment must also be completed within six months of adopting SFAS No. 142. After the first six months, goodwill will be tested for impairment annually. SFAS No. 142 applies to any goodwill acquired in a business combination completed after June 30, 2001. Other intangible assets are to be amortized over their useful life and reviewed for impairment in accordance with the provisions of SFAS No. 121,"Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed Of". An intangible asset with an indefinite useful life can no longer be amortized until its useful life becomes determinable. This Statement requires disclosure of information about goodwill and other intangible assets in the years subsequent to their acquisition that was not previously required. Required disclosures include information about the changes in the carrying amount of goodwill from period to period and the carrying amount of intangible assets by major intangible asset class. After June 30, 2001, we completed two acquisitions, our Boswell and Stolt-Nielsen acquisitions, which resulted in the recognition of goodwill. We adopted SFAS No. 142 on January 1, 2002, and we expect that SFAS No. 142 will not have a material impact on our business, financial position or results of operations. With the adoption of SFAS No. 142, goodwill of approximately $546.7 million is no longer subject to amortization over its estimated useful life. For more information on our acquisitions, see Note 3. REVENUE RECOGNITION We recognize revenues for our pipeline operations based on delivery of actual volume transported or minimum obligations under take-or-pay contracts. We recognize bulk terminal transfer service revenues based on volumes loaded. We recognize liquid terminal tank rental revenue ratably over the contract period. We recognize liquid terminal through-put revenue based on volumes received or volumes delivered depending on the customer contract. Liquid terminal minimum take-or-pay revenue is recognized at the end of the contract year or contract term depending on the terms of the contract. We recognize transmix processing revenues based on volumes processed or sold, and if applicable, when title has passed. We recognize energy-related product sales revenues based on delivered quantities of product. 85 ENVIRONMENTAL MATTERS We expense or capitalize, as appropriate, environmental expenditures that relate to current operations. We expense expenditures that relate to an existing condition caused by past operations, and which do not contribute to current or future revenue generation. We do not discount liabilities to net present value and we record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs. Generally, our making of these accruals coincides with our completion of a feasibility study or our commitment to a formal plan of action. MINORITY INTEREST Minority interest consists of the following: - the 1.0101% general partner interest in our operating partnerships; - the 0.5% special limited partner interest in SFPP, L.P.; - the 33 1/3% interest in Trailblazer Pipeline Company; - the 50% interest in Globalplex Partners, a Louisiana joint venture owned 50% and controlled by Kinder Morgan Bulk Terminals, Inc.; and - the approximate 32% interest in MidTex Gas Storage Company, L.L.P., a Texas limited liability partnership owned approximately 68% and controlled by Kinder Morgan Texas Pipeline L.P. and its consolidated subsidiaries. INCOME TAXES We are not a taxable entity for federal income tax purposes. As such, we do not directly pay federal income tax. Our taxable income or loss, which may vary substantially from the net income or net loss we report in our consolidated statement of income, is includable in the federal income tax returns of each partner. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined as we do not have access to information about each partner's tax attributes in the Partnership. Some of our corporate subsidiaries and corporations in which we have an equity investment do pay federal and state income taxes. Deferred income tax assets and liabilities for certain of our operations conducted through corporations are recognized for temporary differences between the 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 not expected to be realized. COMPREHENSIVE INCOME Statement of Financial Accounting Standards No. 130, "Accounting for Comprehensive Income", requires that enterprises report a total for comprehensive income. For the year ended December 31, 2001, the only difference between net income and comprehensive income for us was the unrealized gain or loss on derivatives utilized for hedging purposes. There was no difference between net income and comprehensive income for each of the years ended December 31, 2000 and 1999. For more information on our hedging activities, see Note 14. NET INCOME PER UNIT We compute Basic Limited Partners' Net Income per Unit by dividing limited partner's interest in net income by the weighted average number of units outstanding during the period. Diluted Limited Partners' Net Income per Unit reflects the potential dilution, by application of the treasury stock method, that could occur if options to issue units were exercised, which would result in the issuance of additional units that would then share in our net income. 86 RISK MANAGEMENT ACTIVITIES We utilize energy derivatives for the purpose of mitigating our risk resulting from fluctuations in the market price of natural gas, natural gas liquids, crude oil and carbon dioxide. In addition, we enter into interest rate swap agreements for the purpose of hedging the interest rate risk associated with our fixed rate debt obligations. Prior to December 31, 2000, our accounting policy for these activities was based on a number of authoritative pronouncements including SFAS No. 80 "Accounting for Futures Contracts". Our new policy, which is based on SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities", became effective on January 1, 2001. See Note 14 for more information on our risk management activities. 3. ACQUISITIONS AND JOINT VENTURES During 1999, 2000 and 2001, we completed the following significant acquisitions. Each of the acquisitions was accounted for under the purchase method and the assets acquired and liabilities assumed were recorded at their estimated fair market values as of the acquisition date. The preliminary amounts assigned to assets and liabilities may be adjusted during a short period following the acquisition. The results of operations from these acquisitions are included in the consolidated financial statements from the date of acquisition. Plantation Pipe Line Company On June 16, 1999, we acquired an additional approximate 27% interest in Plantation Pipe Line Company for approximately $124.2 million. Collectively, we now own approximately 51% of Plantation Pipe Line Company, and ExxonMobil Pipeline Company, an affiliate of ExxonMobil Corporation, owns approximately 49%. Plantation Pipe Line Company owns and operates a 3,100-mile pipeline system throughout the southeastern United States. The pipeline is a common carrier of refined petroleum products to various metropolitan areas, including Atlanta, Georgia; Charlotte, North Carolina; and the Washington, D.C. area. We do not control Plantation Pipe Line Company, and therefore, we account for our investment in Plantation under the equity method of accounting. Our purchase price and the allocation to assets acquired and liabilities assumed was as follows (in thousands): Purchase price: Cash paid, including transaction costs.................... $124,163 -------- Total purchase price...................................... $124,163 ======== Allocation of purchase price: Equity investments........................................ $124,163 -------- $124,163 ========
Transmix Operations On September 10, 1999, we acquired transmix processing plants in Richmond, Virginia and Dorsey Junction, Maryland and other related assets from Primary Corporation. As consideration for the purchase, we paid Primary approximately $16 million in cash and 1,020,294 common units valued at approximately $14.3 million. In addition, we assumed approximately $5.8 million of liabilities. 87 Our purchase price and the allocation to assets acquired and liabilities assumed was as follows (in thousands): Purchase price: Common units issued....................................... $14,348 Cash paid, including transaction costs.................... 15,957 Liabilities assumed....................................... 5,792 ------- Total purchase price...................................... $36,097 ======= Allocation of purchase price: Current assets............................................ $ 4,854 Property, plant and equipment............................. 31,240 Deferred charges and other assets......................... 3 ------- $36,097 =======
Trailblazer Pipeline Company Effective November 30, 1999, we acquired a 33 1/3% interest in Trailblazer Pipeline Company for $37.6 million from Columbia Gulf Transmission Company, an affiliate of Columbia Energy Group. Trailblazer Pipeline Company is an Illinois partnership that owns and operates a 436-mile natural gas pipeline system that traverses from Colorado through southeastern Wyoming to Beatrice, Nebraska. Trailblazer Pipeline Company has a certificated capacity of 492 million cubic feet per day of natural gas. For the month of December 1999, we accounted for our 33 1/3% interest in Trailblazer Pipeline Company under the equity method of accounting. Effective December 31, 1999, following our acquisition of an additional 33 1/3% interest in Trailblazer Pipeline Company, which is discussed below, we included Trailblazer Pipeline Company's activities as part of our consolidated financial statements. On December 12, 2001, we announced that we had signed a definitive agreement to acquire the remaining 33 1/3% ownership interest in Trailblazer Pipeline Company from Enron Trailblazer Pipeline Company for $68 million in cash. Following the acquisition, we will own 100% of Trailblazer Pipeline Company. The transaction, which is expected to close in the first quarter of 2002, is subject to standard closing conditions, as well as approvals by the court overseeing the Enron Corp. bankruptcy and by the Enron board of directors. Through capital contributions it will make to the current expansion project on the Trailblazer pipeline, CIG Trailblazer Gas Company, an affiliate of El Paso Corporation, is expected to become a 7% to 8% equity owner in Trailblazer Pipeline Company in mid-2002. 1999 Kinder Morgan, Inc. Asset Contributions Effective December 31, 1999, we acquired over $935.8 million of assets from KMI. As consideration for the assets, we paid to KMI $330 million in cash and 19,620,000 common units, valued at approximately $406.3 million. In addition, we assumed $40.3 million in debt and approximately $121.6 million in liabilities. We acquired Kinder Morgan Interstate Gas Transmission LLC (formerly K N Interstate Gas Transmission Co.), a 33 1/3% interest in Trailblazer Pipeline Company and a 49% equity interest in Red Cedar Gathering Company. The acquired interest in Trailblazer Pipeline Company, when combined with the interest purchased on November 30, 1999, gave us a 66 2/3% ownership interest. 88 Our purchase price and the allocation to assets acquired and liabilities assumed was as follows (in thousands): Purchase price: Common units issued....................................... $406,262 Cash paid, including transaction costs.................... 367,600 Debt assumed.............................................. 40,300 Liabilities assumed....................................... 121,675 -------- Total purchase price...................................... $935,837 ======== Allocation of purchase price: Current assets............................................ $ 78,335 Property, plant and equipment............................. 741,125 Equity investments........................................ 88,249 Deferred charges and other assets......................... 28,128 -------- $935,837 ========
Milwaukee Bulk Terminals, Inc. and Dakota Bulk Terminal, Inc. Effective January 1, 2000, we acquired all of the shares of the capital stock of Milwaukee Bulk Terminals, Inc. and Dakota Bulk Terminal, Inc. We paid an aggregate consideration of approximately $31.0 million, including 1,148,344 common units, approximately $0.8 million in cash and the assumption of approximately $7.0 million in liabilities. The Milwaukee terminal is located on nine acres of property leased from the Port of Milwaukee. Its major cargoes are coal and bulk de-icing salt. The Dakota terminal, located in St. Paul, Minnesota, primarily handles bulk de-icing salt and grain products. Our purchase price and the allocation to assets acquired and liabilities assumed was as follows (in thousands): Purchase price: Common units issued....................................... $23,319 Cash paid, including transaction costs.................... 757 Liabilities assumed....................................... 6,960 ------- Total purchase price...................................... $31,036 ======= Allocation of purchase price: Current assets............................................ $ 1,764 Property, plant and equipment............................. 15,201 Goodwill.................................................. 14,071 ------- $31,036 =======
Kinder Morgan CO(2) Company, L.P. Effective April 1, 2000, we acquired the remaining 78% limited partner interest and the 2% general partner interest in Shell CO(2) Company, Ltd. from Shell for approximately $212.1 million and the assumption of approximately $37.1 million of liabilities. We renamed the limited partnership Kinder Morgan CO(2) Company, L.P., and going forward from April 1, 2000, we have included its results as part of our consolidated financial statements under our CO(2) Pipelines business segment. As is the case with all of our operating partnerships, we own a 98.9899% limited partner ownership interest in KMCO(2) and our general partner owns a direct 1.0101% general partner ownership interest. 89 Our purchase price and the allocation to assets acquired and liabilities assumed was as follows (in thousands): Purchase price: Cash paid, including transaction costs.................... $212,081 Liabilities assumed....................................... 37,080 -------- Total purchase price...................................... $249,161 ======== Allocation of purchase price: Current assets............................................ $ 51,870 Property, plant and equipment............................. 230,332 Goodwill.................................................. 45,751 Equity investments........................................ (79,693)(a) Deferred charges and other assets......................... 901 -------- $249,161 ========
- --------------- (a) Represents reclassification of our original 20% equity investment in Shell CO(2) Company, L.P. of ($86.7) million and our allocation of purchase price to the equity investment purchased in our acquisition of Shell CO(2) Company, L.P. of $7.0 million. Devon Energy Effective June 1, 2000, we acquired significant interests in carbon dioxide pipeline assets and oil-producing properties from Devon Energy Production Company L.P. for $53.4 million. Included in the acquisition was an approximate 81% equity interest in the Canyon Reef Carriers CO(2) Pipeline, an approximate 71% working interest in the SACROC oil field, and minority interests in the Sharon Ridge unit and the Reinecke unit. All of the assets and properties are located in the Permian Basin of west Texas. Our purchase price and the allocation to assets acquired and liabilities assumed was as follows (in thousands): Purchase price: Cash paid, including transaction costs.................... $53,435 ------- Total purchase price...................................... $53,435 ======= Allocation of purchase price: Property, plant and equipment............................. $53,435 ------- $53,435 =======
Buckeye Refining Company, LLC On October 25, 2000, we acquired Kinder Morgan Transmix, LLC, formerly Buckeye Refining Company, LLC, which owns and operates transmix processing plants in Indianola, Pennsylvania and Wood River, Illinois and other related transmix assets. As consideration for the purchase, we paid Buckeye approximately $37.3 million for property, plant and equipment plus approximately $8.4 million for net working capital and other items. We also assumed approximately $11.5 million of liabilities. 90 Our purchase price and the allocation to assets acquired and liabilities assumed was as follows (in thousands): Purchase price: Cash paid, including transaction costs.................... $45,696 Liabilities assumed....................................... 11,462 ------- Total purchase price...................................... $57,158 ======= Allocation of purchase price: Current assets............................................ $19,862 Property, plant and equipment............................. 37,289 Deferred charges and other assets......................... 7 ------- $57,158 =======
Cochin Pipeline Effective November 3, 2000, we acquired from NOVA Chemicals Corporation an undivided 32.5% interest in the Cochin Pipeline System for approximately $120.5 million. On June 20, 2001, we acquired an additional 2.3% ownership interest in the Cochin Pipeline System from Shell Canada Limited for approximately $8.0 million. We now own approximately 34.8% of the Cochin Pipeline System and the remaining interests are owned by subsidiaries of BP Amoco, Conoco and NOVA Chemicals. We record our proportional share of joint venture revenues and expenses and cost of joint venture assets as part of our Products Pipelines business segment. Our purchase price and the allocation to assets acquired and liabilities assumed was as follows (in thousands): Purchase price: Cash paid, including transaction costs.................... $128,589 -------- Total purchase price...................................... $128,589 ======== Allocation of purchase price: Property, plant and equipment............................. $128,589 -------- $128,589 ========
Effective December 31, 2001, we purchased an additional 10% ownership interest in the Cochin Pipeline System from NOVA Chemicals Corporation for approximately $29 million in cash. We now own approximately 44.8% of the Cochin Pipeline System. We allocated the purchase price to property, plant and equipment in January 2002. Delta Terminal Services LLC Effective December 1, 2000, we acquired all of the shares of the capital stock of Delta Terminal Services LLC, formerly Delta Terminal Services, Inc., for approximately $114.1 million and the assumption of approximately $22.5 million of liabilities. The acquisition includes two liquid bulk storage terminals in New Orleans, Louisiana and Cincinnati, Ohio. 91 Our purchase price and the allocation to assets acquired and liabilities assumed was as follows (in thousands): Purchase price: Cash paid, including transaction costs.................... $114,112 Liabilities assumed....................................... 22,496 -------- Total purchase price...................................... $136,608 ======== Allocation of purchase price: Current assets............................................ $ 1,137 Property, plant and equipment............................. 70,189 Goodwill.................................................. 65,245 Deferred charges and other assets......................... 37 -------- $136,608 ========
MKM Partners, L.P. On December 28, 2000, we announced that KMCO()2 had entered into a definitive agreement to form a joint venture with Marathon Oil Company in the southern Permian Basin of west Texas. The joint venture holds a nearly 13% interest in the SACROC unit and a 49.9% interest in the Yates Field unit. The joint venture was formed on January 1, 2001 and named MKM Partners, L.P. As of December 31, 2000, we paid $34.2 million plus committed 30 billion cubic feet of carbon dioxide for our 7.5% interest in the Yates field unit. In January 2001, we contributed our interest in the Yates field unit together with an approximate 2% interest in the SACROC unit in return for a 15% interest in the joint venture. In January 2001, Marathon Oil Company purchased an approximate 11% interest in the SACROC unit from KMCO(2) for $6.2 million. Marathon Oil Company then contributed this interest in the SACROC unit and its 42.4% interest in the Yates field unit for an 85% interest in the joint venture. Going forward from January 1, 2001, we accounted for this investment under the equity method of accounting. Our purchase price and the allocation to assets acquired and liabilities assumed was as follows (in thousands): Purchase price: Cash paid, including transaction costs.................... $34,163 ------- Total purchase price...................................... $34,163 ======= Allocation of purchase price: Equity investments........................................ $34,163 ------- $34,163 =======
2000 Kinder Morgan, Inc. Asset Contributions Effective December 31, 2000, we acquired $621.7 million of assets from KMI. As consideration for these assets, we paid to KMI $192.7 million in cash and approximately $156.3 million in units, consisting of 1,280,000 common units and 5,313,400 class B units. We also assumed liabilities of approximately $272.7 million. We acquired Kinder Morgan Texas Pipeline, L.P. and MidCon NGL Corp. (both of which were converted to single-member limited liability companies), the Casper and Douglas natural gas gathering and processing systems, a 50% interest in Coyote Gas Treating, LLC and a 25% interest in Thunder Creek Gas Services, LLC. 92 Our purchase price and the allocation to assets acquired and liabilities assumed was as follows (in thousands): Purchase price: Common and Class B units issued........................... $156,305 Cash paid, including transaction costs.................... 192,677 Liabilities assumed....................................... 272,718 -------- Total purchase price...................................... $621,700 ======== Allocation of purchase price: Current assets............................................ $255,320 Property, plant and equipment............................. 137,145 Intangible-leasehold Value................................ 179,390 Equity investments........................................ 45,225 Deferred charges and other assets......................... 4,620 -------- $621,700 ========
Colton Transmix Processing Facility Effective December 31, 2000, we acquired the remaining 50% interest in the Colton Transmix Processing Facility from Duke Energy Merchants for approximately $11.2 million and the assumption of approximately $1.8 million of liabilities. We now own 100% of the Colton facility. Prior to our acquisition of the controlling interest in the Colton facility, we accounted for our ownership interest in the Colton facility under the equity method of accounting. Our purchase price and the allocation to assets acquired and liabilities assumed was as follows (in thousands): Purchase price: Cash paid, including transaction costs.................... $11,233 Liabilities assumed....................................... 1,788 ------- Total purchase price...................................... $13,021 ======= Allocation of purchase price: Current assets............................................ $ 4,465 Property, plant and equipment............................. 8,556 ------- $13,021 =======
GATX Domestic Pipelines and Terminals Businesses During the first quarter of 2001, we acquired GATX Corporation's domestic pipeline and terminal businesses. The acquisition included: - KMLT (formerly GATX Terminals Corporation), effective January 1, 2001; - Central Florida Pipeline LLC (formerly Central Florida Pipeline Company), effective January 1, 2001; and - CALNEV Pipe Line LLC (formerly CALNEV Pipe Line Company), effective March 30, 2001. KMLT's assets includes 12 terminals, located across the United States, which store approximately 35.6 million barrels of refined petroleum products and chemicals. Five of the terminals are included in our Terminals business segment, and the remaining assets are included in our Products Pipelines business segment. Central Florida Pipeline LLC consists of a 195-mile pipeline transporting refined petroleum 93 products from Tampa to the growing Orlando, Florida market. CALNEV Pipe Line LLC consists of a 550-mile refined petroleum products pipeline originating in Colton, California and extending into the growing Las Vegas, Nevada market. The pipeline interconnects in Colton with our Pacific operations' West Line pipeline segment. Our purchase price was approximately $1,231.6 million, consisting of $975.4 million in cash, $134.8 million in assumed debt and $121.4 million in assumed liabilities. Our purchase price and the allocation to assets acquired and liabilities assumed was as follows (in thousands): Purchase price: Cash paid, including transaction costs.................... $ 975,428 Debt assumed.............................................. 134,746 Liabilities assumed....................................... 121,436 ---------- Total purchase price...................................... $1,231,610 ========== Allocation of purchase price: Current assets............................................ $ 32,364 Property, plant and equipment............................. 927,344 Deferred charges and other assets......................... 4,784 Goodwill.................................................. 267,118 ---------- $1,231,610 ==========
Pinney Dock & Transport LLC Effective March 1, 2001, we acquired all of the shares of the capital stock of Pinney Dock & Transport LLC, formerly Pinney Dock & Transport Company, for approximately $52.5 million. The acquisition includes a bulk product terminal located in Ashtabula, Ohio on Lake Erie. The facility handles iron ore, titanium ore, magnetite and other aggregates. Our purchase price consisted of approximately $41.7 million in cash and approximately $10.8 million in assumed liabilities. Our purchase price and the allocation to assets acquired and liabilities assumed was as follows (in thousands): Purchase price: Cash paid, including transaction costs.................... $41,674 Liabilities assumed....................................... 10,875 ------- Total purchase price...................................... $52,549 ======= Allocation of purchase price: Current assets............................................ $ 1,970 Property, plant and equipment............................. 32,467 Deferred charges and other assets......................... 487 Goodwill.................................................. 17,625 ------- $52,549 =======
Vopak Effective July 10, 2001, we acquired certain bulk terminal businesses, which were converted or merged into six single-member limited liability companies, from Koninklijke Vopak N.V. (Royal Vopak) of The Netherlands. Acquired assets included four bulk terminals. Two of the terminals are located in Tampa, Florida and the other two are located in Fernandina Beach, Florida and Chesapeake, Virginia. As a result of the acquisition, our bulk terminals portfolio gained entry into the Florida market. Our purchase 94 price was approximately $44.3 million, consisting of approximately $43.6 million in cash and approximately $0.7 million in assumed liabilities. Our purchase price and the allocation to assets acquired and liabilities assumed was as follows (in thousands): Purchase price: Cash paid, including transaction costs.................... $ 43,622 Liabilities assumed....................................... 700 -------- Total purchase price...................................... $ 44,322 ======== Allocation of purchase price: Property, plant and equipment............................. $ 44,322 ========
Kinder Morgan Texas Pipeline Effective July 18, 2001, we acquired, from an affiliate of Occidental Petroleum Corporation, Kinder Morgan Texas Pipeline, L.P., a partnership that owns a natural gas pipeline system in the State of Texas. Prior to our acquisition of this natural gas pipeline system, these assets were leased and operated by Kinder Morgan Texas Pipeline, L.P., a business unit included in our Natural Gas Pipelines business segment. As a result of this acquisition, we will be released from lease payments of $40 million annually from 2002 through 2005 and $30 million annually from 2006 through 2026. The acquisition included 2,600 miles of pipeline that primarily transports natural gas from south Texas and the Texas Gulf Coast to the greater Houston/Beaumont area. In addition, we signed a five-year agreement to supply approximately 90 billion cubic feet of natural gas to chemical facilities owned by Occidental affiliates in the Houston area. Our purchase price was approximately $326.1 million and the entire cost was allocated to property, plant and equipment. Our purchase price and the allocation to assets acquired and liabilities assumed was as follows (in thousands): Purchase price: Cash paid, including transaction costs.................... $359,059 Release SFAS No. 13 deferred credit previously held....... (32,918) -------- Total purchase price...................................... $326,141 ======== Allocation of purchase price: Property, plant and equipment............................. $326,141 -------- $326,141 ========
Note: These assets were previously leased from a third party under an operating lease. The released Statement of Financial Accounting Standards No. 13, "Accounting for Leases" deferred credit relates to a deferred credit accumulated to spread non-straight line operating lease rentals over the period expected to benefit from those rentals. The Boswell Oil Company Effective August 31, 2001, we acquired from The Boswell Oil Company three terminals located in Cincinnati, Ohio, Pittsburgh, Pennsylvania and Vicksburg, Mississippi. The Cincinnati and Pittsburgh terminals handle both liquids and dry-bulk materials. The Vicksburg terminal is a break-bulk facility, primarily handling paper and steel products. As a result of the acquisition, we continued the expansion of our bulk terminal businesses and entered new markets. Our purchase price was approximately $22.2 million, consisting of approximately $18.1 million in cash, a $3.0 million one-year note payable and approximately $1.1 million in assumed liabilities. 95 Our purchase price and the allocation to assets acquired and liabilities assumed was as follows (in thousands): Purchase price: Cash paid, including transaction costs.................... $18,035 Note payable.............................................. 3,000 Liabilities assumed....................................... 1,115 ------- Total purchase price...................................... $22,150 ======= Allocation of purchase price: Current assets............................................ $ 1,690 Property, plant and equipment............................. 9,867 Intangibles-Contract Rights............................... 4,000 Goodwill.................................................. 6,593 ------- $22,150 =======
The $6.6 million of goodwill was assigned to our Terminals business segment and the entire amount is expected to be deductible for tax purposes. Stolt-Nielsen In November 2001, we acquired certain liquids terminals in Chicago, Illinois and Perth Amboy, New Jersey from Stolthaven Perth Amboy Inc., Stolthaven Chicago Inc. and Stolt-Nielsen Transportation Group, Ltd. As a result of the acquisition, we expanded our liquids terminals businesses into strategic markets. The Perth Amboy facility provides liquid chemical and petroleum storage and handling, as well as dry-bulk handling of salt and aggregates, with liquid capacity exceeding 2.3 million barrels annually. We closed on the Perth Amboy, New Jersey portion of this transaction on November 8, 2001. The Chicago terminal handles a wide variety of liquid chemicals with a working capacity in excess of 0.7 million barrels annually. We closed on the Chicago, Illinois portion of this transaction on November 29, 2001. Our purchase price was approximately $69.8 million, consisting of approximately $44.8 million in cash and $25.0 million in assumed debt. Our purchase price and the allocation to assets acquired and liabilities assumed was as follows (in thousands): Purchase price: Cash paid, including transaction costs.................... $44,838 Debt assumed.............................................. 25,000 ------- Total purchase price...................................... $69,838 ======= Allocation of purchase price: Property, plant and equipment............................. $69,763 Goodwill.................................................. 75 ------- $69,838 =======
The $0.1 million of goodwill was assigned to our Terminals business segment and the entire amount is expected to be deductible for tax purposes. Snyder and Diamond M Plants On November 14, 2001, we announced that KMCO(2) had purchased Mission Resources Corporation's interest in the Snyder Gasoline Plant and Diamond M Gas Plant. In December 2001, KMCO(2) purchased Torch E&P Company's interest in the Snyder Gasoline Plant and entered into a definitive agreement to 96 purchase Torch's interest in the Diamond M Gas Plant. As of December 31, 2001, we have paid approximately $14.7 million for these interests. Final purchase price adjustments should be made in the first quarter of 2002. All of these assets are located in the Permian Basin of west Texas. As a result of the acquisition, we have increased our ownership interests in both plants, each of which process gas produced by the SACROC unit. Our purchase price and the allocation to assets acquired and liabilities assumed was as follows (in thousands): Purchase price: Cash paid, including transaction costs.................... $14,700 ------- Total purchase price...................................... $14,700 ======= Allocation of purchase price: Property, plant and equipment............................. $14,700 ------- $14,700 =======
PRO FORMA INFORMATION The following summarized unaudited Pro Forma Consolidated Income Statement information for the twelve months ended December 31, 2001 and 2000, assumes the 2001 and 2000 acquisitions and joint ventures had occurred as of January 1, 2000. We have prepared these unaudited Pro Forma financial results for comparative purposes only. These unaudited Pro Forma financial results may not be indicative of the results that would have occurred if we had completed the 2001 and 2000 acquisitions and joint ventures as of January 1, 2000 or the results which will be attained in the future. Amounts presented below are in thousands, except for the per unit amounts:
PRO FORMA YEAR ENDED DECEMBER 31, ----------------------- 2001 2000 ---------- ---------- (UNAUDITED) Revenues.................................................... $3,028,543 $3,295,040 Operating Income............................................ 592,668 537,561 Income before extraordinary charge.......................... 501,153 469,609 Net Income.................................................. 484,521 448,201 Basic and diluted Limited Partners' Income per unit before extraordinary charge...................................... $ 1.56 $ 1.38 Basic and diluted Limited Partners' Net Income per unit..... $ 1.56 $ 1.38
ACQUISITIONS SUBSEQUENT TO DECEMBER 31, 2001 On December 12, 2001, we announced that we had signed a definitive agreement to acquire the remaining 33 1/3% ownership interest in Trailblazer Pipeline Company from Enron Trailblazer Pipeline Company for $68 million in cash. Following the acquisition, we will own 100% of Trailblazer Pipeline Company. The transaction, which is expected to close in the first quarter of 2002, is subject to standard closing conditions, as well as approvals by the court overseeing the Enron Corp. bankruptcy and by the Enron board of directors. Through capital contributions it will make to the current expansion project on the Trailblazer pipeline, CIG Trailblazer Gas Company, an affiliate of El Paso Corporation, is expected to become a 7% to 8% equity owner in Trailblazer Pipeline Company in mid-2002. On December 17, 2001, we announced that we had entered into a definitive agreement to purchase Tejas Gas, LLC, a wholly owned subsidiary of InterGen (North America), Inc., for approximately $750 million in cash. Tejas Gas, LLC is a 3,400-mile natural gas intrastate pipeline system that extends from south Texas along the Mexico border and the Texas Gulf Coast to near the Louisiana border and 97 north from near Houston to east Texas. InterGen is a joint venture owned by affiliates of the Royal Dutch/Shell Group of Companies and Bechtel Enterprises Holding, Inc. The transaction is subject to standard closing conditions including receipt of certain regulatory and third party approvals. It is expected to close in the first quarter of 2002. On February 4, 2002, we announced two acquisitions and a major expansion program, both within our Terminals business segment. Together, the investments represent approximately $43 million. The purchases included Pittsburgh, Pennsylvania based Laser Materials Services LLC, operator of 59 transload facilities in 18 states, and a 66 2/3% interest in International Marine Terminals Partnership (IMT), which operates a bulk terminal site in Port Sulphur, Louisiana. The expansion project, which is being carried out at our Carteret, New Jersey, liquids terminal, will add 400,000 barrels of storage (6% of current storage capacity) within 2002. 4. GAIN ON SALE OF EQUITY INTEREST, NET OF SPECIAL CHARGES During the third quarter of 1999, we completed the sale of our partnership interest in the Mont Belvieu fractionation facility for approximately $41.8 million. We recognized a gain of $14.1 million on the sale and included that gain as part of our Natural Gas Pipelines business segment. Offsetting the gain were charges of approximately $3.6 million relating to our write-off of abandoned project costs, primarily within our Products Pipelines business segment, and a charge of $0.4 million relating to prior years' over-billed storage tank lease fees, also within our Products Pipelines business segment. 5. INCOME TAXES Components of the income tax provision applicable to continuing operations for federal and state taxes are as follows (in thousands):
YEAR ENDED DECEMBER 31, -------------------------- 2001 2000 1999 ------- ------- ------ Taxes currently payable: Federal................................................ $ 9,058 $10,612 $8,169 State.................................................. 1,192 1,416 1,002 ------- ------- ------ Total.................................................. 10,250 12,028 9,171 Taxes deferred: Federal................................................ 5,366 1,627 583 State.................................................. 757 279 72 ------- ------- ------ Total.................................................. 6,123 1,906 655 ------- ------- ------ Total tax provision...................................... $16,373 $13,934 $9,826 ======= ======= ====== Effective tax rate....................................... 3.5% 4.8% 5.0%
98 The difference between the statutory federal income tax rate and our effective income tax rate is summarized as follows:
YEAR ENDED DECEMBER 31, ------------------------ 2001 2000 1999 ------ ------ ------ Federal income tax rate..................................... 35.0% 35.0% 35.0% Increase (decrease) as a result of: Partnership earnings not subject to tax................... (35.0)% (35.0)% (35.3)% Corporate subsidiary earnings subject to tax.............. 1.3% 0.6% 1.0% Income tax expense attributable to corporate equity earnings............................................... 1.8% 4.1% 4.4% State taxes............................................... 0.4% 0.1% 0.1% Other..................................................... -- -- (0.2)% ----- ----- ----- Effective tax rate.......................................... 3.5% 4.8% 5.0% ===== ===== =====
Deferred tax assets and liabilities result from the following (in thousands):
DECEMBER 31, ---------------- 2001 2000 ------- ------ Deferred tax assets: State taxes............................................... $ -- $ 184 Book accruals............................................. 404 176 Net Operating Loss/Alternative minimum tax credits........ 1,846 1,376 ------- ------ Total deferred tax assets................................... 2,250 1,736 Deferred tax liabilities: Property, plant and equipment............................. 40,794 4,223 ------- ------ Total deferred tax liabilities.............................. 40,794 4,223 ------- ------ Net deferred tax liabilities................................ $38,544 $2,487 ======= ======
We had available, at December 31, 2001, approximately $1.1 million of alternative minimum tax credit carryforwards, which are available indefinitely, and $1.9 million of net operating loss carryforwards, which will expire between the years 2002 and 2018. We believe it is more likely than not that the net operating loss carryforwards will be utilized prior to their expiration; therefore, no valuation allowance is necessary. 99 6. PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment consists of the following (in thousands):
DECEMBER 31, ----------------------- 2001 2000 ---------- ---------- Natural gas, liquids and carbon dioxide pipelines........... $2,246,930 $1,732,607 Natural gas, liquids and carbon dioxide pipeline station equip.................................................. 2,168,924 1,072,185 Coal and bulk tonnage transfer, storage and services...... 214,040 191,313 Natural gas and transmix processing....................... 97,155 95,624 Land and land right-of-way................................ 283,878 196,109 Construction work in process.............................. 156,452 90,067 Other..................................................... 217,245 117,981 ---------- ---------- Total cost................................................ 5,384,624 3,495,886 Accumulated depreciation and depletion.................... (302,012) (189,581) ---------- ---------- $5,082,612 $3,306,305 ========== ==========
Depreciation and depletion expense charged against property, plant and equipment consists of the following (in thousands):
2001 2000 1999 -------- ------- ------- Depreciation and depletion expense..................... $126,641 $79,740 $44,553
7. INVESTMENTS Our significant equity investments at December 31, 2001 consisted of: - Plantation Pipe Line Company (51%); - Red Cedar Gathering Company (49%); - Thunder Creek Gas Services, LLC (25%); - Coyote Gas Treating, LLC (Coyote Gulch) (50%); - Cortez Pipeline Company (50%) - MKM Partners, L.P. (15%); and - Heartland Pipeline Company (50%). On June 16, 1999, we acquired an additional approximate 27% interest in Plantation Pipe Line Company. As a result, we now own approximately 51% of Plantation Pipe Line Company, and an affiliate of ExxonMobil owns the remaining approximate 49%. Each investor has an equal number of directors on Plantation's board of directors, and board approval is required for certain corporate actions that are considered participating rights. Therefore, we do not control Plantation Pipe Line Company, and we account for our investment under the equity method of accounting. On April 1, 2000, we acquired the remaining 80% ownership interest in Shell CO(2) Company, Ltd. and renamed the entity Kinder Morgan CO(2) Company, L.P. (KMCO(2)). On December 31, 2000, we acquired the remaining 50% ownership interest in the Colton Transmix Processing Facility. Due to these acquisitions, we no longer report these two investments under the equity method of accounting. In addition, we had an equity investment in Trailblazer Pipeline Company (33 1/3%) for one month of 1999 and had an equity interest in Mont Belvieu Associates through two quarters of 1999. We sold our equity interest in Mont Belvieu Associates in the third quarter of 1999 and acquired an additional 33 1/3% interest in Trailblazer Pipeline Company effective December 31, 1999. 100 On December 28, 2000, we announced that KMCO(2) had entered into a definitive agreement to form a joint venture with Marathon Oil Company in the southern Permian Basin of west Texas. The joint venture consists of a nearly 13% interest in the SACROC unit and a 49.9% interest in the Yates oil field. The joint venture was formed on January 1, 2001 and named MKM Partners, L.P. As of December 31, 2000, we paid $34.2 million plus committed 30 billion cubic feet of carbon dioxide for our 7.5% interest in the Yates oil field. In January 2001, we contributed our interest in the Yates oil field together with an approximate 2% interest in the SACROC unit in return for a 15% interest in the joint venture. In January 2001, Marathon Oil Company purchased an approximate 11% interest in the SACROC unit from KMCO(2) for $6.2 million. Marathon Oil Company then contributed this interest in the SACROC unit and its 42.4% interest in the Yates oil field for an 85% interest in the joint venture. Going forward from January 1, 2001, we have accounted for this investment under the equity method. We acquired our investment in Cortez Pipeline Company as part of our KMCO(2) acquisition and we acquired our investments in Coyote Gas Treating, LLC and Thunder Creek Gas Services, LLC from KMI on December 31, 2000. Please refer to Notes 3 and 4 for more information. Our total equity investments consisted of the following (in thousands):
DECEMBER 31, ------------------- 2001 2000 -------- -------- Plantation Pipe Line Company................................ $217,473 $223,627 Red Cedar Gathering Company................................. 99,484 96,388 MKM Partners, L.P........................................... 58,633 -- Thunder Creek Gas Services, LLC............................. 30,159 27,625 Coyote Gas Treating, LLC.................................... 16,323 17,000 Cortez Pipeline Company..................................... 9,599 9,559 Heartland Pipeline Company.................................. 5,608 6,025 All Others.................................................. 3,239 2,658 -------- -------- Total Equity Investments.................................... $440,518 $382,882 Investment in oil and gas assets to be contributed to joint venture................................................... -- 34,163 -------- -------- Total Investments........................................... $440,518 $417,045 ======== ========
101 Our earnings from equity investments were as follows (in thousands):
YEAR ENDED DECEMBER 31, --------------------------- 2001 2000 1999 ------- ------- ------- Plantation Pipe Line Company............................ $25,314 $31,509 $22,510 Cortez Pipeline Company................................. 25,694 17,219 -- Red Cedar Gathering Company............................. 18,814 16,110 -- MKM Partners, L.P....................................... 8,304 -- -- Shell CO(2) Company, Ltd................................ -- 3,625 14,500 Colton Transmix Processing Facility..................... -- 1,815 1,531 Heartland Pipeline Company.............................. 882 1,581 1,571 Coyote Gas Treating, LLC................................ 2,115 -- -- Thunder Creek Gas Services, LLC......................... 1,629 -- -- Mont Belvieu Associates................................. -- -- 2,500 Trailblazer Pipeline Company............................ -- (24) 284 All Others.............................................. 2,082 (232) 22 ------- ------- ------- Total................................................... $84,834 $71,603 $42,918 ======= ======= ======= Amortization of excess costs............................ $(9,011) $(8,195) $(4,254) ======= ======= =======
Summarized combined unaudited financial information for our significant equity investments is reported below (in thousands; amounts represent 100% of investee financial information, not our pro rata portion):
YEAR ENDED DECEMBER 31, ------------------------------ INCOME STATEMENT 2001 2000 1999 - ---------------- -------- -------- -------- Revenues............................................. $449,502 $399,335 $344,017 Costs and expenses................................... 280,364 276,000 244,515 Earnings before extraordinary items.................. 169,138 123,335 99,502 Net income........................................... 169,138 123,335 99,502
DECEMBER 31, --------------------- BALANCE SHEET 2001 2000 - ------------- ---------- -------- Current assets.............................................. $ 101,015 $117,050 Non-current assets.......................................... 1,079,054 665,435 Current liabilities......................................... 75,722 92,027 Non-current liabilities..................................... 559,454 576,278 Partners'/owners' equity.................................... 544,893 114,180
8. INTANGIBLES Our intangible assets include acquired goodwill, lease value, contracts and agreements. We acquired our 2000 intangible lease value as part of our acquisition of Kinder Morgan Texas Pipeline, L.P. on December 31, 2000 from KMI. In our July 2001 acquisition of K M Texas Pipeline, L.P., we acquired the leased pipeline asset from Occidental Petroleum and our operating lease was terminated. We allocated the balance of the KMTP intangible lease value between goodwill and property. All of our intangible assets having definite lives are being amortized on a straight-line basis over their estimated useful lives. As of December 31, 2001, goodwill was being amortized over a period of 40 years. 102 Intangible assets consisted of the following (in thousands):
DECEMBER 31, ------------------- 2001 2000 -------- -------- Goodwill.................................................... $566,633 $162,271 Accumulated amortization.................................... (19,899) (4,201) -------- -------- 546,734 158,070 Lease value................................................. 6,124 185,982 Contracts and other......................................... 10,739 1,861 -------- -------- Accumulated amortization.................................... (200) (608) -------- -------- Other intangibles, net...................................... 16,663 187,235 -------- -------- Total intangibles, net...................................... $563,397 $345,305 ======== ========
Amortization expense consists of the following (in thousands):
2001 2000 1999 ------- ------ ------ Amortization expense...................................... $15,436 $2,890 $1,916
9. DEBT Our debt and credit facilities as of December 31, 2001, consist primarily of: - $200 million of Floating Rate Senior Notes due March 22, 2002; - an $85.2 million unsecured two-year credit facility due June 29, 2003 (our subsidiary Trailblazer Pipeline Company is the obligor on the facility); - a $750 million unsecured 364-day credit facility due October 23, 2002; - a $300 million unsecured five-year credit facility due September 29, 2004; - $200 million of 8.00% Senior Notes due March 15, 2005; - $250 million of 6.30% Senior Notes due February 1, 2009; - $250 million of 7.50% Senior Notes due November 1, 2010; - $700 million of 6.75% Senior Notes due March 15, 2011; - $25 million of New Jersey Economic Development Revenue Refunding Bonds due January 15, 2018 (our subsidiary, Kinder Morgan Liquids Terminals LLC, is the obligor on the bonds); - $23.7 million of tax-exempt bonds due 2024 (our subsidiary, Kinder Morgan Operating L.P. "B", is the obligor on the bonds); - $300 million of 7.40% Senior Notes due March 15, 2031; - $79.6 million of Series F First Mortgage Notes due December 2004 (our subsidiary, SFPP, L.P. is the obligor on the notes); - $87.9 million of Industrial Revenue Bonds with final maturities ranging from September 2019 to December 2024 (our subsidiary, Kinder Morgan Liquids Terminals LLC, is the obligor on the bonds); - $35 million of 7.84% Senior Notes, with a final maturity of July 2008 (our subsidiary, Central Florida Pipe Line LLC, is the obligor on the notes); and - a $900 million short-term commercial paper program. 103 None of our debt or credit facilities are subject to payment acceleration as a result of any change to our credit ratings. Our short-term debt at December 31, 2001, consisted of: - $590.5 million of commercial paper borrowings; - $200.0 million under our Floating Rate Senior Notes due March 22, 2002; - $42.5 million under the SFPP 10.7% First Mortgage Notes; and - $3.5 million in other borrowings. Based on prior successful short-term debt refinancings and current market conditions, we intend and have the ability to refinance $276.3 million of our short-term debt on a long-term basis under our unsecured five-year credit facility, and we do not anticipate any liquidity problems. Credit Facilities On September 29, 1999, our $325 million credit facility was replaced with a $300 million unsecured five-year credit facility expiring in September 2004 and a $300 million unsecured 364-day credit facility. We recorded an extraordinary charge of $2.6 million related to the retirement of our $325 million credit facility. Our 364-day credit facility expired on September 29, 2000 and was extended until October 25, 2000. On October 25, 2000, the facility was replaced with a new $600 million unsecured 364-day credit facility expiring on October 25, 2001. The outstanding balance under our 364-day credit facility was $582 million at December 31, 2000. During the first quarter of 2001, we obtained a third unsecured credit facility, in the amount of $1.1 billion, expiring on December 31, 2001. The terms of this credit facility were substantially similar to the terms of the other two facilities. Upon issuance of additional senior notes on March 12, 2001, this short-term credit facility was reduced to $500 million. During the second quarter of 2001, we terminated our $500 million credit facility, which was scheduled to expire on December 31, 2001. On October 25, 2001, our 364-day credit facility expired and we obtained a new $750 million unsecured 364-day credit facility. The terms of this credit facility are substantially similar to the terms of the expired facility. No borrowings were outstanding under our 364-day credit facility at December 31, 2001. On August 11, 2000, we refinanced the outstanding balance under SFPP, L.P.'s secured credit facility with a $175.0 million borrowing under our five-year credit facility. The outstanding balance under our five-year credit facility was $207.6 million at December 31, 2000. No borrowings were outstanding under our five-year credit facility at December 31, 2001. Our two credit facilities are with a syndicate of financial institutions. First Union National Bank is the administrative agent under the agreements. Interest on our credit facilities accrues at our option at a floating rate equal to either: - First Union National Bank's base rate (but not less than the Federal Funds Rate, plus 0.5%); or - LIBOR, plus a margin, which varies depending upon the credit rating of our long-term senior unsecured debt. Our five-year credit facility also permits us to obtain bids for fixed rate loans from members of the lending syndicate. The weighted average interest rate on our borrowings under our credit facilities was 6.1531% during 2001 and 6.8987% during 2000. The amount available for borrowing under our credit facilities are reduced by a $23.7 million letter of credit that supports Kinder Morgan Operating L.P. "B"'s tax-exempt bonds and our outstanding commercial paper borrowings. We intend to secure promptly after the date of this document an additional $750 million credit facility to back-up an increase in our commercial paper program to $1.8 billion to fund the Tejas acquisition. We expect to terminate this facility once we have issued debt and/or equity to permanently finance the 104 acquisition. At that time, our commercial paper capacity will be reduced to $1.05 billion. We expect to increase the debt to EBITDA ratio allowed by our credit facilities to 4.25 to 1 through June 30, 2002. Senior Notes Under an indenture dated March 22, 2000, we completed a private placement of $200 million of floating rate notes due March 22, 2002 and $200 million of 8.0% notes due March 15, 2005. On May 31, 2000, we exchanged these notes with substantially identical notes that were registered under the Securities Act of 1933. The proceeds from this offering, net of underwriting discounts, were $397.9 million. The proceeds from the issuance of these notes were used to reduce our outstanding commercial paper. At December 31, 2001, the interest rate on our floating rate notes was 3.1025%. On November 8, 2000, we closed a private placement of $250 million of 7.5% notes due November 1, 2010. On March 28, 2001, we exchanged these notes with substantially identical notes that were registered under the Securities Act of 1933. The proceeds from this offering, net of underwriting discounts, were $246.8 million. These proceeds were used to reduce our outstanding commercial paper. On March 12, 2001, we closed a public offering of $1.0 billion in principal amount of senior notes, consisting of $700 million in principal amount of 6.75% senior notes due March 15, 2011 at a price to the public of 99.705% per note, and $300 million in principal amount of 7.40% senior notes due March 15, 2031 at a price to the public of 99.748% per note. In the offering, we received proceeds, net of underwriting discounts and commissions, of approximately $693.4 million for the 6.75% notes and $296.6 million for the 7.40% notes. We used the proceeds to pay for our acquisition of Pinney Dock & Transport LLC (see Note 3) and to reduce our outstanding balance on our credit facilities and commercial paper borrowings. At December 31, 2001, our unamortized liability balance due on the various series of our senior notes were as follows (in millions): 6.30% senior notes due February 1, 2009..................... $ 249.4 8.0% senior notes due March 15, 2005........................ 199.7 Floating rate notes due March 22, 2002...................... 200.0 7.5% senior notes due November 1, 2010...................... 248.6 6.75% senior notes due March 15, 2011....................... 698.1 7.40% senior notes due March 15, 2031....................... 299.3 -------- Total..................................................... $1,895.1 ========
In addition, in order to maintain a cost effective capital structure, it is our policy to borrow funds utilizing a mix of fixed rate debt and variable rate debt. In the third quarter of 2001, we elected to adjust our mix to be closer to our target ratio of 50% fixed rate debt and 50% variable rate debt. Accordingly, in August 2001, we entered into interest rate swap agreements with a notional principal amount of $750 million for the purpose of hedging the interest rate risk associated with our fixed rate debt obligations. These agreements effectively convert the interest expense associated with the following series of our senior notes from fixed rates to variable rates based on an interest rate of LIBOR plus a spread: - 8.0% senior notes due March 15, 2005; - 6.30% senior notes due February 1, 2009; and - 7.40% senior notes due March 15, 2031. The swap agreements for our 8.0% senior notes and 6.30% senior notes have terms that correspond to the maturity dates of such series. The swap agreement for our 7.40% senior notes contains mutual cash-out agreements at the then-current economic value every seven years. 105 Commercial Paper Program In December 1999, we established a commercial paper program providing for the issuance of up to $200 million of commercial paper, subsequently increased to $300 million in January 2000. On October 25, 2000, in conjunction with our new 364-day credit facility, we also increased our commercial paper program to provide for the issuance of up to $600 million of commercial paper. During the first quarter of 2001, we increased our commercial paper program to provide for the issuance of an additional $1.1 billion of commercial paper, and during the second quarter of 2001, we decreased our commercial paper program back to $600 million. On October 17, 2001, we increased our commercial paper program to $900 million. Borrowings under our commercial paper program reduce the borrowings allowed under our credit facilities. As of December 31, 2001, we had $590.5 million of commercial paper outstanding with an interest rate of 2.6585%. The borrowings under our commercial paper program were used to finance acquisitions made during 2001. We intend to secure promptly after the date of this document an additional $750 million credit facility to back-up an increase in our commercial paper program to $1.8 billion to fund the Tejas acquisition. We expect to terminate this facility once we have issued debt and/or equity to permanently finance the acquisition. At that time, our commercial paper capacity will be reduced to $1.05 billion. We expect to increase the debt to EBITDA ratio allowed by our credit facilities to 4.25 to 1 through June 30, 2002. SFPP, L.P. Debt At December 31, 2001, the outstanding balance under SFPP, L.P.'s Series F notes was $79.6 million. The annual interest rate on the Series F notes is 10.70%, the maturity is December 2004, and interest is payable semiannually in June and December. We expect to repay the Series F notes prior to maturity as a result of SFPP , L.P. taking advantage of certain optional prepayment provisions without penalty in 1999 and 2000. Remaining annual installments are $42.6 million in 2002 and $37.0 million in 2003. Additionally, the Series F notes may be prepaid in full or in part at a price equal to par plus, in certain circumstances, a premium. We agreed as part of the acquisition of SFPP, L.P.'s operations (which constitute a significant portion of our Pacific operations) not to take actions with respect to $190 million of SFPP, L.P.'s debt that would cause adverse tax consequences for the prior general partner of SFPP, L.P. The Series F notes are secured by mortgages on substantially all of the properties of SFPP, L.P. The Series F notes contain certain covenants limiting the amount of additional debt or equity that may be issued by SFPP, L.P. and limiting the amount of cash distributions, investments, and property dispositions by SFPP, L.P. We do not believe that these restrictions will materially affect distributions to our partners. Kinder Morgan Liquids Terminals LLC Debt Effective January 1, 2001, we acquired Kinder Morgan Liquids Terminals LLC (see Note 3). As part of our purchase price, we assumed debt of $87.9 million, consisting of five series of Industrial Revenue Bonds. The Bonds consist of the following: - $4.1 million of 7.30% New Jersey Industrial Revenue Bonds due September 1, 2019; - $59.5 million of 6.95% Texas Industrial Revenue Bonds due February 1, 2022; - $7.4 million of 6.65% New Jersey Industrial Revenue Bonds due September 1, 2022; - $13.3 million of 7.00% Louisiana Industrial Revenue Bonds due March 1, 2023; and - $3.6 million of 6.625% Texas Industrial Revenue Bonds due February 1, 2024. In November 2001, we acquired a liquids terminal in Perth Amboy, New Jersey from Stolthaven Perth Amboy Inc. and Stolt-Nielsen Transportation Group, Ltd. As part of our purchase price, we assumed $25.0 million of Economic Development Revenue Refunding Bonds issued by the New Jersey Economic Development Authority. The bonds have a maturity date of January 15, 2018. Interest on these bonds is computed on the basis of a year of 365 or 366 days, as applicable, for the actual number of days elapsed during Commercial Paper, Daily or Weekly Rate Periods and on the basis of a 360-day year 106 consisting of twelve 30-day months during a Term Rate Period. As of December 31, 2001, the interest rate was 1.391%. We have an outstanding letter of credit issued by Citibank in the amount of $25.3 million that backs-up the $25.0 million principal amount of the bonds and $0.3 million of interest on the bonds for up to 42 days computed at 12% on a per annum basis on the principal thereof. Central Florida Pipeline LLC Debt Effective January 1, 2001, we acquired Central Florida Pipeline LLC (see Note 3). As part of our purchase price, we assumed an aggregate principal amount of $40 million of Senior Notes originally issued to a syndicate of eight insurance companies. The Senior Notes have a fixed annual interest rate of 7.84% and will be repaid in annual installments of $5 million beginning July 23, 2001. The final payment is due July 23, 2008. Interest is payable semiannually on January 1 and July 23 of each year. At December 31, 2001, Central Florida's outstanding balance under the Senior Notes was $35.0 million. CALNEV Pipe Line LLC Debt Effective March 30, 2001, we acquired CALNEV Pipe Line LLC (see Note 3). As part of our purchase price, we assumed an aggregate principal amount of $6.8 million of Senior Notes originally issued to a syndicate of five insurance companies. The Senior Notes had a fixed annual interest rate of 10.07%. In June 2001, we prepaid the balance outstanding under the Senior Notes, plus $0.9 million for interest and a make-whole premium, from cash on hand. Trailblazer Pipeline Company Debt At December 31, 2000, Trailblazer Pipeline Company had a $10 million borrowing under an intercompany account payable in favor of KMI. In January 2001, Trailblazer Pipeline Company entered into a 364-day revolving credit agreement with Credit Lyonnais New York Branch, providing for loans up to $10 million. The borrowings were used to pay the account payable to KMI. The agreement was to expire on December 27, 2001. The agreement provided for an interest rate of LIBOR plus 0.875%. Pursuant to the terms of the revolving credit agreement with Credit Lyonnais New York Branch, Trailblazer Pipeline Company partnership distributions were restricted by certain financial covenants. On June 26, 2001, Trailblazer Pipeline Company prepaid the balance outstanding under its Senior Secured Notes using a new two-year unsecured revolving credit facility with a bank syndication. The new facility, as amended August 24, 2001, provides for loans of up to $85.2 million and expires June 29, 2003. The agreement provides for an interest rate of LIBOR plus a margin as determined by certain financial ratios. On June 29, 2001, Trailblazer Pipeline Company paid the $10 million outstanding balance under its 364-day revolving credit agreement and terminated that agreement. At December 31, 2001, the outstanding balance under Trailblazer Pipeline Company's two-year revolving credit facility was $55.0 million, with a weighted average interest rate of 2.875%, which reflects three-month LIBOR plus a margin of 0.875%. Pursuant to the terms of the revolving credit facility, Trailblazer Pipeline Company partnership distributions are restricted by certain financial covenants. We do not believe that these restrictions will materially affect distributions to our partners. On September 23, 1992, pursuant to the terms of a Note Purchase Agreement, Trailblazer Pipeline Company issued and sold an aggregate principal amount of $101 million of Senior Secured Notes to a syndicate of fifteen insurance companies. The Senior Secured Notes had a fixed annual interest rate of 8.03% and the $20.2 million balance as of December 31, 2000 was to be repaid in semiannual installments of $5.05 million from March 1, 2001 through September 1, 2002, the final maturity date. Interest was payable semiannually in March and September. Trailblazer Pipeline Company provided collateral for the notes principally by an assignment of certain Trailblazer Pipeline Company transportation contracts, and pursuant to the terms of this Note Purchase Agreement, Trailblazer Pipeline Company's partnership distributions were restricted by certain financial covenants. Effective April 29, 1997, Trailblazer Pipeline Company amended the Note Purchase Agreement. This amendment allowed Trailblazer Pipeline Company to include several additional transportation contracts as collateral for the notes, added a 107 limitation on the amount of additional money that Trailblazer Pipeline Company could borrow and relieved Trailblazer Pipeline Company from its security deposit obligation. On June 26, 2001, Trailblazer Pipeline Company prepaid the $15.2 million balance outstanding under the Senior Secured Notes, plus $0.8 million for interest and a make-whole premium, using its new two-year unsecured revolving credit facility. Kinder Morgan Operating L.P. "B" Debt The $23.7 million principal amount of tax-exempt bonds due 2024 were issued by the Jackson-Union Counties Regional Port District. These bonds bear interest at a weekly floating market rate. During 2001, the weighted-average interest rate on these bonds was 2.71% per annum, and at December 31, 2001 the interest rate was 1.70%. We have an outstanding letter of credit issued under our credit facilities that backs-up our tax-exempt bonds. The letter of credit reduces the amount available for borrowing under our credit facilities. Cortez Pipeline Pursuant to a certain Throughput and Deficiency Agreement, the owners of Cortez Pipeline Company are required to contribute capital to Cortez in the event of a cash deficiency. The agreement contractually supports the financings of Cortez Capital Corporation, a wholly-owned subsidiary of Cortez Pipeline Company, by obligating the owners of Cortez Pipeline to fund cash deficiencies at Cortez Pipeline, including cash deficiencies relating to the repayment of principal and interest. Their respective parent or other companies further severally guarantee the obligations of the Cortez Pipeline owners under this agreement. Due to our indirect ownership of Cortez through KMCO(2), we severally guarantee 50% of the debt of Cortez Capital Corporation. Shell Oil Company shares our guaranty obligations jointly and severally through December 31, 2006 for Cortez's debt programs in place as of April 1, 2000. At December 31, 2001, the debt facilities of Cortez Capital Corporation consisted of: - a $127 million uncommitted 364-day revolving credit facility; - a $48 million committed 364-day revolving credit facility; - $136.4 million of Series D notes; and - a $175 million short-term commercial paper program. At December 31, 2001, Cortez had $146 million of commercial paper outstanding with an interest rate of 1.87%, the average interest rate on the series D notes was 6.8378% and there were no borrowings under the credit facilities. MATURITIES OF DEBT The scheduled maturities of our outstanding debt at December 31, 2001, are summarized as follows (in thousands): 2002........................................................ $ 836,519 2003........................................................ 92,073 2004........................................................ 17 2005........................................................ 199,753 2006........................................................ 19 Thereafter.................................................. 1,663,412 ---------- Total....................................................... $2,791,793 ==========
108 Of the $836.5 million scheduled to mature in 2002, we intend and have the ability to refinance $276.3 million on a long-term basis under our existing credit facilities. We expect to pay the remaining portion of our short-term debt within the next year. FAIR VALUE OF FINANCIAL INSTRUMENTS The estimated fair value of our long-term debt based upon prevailing interest rates available to us at December 31, 2001 and December 31, 2000 is disclosed below. Fair value as used in SFAS No. 107 "Disclosures About Fair Value of Financial Instruments" represents the amount at which an instrument could be exchanged in a current transaction between willing parties.
DECEMBER 31, 2001 DECEMBER 31, 2000 ----------------------- ----------------------- CARRYING ESTIMATED CARRYING ESTIMATED VALUE FAIR VALUE VALUE FAIR VALUE ---------- ---------- ---------- ---------- (IN THOUSANDS) Total Debt................................... $2,791,793 $3,089,089 $1,904,402 $2,011,818
10. PENSIONS AND OTHER POST-RETIREMENT BENEFITS In connection with our acquisition of SFPP and Kinder Morgan Bulk Terminals in 1998, we acquired certain liabilities for pension and post-retirement benefits. We provide medical and life insurance benefits to current employees, their covered dependents and beneficiaries of SFPP and Kinder Morgan Bulk Terminals. We also provide the same benefits to former salaried employees of SFPP. Additionally, we will continue to fund these costs for those employees currently in the plan during their retirement years. The noncontributory defined benefit pension plan covering the former employees of Kinder Morgan Bulk Terminals is the Employee Benefit Plan for Employees of Hall-Buck Marine Services Company and the benefits under this plan were based primarily upon years of service and final average pensionable earnings. Benefit accruals were frozen as of December 31, 1998 for the Hall-Buck plan. Effective December 31, 2000, the Hall-Buck plan, along with the K N Energy, Inc. Retirement Plan for Bargaining Employees, was merged into the K N Energy, Inc. Retirement Plan for Non-Bargaining employees, with the Non-Bargaining Plan being the surviving plan. The merged plan was renamed the Kinder Morgan, Inc. Retirement Plan. SFPP's post-retirement benefit plan is frozen and no additional participants may join the plan. As a result of these events, we recognized a curtailment gain related to the SFPP's plan of $3.9 million in 1999. 109 Net periodic benefit costs and weighted-average assumptions for these plans include the following components (in thousands):
2001 2000 1999 -------------------------- -------------------------- --------------- OTHER OTHER OTHER POST-RETIREMENT PENSION POST-RETIREMENT PENSION POST-RETIREMENT BENEFITS BENEFITS BENEFITS BENEFITS BENEFITS --------------- -------- --------------- -------- --------------- Net periodic benefit cost Service cost............... $ 120 $ -- $ 46 $ -- $ 80 Interest cost.............. 804 145 755 141 696 Expected return on plan assets................... -- (170) -- (150) -- Amortization of prior service cost............. (545) -- (493) -- (493) Actuarial gain............. (27) -- (290) -- (340) ----- ----- ----- ----- ------- Net periodic benefit cost..................... $ 352 $ (25) $ 18 $ (9) $ (57) ===== ===== ===== ===== ======= Additional amounts recognized Curtailment (gain) loss.............. $ -- $ -- $ -- $ -- $(3,859) Weighted-average assumptions as of December 31: Discount rate.............. 7.00% 7.5% 7.75% 7.0% 7.0% Expected return on plan assets................... -- 8.5% -- 8.5% -- Rate of compensation increase................. -- -- -- -- --
110 Information concerning benefit obligations, plan assets, funded status and recorded values for these plans follows (in thousands):
2001 2000 -------------------------- --------------- OTHER OTHER POST-RETIREMENT PENSION POST-RETIREMENT BENEFITS BENEFITS BENEFITS --------------- -------- --------------- Change in benefit obligation Benefit obligation at Jan. 1..................... $ 10,897 $1,737 $ 9,564 Service cost..................................... 120 -- 46 Interest cost.................................... 804 145 755 Amendments....................................... -- -- (371) Administrative expenses.......................... -- (9) -- Actuarial loss................................... 2,350 299 1,339 Benefits paid from plan assets................... (803) (189) (435) -------- ------ -------- Benefit obligation at Dec. 31.................... $ 13,368 $1,983 $ 10,898 ======== ====== ======== Change in plan assets Fair value of plan assets at Jan. 1.............. $ -- $2,060 $ -- Actual return on plan assets..................... -- (138) -- Employer contributions........................... 803 92 435 Administrative expenses.......................... -- (9) -- Benefits paid from plan assets................... (803) (189) (435) -------- ------ -------- Fair value of plan assets at Dec. 31............. $ -- $1,816 $ -- ======== ====== ======== Funded status.................................... $(13,368) $ (167) $(10,898) Unrecognized net actuarial (gain) loss........... 993 360 (1,383) Unrecognized prior service (benefit)............. (1,111) -- (1,656) -------- ------ -------- Prepaid (accrued) benefit cost................... $(13,486) $ 193 $(13,937) ======== ====== ========
In 2001, SFPP modified benefits associated with its post-retirement benefit plan. This plan amendment resulted in a $2.5 million increase in its benefit obligation for 2001. The unrecognized prior service credit is amortized on a straight-line basis over the remaining expected service to retirement (3.5 years). For measurement purposes, a 12% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2001. The rate was assumed to decrease gradually to 5% by 2008 and remain at that level thereafter. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A 1% change in assumed health care cost trend rates would have the following effects:
1-PERCENTAGE 1-PERCENTAGE POINT INCREASE POINT DECREASE -------------- -------------- Effect on total of service and interest cost components... $ 85 $ (72) Effect on postretirement benefit obligation............... $1,081 $(926)
Multiemployer Plans and Other Benefits. With our acquisition of Kinder Morgan Bulk Terminals, effective July 1, 1998, we participate in multi-employer pension plans for the benefit of its employees who are union members. We do not administer these plans and contribute to them in accordance with the provisions of negotiated labor contracts. Other benefits include a self-insured health and welfare insurance plan and an employee health plan where employees may contribute for their dependents' health care costs. Amounts charged to expense for these plans were $0.6 million for the year ended 2001 and $0.2 million for the year ended 2000. The amount charged from the period of acquisition through December 31, 1998 was $0.5 million. 111 We assumed River Consulting, Inc.'s (a consolidated affiliate of Kinder Morgan Bulk Terminals) savings plan under Section 401(k) of the Internal Revenue Code. This savings plan allowed eligible employees to contribute up to 10% of their compensation on a pre-tax basis, with us matching 2.5% of the first 5% of the employees' wage. Matching contributions are vested at the time of eligibility, which is one year after employment. Effective January 1, 1999, we merged this savings plan into the retirement savings plan of our general partner (see next paragraph). Effective July 1, 1997, our general partner established the Kinder Morgan Retirement Savings Plan, a defined contribution 401(k) plan. This plan was subsequently amended and merged to form the Kinder Morgan Savings Plan. The plan now permits all full-time employees of our general partner to contribute 1% to 50% of base compensation, on a pre-tax basis, into participant accounts. In addition to a mandatory contribution equal to 4% of base compensation per year for most plan participants, our general partner may make discretionary contributions in years when specific performance objectives are met. Certain employees' contributions are based on collective bargaining agreements. Our mandatory contributions are made each pay period on behalf of each eligible employee. Any discretionary contributions are made during the first quarter following the performance year. All contributions, including discretionary contributions, are in the form of KMI stock that is immediately convertible into other available investment vehicles at the employee's discretion. In the first quarter of 2002, no discretionary contributions were made to individual accounts for 2001. The total amount charged to expense for our Retirement Savings Plan was $4.6 million during 2001. All contributions, together with earnings thereon, are immediately vested and not subject to forfeiture. Participants may direct the investment of their contributions into a variety of investments. Plan assets are held and distributed pursuant to a trust agreement. Effective January 1, 2001, employees of our general partner became eligible to participate in a new Cash Balance Retirement Plan. Certain employees continue to accrue benefits through a career-pay formula, "grandfathered" according to age and years of service on December 31, 2000, or collective bargaining arrangements. All other employees will accrue benefits through a personal retirement account in the new Cash Balance Retirement Plan. Employees with prior service and not grandfathered convert to the Cash Balance Retirement Plan and will be credited with the current fair value of any benefits they have previously accrued through the defined benefit plan. We will then begin contributions on behalf of these employees equal to 3% of eligible compensation every pay period. In addition, we may make discretionary contributions to the plan based on our performance. In the first quarter of 2002, an additional 1% discretionary contribution was made to individual accounts based on achieving 2001 financial targets to unitholders. Interest will be credited to the personal retirement accounts at the 30-year U.S. Treasury bond rate in effect each year. Employees will be fully vested in the plan after five years, and they may take a lump sum distribution upon termination of employment or retirement. 11. PARTNERS' CAPITAL At December 31, 2001, our Partners' capital consisted of 129,855,018 common units, 5,313,400 Class B units and 30,636,363 i-units. Together, these 165,804,781 units represent the limited partners' interest and an effective 98% economic interest in the Partnership, exclusive of our general partner's incentive distribution. Our common unit total consisted of 110,071,392 units held by third parties, 18,059,626 units held by KMI and its consolidated affiliates (excluding our general partner) and 1,724,000 units held by our general partner. Our Class B units were held entirely by KMI and our i-units were held entirely by KMR. At December 31, 2000 and 1999, there were 129,716,218 and 118,274,274 common units outstanding, respectively. The Class B units were issued in December 2000 and the i-units were issued in 2001. Our general partner has an effective 2% interest in the Partnership, excluding the general partner's incentive distribution. 112 In May 2001, we received net proceeds of approximately $996.9 million from KMR for the issuance of i-units. In accordance with KMR's public offering of limited liability shares, i-units were issued as follows: - 2,975,000 units to KMI; and - 26,775,000 units to the public. We used the proceeds from the i-unit issuance to reduce the debt we incurred in our acquisition of GATX Corporation's domestic pipeline and liquids terminal businesses during the first quarter of 2001. The i-units are a separate class of limited partner interest in the Partnership. All of the i-units will be owned by KMR and will not be publicly traded. KMR's limited liability company agreement provides that the number of all of its outstanding shares, including voting shares owned by our general partner, shall at all times equal the number of i-units that it owns. Through the combined effect of the provisions in our partnership agreement and the provisions of KMR's limited liability company agreement, the number of outstanding KMR shares and the number of i-units will at all times be equal. KMR, as the owner of the i-units, generally will vote together with the holders of the common units and Class B units as a single class. However, the i-units will vote separately as a class on the following matters: - amendments to our partnership agreement that would have a material adverse effect on the holders of the i-units in relation to the other classes of units (this kind of an amendment requires the approval of two-thirds of the outstanding i-units, excluding the number of i-units equal to the number of KMR shares owned by KMI and its affiliates); and - the approval of the withdrawal of our general partner or the transfer to a non-affiliate of all of its interest as our general partner (these matters require the approval of a majority of the outstanding i-units excluding the number of i-units equal to the number of KMR shares owned by KMI and its affiliates). In all cases, KMR will vote its i-units in proportion to the affirmative and negative votes, abstentions and non-votes of owners of KMR shares. Furthermore, under the terms of our partnership agreement, we agree that we will not, except in liquidation, make a distribution on an i-unit other than in additional i-units or a security that has in all material respects the same rights and privileges as our i-units. Typically, our general partner and owners of common units and Class B units will receive distributions from us in cash, while KMR as the owner of i-units will receive distributions in additional i-units or fractions of i-units. For each outstanding i-unit, a fraction of an i-unit will be issued. The fraction will be determined by dividing the amount of cash being distributed per common unit by the average market price of a KMR share over the ten consecutive trading days preceding the date on which the shares begin to trade ex-dividend under the rules of the principal exchange on which the shares are listed. The cash equivalent of distributions of i-units will be treated as if it had actually been distributed for purposes of determining the distributions to our general partner. We will not distribute the related cash but will retain the cash and use the cash in our business. If additional units are distributed to the holders of our common units, we will issue an equivalent amount of i-units to KMR based on the number of i-units it owns. For the purposes of maintaining partner capital accounts, our partnership agreement specifies that items of income and loss shall be allocated among the partners, other than owners of i-units, in accordance with their percentage interests. Normal allocations according to percentage interests are made, however, only after giving effect to any priority income allocations in an amount equal to the incentive distributions that are allocated 100% to our general partner. Incentive distributions allocated to our general partner are determined by the amount quarterly distributions to unitholders exceed certain specified target levels. For the years ended December 31, 2001, 2000 and 1999, we distributed $2.15, $1.7125 and $1.425, respectively, per unit. Our distributions to unitholders for 2001, 2000 and 1999 required incentive distributions to our general partner in the amount of $199.7 million, $107.8 million and $55.0 million, respectively. The increased incentive distributions paid 113 for 2001 over 2000 and 2000 over 1999 reflect the increase in amounts distributed per unit as well as the issuance of additional units. On January 16, 2002, we declared a cash distribution for the quarterly period ended December 31, 2001, of $0.55 per unit. This distribution was paid on February 14, 2002, to unitholders of record as of January 31, 2002. Our common unitholders and Class B unitholders received cash. KMR, our sole i-unitholder, received a distribution in the form of additional i-units based on the $0.55 distribution per common unit. The number of i-units distributed was 453,970. For each outstanding i-unit that KMR held, a fraction of an i-unit was issued. The fraction was determined by dividing: - $0.55, the cash amount distributed per common unit by - $37.116, the average of KMR's limited liability shares' closing market prices from January 14-28, 2002, the ten consecutive trading days preceding the date on which the shares began to trade ex-dividend under the rules of the New York Stock Exchange. This distribution required an incentive distribution to our general partner in the amount of $54.4 million. Since this distribution was declared after the end of the quarter, no amount is shown in the December 31, 2001 balance sheet as a Distribution Payable. 12. RELATED PARTY TRANSACTIONS GENERAL AND ADMINISTRATIVE EXPENSES Kinder Morgan Management, LLC, through its wholly owned subsidiary, Kinder Morgan Services LLC provides employees and related centralized payroll and employee benefits services to us, our operating partnerships and subsidiaries, Kinder Morgan G.P., Inc. and KMR (collectively, the "Group"). Employees of Kinder Morgan Services are assigned to work for one or more members of the Group. The direct costs of all compensation, benefits expenses, employer taxes and other employer expenses for these employees are allocated and charged by Kinder Morgan Services LLC to the appropriate members of the Group; and the members of the Group reimburse Kinder Morgan Services for their allocated shares of these direct costs. There is no profit or margin charged by Kinder Morgan Services LLC to the members of the Group. The administrative support necessary to implement these payroll and benefits services is provided by the human resource department of Kinder Morgan, Inc., and the related administrative costs are allocated to members of the Group in accordance with existing expense allocation procedures. The effect of these arrangements is that each member of the Group bears the direct compensation and employee benefits costs of its assigned or partially assigned employees, as the case may be, while also bearing its allocable share of administrative costs. Pursuant to our limited partnership agreement, we reimburse Kinder Morgan Services LLC for our share of these administrative costs and such reimbursements will be accounted for as described above. The named executive officers of our general partner and KMR and some other employees that provide management or services to both Kinder Morgan, Inc. and the Group are employed by Kinder Morgan, Inc. Additionally, other Kinder Morgan, Inc. employees assist in the operation of Kinder Morgan Energy Partners' Natural Gas Pipeline assets formerly owned by Kinder Morgan, Inc. These Kinder Morgan, Inc. employees' expenses are allocated without a profit component between Kinder Morgan, Inc. and the appropriate members of the Group. PARTNERSHIP DISTRIBUTIONS Kinder Morgan G.P., Inc. Kinder Morgan G.P., Inc. serves as our sole general partner. Pursuant to our partnership agreements, our general partner's interests represent a 1% ownership interest in the Partnership, and a direct 1.0101% ownership interest in each of our five operating partnerships. Collectively, our general partner owns an effective 2% interest in the operating partnerships, excluding incentive distributions: 114 - its 1.0101% direct general partner ownership interest (accounted for as minority interest in the consolidated financial statements of the Partnership); and - its 0.9899% ownership interest indirectly owned via its 1% ownership interest in the Partnership. At December 31, 2001, our general partner owned 1,724,000 common units, representing approximately 1.04% of our outstanding limited partner units. Our partnership agreement requires that we distribute 100% of "Available Cash" (as defined in the partnership agreement) to our partners within 45 days following the end of each calendar quarter in accordance with their respective percentage interests. Available Cash consists generally of all of our cash receipts and net reductions in reserves less cash disbursements and net additions to reserves (including any reserves required under debt instruments for future principal and interest payments) and amounts payable to the former general partner of SFPP, L.P. in respect of its remaining 0.5% special limited partner interest in SFPP, L.P. Our general partner is granted discretion by our partnership agreement, which discretion has been delegated to KMR, subject to the approval of our general partner in certain cases, to establish, maintain and adjust reserves for future operating expenses, debt service, maintenance capital expenditures, rate refunds and distributions for the next four quarters. These reserves are not restricted by magnitude, but only by type of future cash requirements with which they can be associated. When KMR determines our quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level. Typically, our general partner and owners of our common units and Class B units receive distributions in cash, while KMR, the sole owner of our i-units, receives distributions in additional i-units or fractions of i-units. For each outstanding i-unit, a fraction of an i-unit will be issued. The fraction is calculated by dividing the amount of cash being distributed per common unit by the average market price of KMR's limited liability shares over the ten consecutive trading days preceding the date on which the shares begin to trade ex-dividend under the rules of the New York Stock Exchange. The cash equivalent of distributions of i-units will be treated as if it had actually been distributed, including for purposes of determining the distributions to our general partner and calculating Available Cash for future periods. We will not distribute the related cash but will retain the cash and use the cash in our business. Available Cash is initially distributed 98% to our limited partners and 2% to our general partner. These distribution percentages are modified to provide for incentive distributions to be paid to our general partner in the event that quarterly distributions to unitholders exceed certain specified targets. Available Cash for each quarter is distributed as follows; - first, 98% to the owners of all classes of units pro rata and 2% to our general partner until the owners of all classes of units have received a total of $0.15125 per unit in cash or equivalent i-units for such quarter; - second, 85% of any Available Cash then remaining to the owners of all classes of units pro rata and 15% to our general partner until the owners of all classes of units have received a total of $0.17875 per unit in cash or equivalent i-units for such quarter; - third, 75% of any Available Cash then remaining to the owners of all classes of units pro rata and 25% to our general partner until the owners of all classes of units have received a total of $0.23375 per unit in cash or equivalent i-units for such quarter; and - fourth, 50% of any Available Cash then remaining to the owners of all classes of units pro rata, to owners of common units and Class B units in cash and to KMR in the equivalent number of i-units, and 50% to our general partner in cash. Incentive distributions are generally defined as all cash distributions paid to our general partner that are in excess of 2% of the aggregate amount of cash being distributed. Our general partner's declared incentive distributions for the years ended December 31, 2001, 2000 and 1999 were $199.7 million, $107.8 million and $55.0 million, respectively. 115 Kinder Morgan, Inc. KMI, through its subsidiary Kinder Morgan (Delaware), Inc., remains the sole stockholder of our general partner. At December 31, 2001, KMI directly owned 13,047,300 common units and 5,313,400 class B units, indirectly owned 6,736,326 common units owned by its consolidated affiliates, including our general partner, and owned 5,956,946 KMR shares, representing an indirect ownership interest of 5,956,946 i-units. These units represent approximately 18.7% of our outstanding limited partner units. Kinder Morgan Management, LLC KMR, our general partner's delegate, remains the sole owner of our 30,636,363 i-units. ASSET ACQUISITIONS Effective December 31, 1999, we acquired over $935.8 million of assets from KMI. As consideration for the assets, we paid to KMI $330 million and 19,620,000 common units, valued at approximately $406.3 million. In addition, we assumed $40.3 million in debt and approximately $121.6 million in liabilities. We acquired Kinder Morgan Interstate Gas Transmission LLC (formerly K N Interstate Gas Transmission Co.), a 33 1/3% interest in Trailblazer Pipeline Company and a 49% equity interest in Red Cedar Gathering Company. The acquired interest in Trailblazer Pipeline Company, when combined with the interest purchased on November 30, 1999, gave us a 66 2/3% ownership interest. Effective December 31, 2000, we acquired over $621.7 million of assets from KMI. As consideration for these assets, we paid to KMI $192.7 million in cash and approximately $156.3 million in units, consisting of 1,280,000 common units and 5,313,400 class B units. We also assumed liabilities of approximately $272.7 million. We acquired Kinder Morgan Texas Pipeline, L.P. and MidCon NGL Corp. (both of which were converted to single-member limited liability companies), the Casper and Douglas natural gas gathering and processing systems, a 50% interest in Coyote Gas Treating, LLC and a 25% interest in Thunder Creek Gas Services, LLC. The purchase price for the transaction was determined by the boards of directors of KMI and our general partner based on pricing principles used in the acquisition of similar assets as well as a fairness opinion from the investment banking firm A.G. Edwards & Sons, Inc. OPERATIONS KMI or its subsidiaries operate and maintain for us the assets comprising our Natural Gas Pipelines business segment. Natural Gas Pipeline Company of America, a subsidiary of KMI, operates Trailblazer Pipeline Company's assets under a long-term contract pursuant to which Trailblazer Pipeline Company incurs the costs and expenses related to NGPL's operating and maintaining the assets. Trailblazer Pipeline Company provides the funds for capital expenditures. NGPL does not profit from or suffer loss related to its operation of Trailblazer Pipeline Company's assets. The remaining assets comprising our Natural Gas Pipelines business segment are operated under two separate agreements, one entered into December 31, 1999, between KMI and Kinder Morgan Interstate Gas Transmission LLC, and one entered into December 31, 2000, between KMI and Kinder Morgan Operating L.P. "A". Both agreements have five-year terms and contain automatic five-year extensions. Under these agreements, Kinder Morgan Interstate Gas Transmission LLC and Kinder Morgan Operating L.P. "A" pay KMI a fixed amount as reimbursement for the corporate general and administrative costs incurred in connection with the operation of these assets. The amounts paid to KMI under these agreements for corporate general and administrative costs were $9.5 million for 2001 and $6.1 million for 2000. For 2002, the amount will decrease to $8.6 million. Although we believe the amounts paid to KMI for the services they provided each year fairly reflect the value of the services performed, the determination of these amounts were not the result of arms length negotiations. However, due to the nature of the allocations, these reimbursements may not have exactly matched the actual time and overhead spent. We believe the agreed-upon amounts were, at the time the contracts were entered into, a reasonable estimate of the corporate general and administrative expenses to be incurred by KMI and its 116 subsidiaries in performing such services. We also reimburse KMI and its subsidiaries for operating and maintenance costs and capital expenditures incurred with respect to these assets. OTHER Generally, KMR makes all decisions relating to the management and control of our business. Our general partner owns all of KMR's voting securities and is its sole managing member. KMI, through its wholly owned and controlled subsidiary Kinder Morgan (Delaware), Inc., owns all the common stock of our general partner. Certain conflicts of interest could arise as a result of the relationships among KMR, our general partner, KMI and us. The directors and officers of KMI have fiduciary duties to manage KMI, including selection and management of its investments in its subsidiaries and affiliates, in a manner beneficial to the shareholders of KMI. In general, KMR has a fiduciary duty to manage us in a manner beneficial to our unitholders. The partnership agreements for us and our operating partnerships contain provisions that allow KMR to take into account the interests of parties in addition to us in resolving conflicts of interest, thereby limiting its fiduciary duty to our unitholders, as well as provisions that may restrict the remedies available to unitholders for actions taken that might, without such limitations, constitute breaches of fiduciary duty. The duty of the directors and officers of KMI to the shareholders of KMI may, therefore, come into conflict with the duties of KMR and its directors and officers to our unitholders. The Conflicts and Audit Committee of KMR's board of directors will, at the request of KMR, review (and is one of the means for resolving) conflicts of interest that may arise between KMI or its subsidiaries, on the one hand, and us, on the other hand. 13. LEASES AND COMMITMENTS We have entered into certain operating leases. Including probable elections to exercise renewal options, the remaining terms on our leases range from one to 42 years. Future commitments related to these leases at December 31, 2001 are as follows (in thousands): 2002........................................................ $ 16,735 2003........................................................ 14,702 2004........................................................ 12,133 2005........................................................ 11,019 2006........................................................ 10,798 Thereafter.................................................. 68,793 -------- Total minimum payments...................................... $134,180 ========
We have not reduced our total minimum payments for future minimum sublease rentals aggregating approximately $2.2 million. Total lease and rental expenses, including related variable charges were $41.1 million for 2001, $7.5 million for 2000 and $8.8 million for 1999. During 1998, we established a common unit option plan, which provides that key personnel are eligible to receive grants of options to acquire common units. The number of common units available under the option plan is 500,000. The option plan terminates in March 2008. As of December 31, 2001, outstanding options for 379,400 common units were granted to certain personnel with a term of seven years at exercise prices equal to the market price of the common units at the grant date. In addition, as of December 31, 2001, outstanding options for 30,000 common units were granted to our three non-employee directors. The options granted generally vest 40% in the first year and 20% each year thereafter. We apply Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations in accounting for common unit options granted under our common unit option plan. Pro forma information regarding changes in net income and per unit data, if the accounting prescribed by Statement of Financial Accounting Standards No. 123 "Accounting for Stock Based Compensation," had been applied, is not material. No compensation expense has been recorded since the options were granted at exercise prices equal to the market prices at the date of grant. 117 Effective January 17, 2002, our general partner entered into a retention agreement with C. Park Shaper, an officer of our general partner and its delegate. Pursuant to the terms of the agreement, Mr. Shaper received a $5 million personal loan guaranteed by us. Mr. Shaper was required to purchase KMI common shares and our common units in the open market with the loan proceeds. If he voluntarily leaves us prior to the end of five years, then he must repay the entire loan. After five years, provided Mr. Shaper has continued to be employed by our general partner, we and KMI will assume Mr. Shaper's obligations under the loan. The agreement contains provisions that address termination for cause, death, disability and change of control. We have an Executive Compensation Plan for certain executive officers of our general partner. We may, at our option and with the approval of our unitholders, pay the participants in units instead of cash. Eligible awards are equal to a percentage of an incentive compensation value, which is equal to a formula based upon the cash distributions paid to our general partner during the four calendar quarters preceding the date of redemption multiplied by eight. The amount of these awards are accrued as compensation expense and adjusted quarterly. Under the plan, no eligible employee may receive a grant in excess of 2% of the incentive compensation value and total awards under the plan may not exceed 10% of the incentive compensation value. The plan terminates January 1, 2007, and any unredeemed awards will be automatically redeemed. At December 31, 2001, there were no outstanding awards granted under our Executive Compensation Plan. 14. RISK MANAGEMENT HEDGING ACTIVITIES Our normal business activities expose us to risks associated with changes in the market price of natural gas and associated transportation, natural gas liquids, crude oil and carbon dioxide. Through KMI, we use energy financial instruments to reduce our risk of price changes in the spot and fixed price of natural gas, natural gas liquids and crude oil markets as discussed below. We are exposed to credit-related losses in the event of nonperformance by counterparties to these financial instruments but, given their existing credit ratings, we do not expect any counterparties to fail to meet their obligations. The fair value of these risk management instruments reflects the estimated amounts that we would receive or pay to terminate the contracts at the reporting date, thereby taking into account the current unrealized gains or losses on open contracts. We have available market quotes for substantially all of the financial instruments that we use. The energy risk management products that we use include: - commodity futures and options contracts; - fixed-price swaps; and - basis swaps. Pursuant to our management's approved policy, we are to engage in these activities only as a hedging mechanism against price volatility associated with: - pre-existing or anticipated physical natural gas, natural gas liquids, crude oil and carbon dioxide sales; - gas purchases; and - system use and storage. Our risk management activities are only used in order to protect our profit margins and our risk management policies prohibit us from engaging in speculative trading. Commodity-related activities of our risk management group are monitored by KMI's Risk Management Committee, which is charged with the review and enforcement of our management's risk management policy. 118 Effective January 1, 2001, we adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" as amended by Statement of Financial Accounting Standards No. 137, "Accounting for Derivative Instruments and Hedging Activities -- Deferral of the Effective Date of FASB Statement No. 133" and No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities". SFAS No. 133 established accounting and reporting standards requiring that every derivative financial instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. SFAS No. 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. If the derivatives meet those criteria, SFAS No. 133 allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company formally designate a derivative as a hedge and document and assess the effectiveness of derivatives associated with transactions that receive hedge accounting. As a result of our adoption of SFAS No. 133, we recorded a cumulative effect adjustment in other comprehensive income of $22.8 million representing the fair value of our derivative financial instruments utilized for hedging activities as of January 1, 2001. During the year ended December 31, 2001, $16.6 million of this initial adjustment was reclassified to earnings as a result of hedged sales and purchases during the period. Purchases or sales of commodity contracts require a dollar amount to be placed in margin accounts. In addition, through KMI, we are required to post margins with certain over-the-counter swap partners. These margin requirements are determined based upon credit limits and mark-to-market positions. Our margin deposits associated with commodity contract positions were $20.0 million at December 31, 2001 and $7.0 million on December 31, 2000. Our margin deposits associated with over-the-counter swap partners were ($42.1) million on December 31, 2001 and $0.0 on December 31, 2000. We recognized approximately $1.3 million net in earnings as a loss during 2001 as a result of ineffective hedges, which amount is reported within the caption "Operations and maintenance" in the accompanying Consolidated Statements of Income. We did not exclude any component of the derivative instruments' gain or loss from the assessment of hedge effectiveness. We reclassify the gains and losses included in accumulated other comprehensive income into earnings as the hedged sales and purchases take place. We expect to reclassify approximately $45.4 million of the accumulated other comprehensive income balance of $63.8 million representing unrecognized net gains on derivative activities at December 31, 2001 into earnings during the next twelve months. During 2001, we did not reclassify any gains or losses into earnings as a result of the discontinuance of cash flow hedges due to a determination that the forecasted transactions will no longer occur by the end of the originally specified time period. The differences between the current market value and the original physical contracts value associated with hedging activities are primarily reflected as other current assets and accrued other current liabilities in the accompanying consolidated balance sheet at December 31, 2001. At December 31, 2001, our balance of $194.9 million of other current assets includes approximately $163.7 million related to risk management activities, and our balance of $209.9 million of accrued other current liabilities includes approximately $117.8 million related to risk management activities. The remaining differences between the current market value and the original physical contracts value associated with hedging activities are reflected as deferred charges or deferred credits in the accompanying consolidated balance sheet at December 31, 2001. Prior to 2001, we accounted for gain/loss on our over the counter swaps and marked our open futures position to market value. Such items were deferred on the balance sheet and reflected in current receivables, other current assets, accrued other current liabilities, deferred charges or deferred credits in the accompanying consolidated balance sheet at December 31, 2000. These deferrals are offset by the corresponding value of the underlying physical transactions. In the event energy financial instruments are terminated prior to the period of physical delivery of the items being hedged, the gains and losses on the energy financial instruments at the time of termination remain deferred until the period of physical delivery. 119 Given our portfolio of businesses as of December 31, 2001, our principal uses of derivative financial instruments will be to mitigate the risk associated with market movements in the price of energy commodities. Our short natural gas derivatives position primarily represents our hedging of anticipated future natural gas sales. Our short crude oil derivatives position represents our crude oil derivative sales made to hedge anticipated oil sales. In addition, crude oil contracts have been sold to hedge anticipated carbon dioxide sales that have pricing tied to crude oil prices. Finally, our short natural gas liquids derivatives position reflects the hedging of our forecasted natural gas liquids sales. As of December 31, 2001, our commodity contracts and over-the-counter swaps and options (in thousands) consisted of the following:
OVER THE COUNTER SWAPS AND COMMODITY OPTIONS CONTRACTS CONTRACTS TOTAL --------- ---------- ---------- (DOLLARS IN THOUSANDS) Deferred Net (Loss) Gain............................ $ 20,957 $ 35,901 $ 56,858 Contract Amounts -- Gross........................... $339,456 $1,436,291 $1,775,747 Contract Amounts -- Net............................. $(90,036) $ (227,979) $ (318,015) (NUMBER OF CONTRACTS(1)) Natural Gas Notional Volumetric Positions: Long............... 3,687 1,688 5,375 Notional Volumetric Positions: Short.............. (4,851) (1,980) (6,831) Net Notional Totals to Occur in 2002.............. (964) (20) (984) Net Notional Totals to Occur in 2003 and Beyond... (200) (271) (471) Crude Oil Notional Volumetric Positions: Long............... 140 116 256 Notional Volumetric Positions: Short.............. (1,947) (583) (2,530) Net Notional Totals to Occur in 2002.............. (1,360) (186) (1,546) Net Notional Totals to Occur in 2003 and Beyond... (447) (281) (728) Natural Gas Liquids Notional Volumetric Positions: Long............... -- 55 55 Notional Volumetric Positions: Short.............. -- (1,258) (1,258) Net Notional Totals to Occur in 2002.............. -- (626) (626) Net Notional Totals to Occur in 2003 and Beyond... -- (577) (577)
- --------------- (1) A term of reference describing a unit of commodity trading. One natural gas contract equals 10,000 MMBtus. One crude oil or natural gas liquids contract equals 1,000 barrels. Our over-the-counter swaps and options are with a number of parties, each of which is an investment grade credit. We both owe money and are owed money under these financial instruments. At December 31, 2001, if all parties owing us failed to pay us amounts due under these arrangements, our credit loss would be $23.2 million. At December 31, 2001, our largest credit exposure to a single counterparty was $4.5 million. During the fourth quarter of 2001, we determined that Enron Corp. was no longer likely to honor the obligations it had to us in conjunction with derivatives we were accounting for as hedges under SFAS No. 133. Upon making that determination, we: - ceased to account for those derivatives as hedges; - entered into new derivative transactions with other counterparties to replace our position with Enron; - designated the replacement derivative positions as hedges of the exposures that had been hedged with the Enron positions; and 120 - recognized a $6.0 million loss (included with "General and administrative" expenses in the accompanying Consolidated Statement of Operations for 2001) in recognition of the fact that it was unlikely that we would be paid the amounts then owed under the contracts with Enron. While we enter into derivative transactions only with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that additional losses will result from counterparty credit risk in the future. INTEREST RATE SWAPS In order to maintain a cost effective capital structure, it is our policy to borrow funds using a mix of fixed rate debt and variable rate debt. Since August 1998, we have entered into interest rate swap agreements for the purpose of hedging the interest rate risk associated with our variable rate debt obligations. In the third quarter of 2001, we elected to adjust our mix to be closer to our target ratio of 50% fixed rate debt and 50% variable rate debt. Accordingly, in August 2001, we entered into interest rate swap agreements with a notional principal amount of $750 million for the purpose of hedging the interest rate risk associated with our fixed rate debt obligations. These agreements effectively convert the interest expense associated with the following series of our senior notes from fixed rates to variable rates based on an interest rate of LIBOR plus a spread: - 8.0% senior notes due March 15, 2005; - 6.30% senior notes due February 1, 2009; and - 7.40% senior notes due March 15, 2031. The swap agreements for our 8.0% senior notes and 6.30% senior notes have terms that correspond to the maturity dates of such series. The swap agreement for our 7.40% senior notes contains mutual cash-out agreements at the then-current economic value every seven years. As of December 31, 2001, we were party to interest rate swap agreements with a total notional principal amount of $900 million. These swaps have been designated as fair value hedges as defined by SFAS No. 133. These swaps also meet the conditions required to assume no ineffectiveness under SFAS No. 133 and, therefore, we have accounted for them using the "shortcut" method prescribed for fair value hedges by SFAS No. 133. Accordingly, we will adjust the carrying value of each swap to its fair value each quarter, with an offsetting entry to adjust the carrying value of the debt securities whose fair value is being hedged. We will record interest expense equal to the variable rate payments, which will be accrued monthly and paid semi-annually. At December 31, 2001, we recognized a liability of $5.4 million for the net fair value of our swap agreements and we included this amount with Other Long-Term Liabilities and Deferred Credits on the accompanying balance sheet. 15. REPORTABLE SEGMENTS We compete in four reportable business segments (see Note 1): - Products Pipelines; - Natural Gas Pipelines; - CO(2) Pipelines; and - Terminals. Each segment uses the same accounting policies as those described in the summary of significant accounting policies (see Note 2). We evaluate performance based on each segments' earnings, which exclude general and administrative expenses, third-party debt costs, interest income and expense and minority interest. Our reportable segments are strategic business units that offer different products and services. Each segment is managed separately because each segment involves different products and marketing strategies. 121 Our Products Pipelines segment derives its revenues primarily from the transportation of refined petroleum products, including gasoline, diesel fuel, jet fuel and natural gas liquids. Our Natural Gas Pipelines segment derives its revenues primarily from the gathering and transmission of natural gas. Our CO(2) Pipelines segment derives its revenues primarily from the marketing and transportation of carbon dioxide used as a flooding medium for recovering crude oil from mature oil fields. Our Terminals segment derives its revenues primarily from the transloading and storing of refined petroleum products and dry and liquid bulk products, including coal, petroleum coke, cement, alumina, salt, and chemicals. Financial information by segment follows (in thousands):
2001 2000 1999 ---------- ---------- ---------- Revenues Product Pipelines.............................. $ 605,392 $ 420,272 $ 313,017 Natural Gas Pipelines.......................... 1,869,315 174,187 1,096 CO(2) Pipelines................................ 122,094 89,214 23 Terminals...................................... 349,875 132,769 114,613 ---------- ---------- ---------- Total consolidated revenues.................... $2,946,676 $ 816,442 $ 428,749 ========== ========== ========== Operating income Product Pipelines.............................. $ 295,288 $ 193,424 $ 185,998 Natural Gas Pipelines.......................... 171,811 97,305 88 CO(2) Pipelines................................ 59,295 47,901 18 Terminals...................................... 136,443 36,996 36,917 ---------- ---------- ---------- Total segment operating income................. 662,837 375,626 223,021 Corporate administrative expenses.............. (99,009) (60,065) (35,614) ---------- ---------- ---------- Total consolidated operating Income............ $ 563,828 $ 315,561 $ 187,407 ========== ========== ========== Earnings from equity investments, net of amortization of excess costs Product Pipelines.............................. $ 22,686 $ 29,105 $ 21,395 Natural Gas Pipelines.......................... 21,156 14,975 2,759 CO(2) Pipelines................................ 31,981 19,328 14,487 Terminals...................................... -- -- 23 ---------- ---------- ---------- Consolidated equity earnings, net of amortization................................ $ 75,823 $ 63,408 $ 38,664 ========== ========== ==========
2001 2000 1999 ---------- ---------- ---------- Interest revenue Product Pipelines.............................. $ -- $ -- $ -- Natural Gas Pipelines.......................... -- -- -- CO(2) Pipelines................................ -- -- -- Terminals...................................... -- -- -- ---------- ---------- ---------- Total segment interest revenue................. -- -- -- Unallocated interest revenue................... 4,473 3,818 1,731 ---------- ---------- ---------- Total consolidated interest revenue............ $ 4,473 $ 3,818 $ 1,731 ========== ========== ==========
122
2001 2000 1999 ---------- ---------- ---------- Interest (expense) Product Pipelines.............................. $ -- $ -- $ -- Natural Gas Pipelines.......................... -- -- -- CO(2) Pipelines................................ -- -- -- Terminals...................................... -- -- -- ---------- ---------- ---------- Total segment interest (expense)............... -- -- -- Unallocated interest (expense)................. (175,930) (97,102) (54,336) ---------- ---------- ---------- Total consolidated interest (expense).......... $ (175,930) $ (97,102) $ (54,336) ========== ========== ========== Other, net Product Pipelines.............................. $ 440 $ 10,492 $ 9,948 Natural Gas Pipelines.......................... 749 744 14,159 CO(2) Pipelines................................ 547 741 710 Terminals...................................... 226 2,607 (669) ---------- ---------- ---------- Total consolidated other, net.................. $ 1,962 $ 14,584 $ 24,148 ========== ========== ========== Income tax benefit (expense) Product Pipelines.............................. $ (9,653) $ (11,960) $ (8,493) Natural Gas Pipelines.......................... -- -- (45) CO(2) Pipelines................................ -- -- -- Terminals...................................... (6,720) (1,974) (1,288) ---------- ---------- ---------- Total consolidated income tax benefit (expense)................................... $ (16,373) $ (13,934) $ (9,826) ========== ========== ========== Segment earnings Product Pipelines.............................. $ 308,761 $ 221,061 $ 208,848 Natural Gas Pipelines.......................... 193,716 113,024 16,961 CO(2) Pipelines................................ 91,823 67,970 15,215 Terminals...................................... 129,949 37,629 34,983 ---------- ---------- ---------- Total segment earnings......................... 724,249 439,684 276,007 Interest and corporate administrative expenses(a)................................. (281,906) (161,336) (93,705) ---------- ---------- ---------- Total consolidated net income.................. $ 442,343 $ 278,348 $ 182,302 ========== ========== ==========
- --------------- (a) Includes interest and debt expense, general and administrative expenses, minority interest expense, extraordinary charges and other insignificant items.
2001 2000 1999 ---------- ---------- ---------- Assets at December 31 Product Pipelines.............................. $3,095,899 $2,220,984 $2,007,050 Natural Gas Pipelines.......................... 2,058,836 1,552,506 888,021 CO(2) Pipelines................................ 503,565 417,278 86,684 Terminals...................................... 990,760 357,689 203,601 ---------- ---------- ---------- Total segment assets........................... 6,649,060 4,548,457 3,185,356 Corporate assets(a)............................ 83,606 76,753 43,382 ---------- ---------- ---------- Total consolidated assets...................... $6,732,666 $4,625,210 $3,228,738 ========== ========== ==========
123 - --------------- (a) Includes cash, cash equivalents and certain unallocable deferred charges. Depreciation and amortization Product Pipelines.............................. $ 65,864 $ 40,730 $ 37,999 Natural Gas Pipelines.......................... 31,564 21,709 929 CO(2) Pipelines................................ 17,562 10,559 -- Terminals...................................... 27,087 9,632 7,541 ---------- ---------- ---------- Total consolidated depreciation and amortization................................ $ 142,077 $ 82,630 $ 46,469 ========== ========== ========== Equity Investments at December 31 Product Pipelines.............................. $ 225,561 $ 231,651 $ 243,668 Natural Gas Pipelines.......................... 146,566 141,613 88,249 CO(2) Pipelines................................ 68,232 9,559 86,675 Terminals...................................... 159 59 59 ---------- ---------- ---------- Total consolidated equity investments.......... 440,518 382,882 418,651 Investment in oil and gas assets to be contributed to joint venture................... -- 34,163 -- ---------- ---------- ---------- $ 440,518 $ 417,045 $ 418,651 ========== ========== ========== Capital expenditures Product Pipelines.............................. $ 84,709 $ 69,243 $ 68,674 Natural Gas Pipelines.......................... 86,124 14,496 -- CO(2) Pipelines................................ 65,778 16,115 -- Terminals...................................... 58,477 25,669 14,051 ---------- ---------- ---------- Total consolidated capital expenditures........ $ 295,088 $ 125,523 $ 82,725 ========== ========== ==========
Our total operating revenues are derived from a wide customer base. For the year ended December 31, 2001, one customer accounted for more than 10% of our total consolidated revenues. Total transactions with Reliant Energy, within our Natural Gas Pipelines and Terminals segments, accounted for 20.2% of our total consolidated revenues during 2001. For each of the two years ending December 31, 2000 and 1999, no revenues from transactions with a single external customer amounted to 10% or more of our total consolidated revenues. 16. LITIGATION AND OTHER CONTINGENCIES The tariffs charged for interstate common carrier pipeline transportation for our pipelines are subject to rate regulation by the Federal Energy Regulatory Commission ("FERC") under the Interstate Commerce Act. The Interstate Commerce Act requires, among other things, that petroleum products pipeline rates be just and reasonable and non-discriminatory. Pursuant to FERC Order No. 561, effective January 1, 1995, petroleum products pipelines are able to change their rates within prescribed ceiling levels that are tied to an inflation index. FERC Order No. 561-A, affirming and clarifying Order No. 561, expands the circumstances under which petroleum products pipelines may employ cost-of-service ratemaking in lieu of the indexing methodology, effective January 1, 1995. For each of the years ended December 31, 2001, 2000 and 1999, the application of the indexing methodology did not significantly affect our tariff rates. 124 FEDERAL ENERGY REGULATORY COMMISSION PROCEEDINGS SFPP, L.P. SFPP, L.P. is the subsidiary limited partnership that owns our Pacific operations, excluding the CALNEV pipeline and related terminals acquired from GATX Corporation. Tariffs charged by SFPP are subject to certain proceedings involving shippers' complaints regarding the interstate rates, as well as practices and the jurisdictional nature of certain facilities and services, on our Pacific operations' pipeline systems. In September 1992, El Paso Refinery, L.P. filed a protest/complaint with the FERC: - challenging SFPP's East Line rates from El Paso, Texas to Tucson and Phoenix, Arizona; - challenging SFPP's proration policy; and - seeking to block the reversal of the direction of flow of SFPP's six-inch pipeline between Phoenix and Tucson. At various dates following El Paso Refinery's September 1992 filing, other shippers on SFPP's South System filed separate complaints, and/or motions to intervene in the FERC proceeding, challenging SFPP's rates on its East and West Lines. These shippers include: - Chevron U.S.A. Products Company; - Navajo Refining Company; - ARCO Products Company; - Texaco Refining and Marketing Inc.; - Refinery Holding Company, L.P. (a partnership formed by El Paso Refinery's long-term secured creditors that purchased its refinery in May 1993); - Mobil Oil Corporation; and - Tosco Corporation. Certain of these parties also claimed that a gathering enhancement charge at SFPP's Watson origin pump station in Carson, California was charged in violation of the Interstate Commerce Act. In subsequent procedural rulings, the FERC consolidated these challenges (Docket Nos. OR92-8-000, et al.) and ruled that they must proceed as a complaint proceeding, with the burden of proof being placed on the complaining parties. These parties must show that SFPP's rates and practices at issue violate the requirements of the Interstate Commerce Act. Hearings in the FERC proceeding were held in 1996 and an initial decision by the FERC administrative law judge was issued on September 25, 1997. The initial decision upheld SFPP's position that "changed circumstances" were not shown to exist on the West Line, thereby retaining the just and reasonable status of all West Line rates that were "grandfathered" under the Energy Policy Act of 1992. Accordingly, the administrative law judge ruled that these rates are not subject to challenge, either for the past or prospectively, in that proceeding. The administrative law judge's decision specifically excepted from that ruling SFPP's Tariff No. 18 for movement of jet fuel from Los Angeles to Tucson, which was initiated subsequent to the enactment of the Energy Policy Act. The initial decision also included rulings that were generally adverse to SFPP on such cost of service issues as: - the capital structure to be used in computing SFPP's 1985 starting rate base under FERC Opinion 154-B; - the level of income tax allowance; and - the recoverability of civil and regulatory litigation expense and certain pipeline reconditioning costs. 125 The administrative law judge also ruled that the gathering enhancement service at SFPP's Watson origin pump station was subject to FERC jurisdiction and ordered that a tariff for that service and supporting cost of service documentation be filed no later than 60 days after a final FERC order on this matter. On January 13, 1999, the FERC issued its Opinion No. 435, which affirmed in part and modified in part the initial decision. In Opinion No. 435, the FERC ruled that all but one of the West Line rates are "grandfathered" as just and reasonable and that "changed circumstances" had not been shown to satisfy the complainants' threshold burden necessary to challenge those rates. The FERC further held that the one "non-grandfathered" West Line tariff did not require rate reduction. Accordingly, the FERC dismissed all complaints against the West Line rates without any requirement that SFPP reduce, or pay any reparations for, any West Line rate. With respect to the East Line rates, Opinion No. 435 reversed in part and affirmed in part the initial decision's ruling regarding the methodology for calculating the rate base for the East Line. Opinion No. 435 modified the initial decision concerning the date on which the starting rate base should be calculated and the accumulated deferred income tax and allowable cost of equity used to calculate the rate base. In addition, Opinion No. 435 ruled that SFPP would not owe reparations to any complainant for any period prior to the date on which that complainant's complaint was filed, thus reducing by two years the potential reparations period claimed by most complainants. On January 19, 1999, ARCO filed a petition with the United States Court of Appeals for the District of Columbia Circuit for review of Opinion No. 435. Additional petitions for review were thereafter filed in that court by RHC, Navajo, Chevron and SFPP. SFPP and certain complainants each sought rehearing of Opinion No. 435 by the FERC, asking that a number of rulings be modified. In compliance with Opinion No. 435, on March 15, 1999, SFPP submitted a compliance filing implementing the rulings made by FERC, establishing the level of rates to be charged by SFPP in the future, and setting forth the amount of reparations owed by SFPP to the complainants under the order. The complainants contested SFPP's compliance filing. On July 6, 1999, in response to a motion by the FERC, the Court of Appeals held the ARCO and RHC petitions in abeyance pending FERC action on petitions for rehearing of Opinion No. 435 and dismissed the Navajo, Chevron and SFPP petitions as premature because those parties had sought FERC rehearing. On May 17, 2000, the FERC issued its Opinion No. 435-A, which ruled on the requests for rehearing and modified Opinion No. 435 in certain respects. It denied requests to reverse its prior rulings that SFPP's West Line rates and Watson Station gathering enhancement facilities charge are entitled to be treated as just and reasonable "grandfathered" rates under the Energy Policy Act. It suggested, however, that if SFPP had fully recovered the capital costs of the Watson Station facilities, that might form the basis of an amended "changed circumstances" complaint. Opinion No. 435-A granted a request by Chevron and Navajo to require that SFPP's December 1988 partnership capital structure be used to compute the starting rate base from December 1983 forward, as well as a request by SFPP to vacate a ruling that would have required the elimination of approximately $125 million from the rate base used to determine capital structure. It also granted two clarifications sought by Navajo, to the effect that SFPP's return on its starting rate base should be based on SFPP's capital structure in each given year (rather than a single capital structure from the outset) and that the return on deferred equity should also vary with the capital structure for each year. Opinion No. 435-A denied the request of Chevron and Navajo that no income tax allowance be recognized for the limited partnership interests held by SFPP's corporate parent, as well as SFPP's request that the tax allowance should include interests owned by certain non-corporate entities. However, it granted Navajo's request to make the computation of interest expense for tax allowance purposes the same as the computation for debt return. 126 Opinion No. 435-A reaffirmed that SFPP may recover certain litigation costs incurred in defense of its rates (amortized over five years), but reversed a ruling that those expenses may include the costs of certain civil litigation between SFPP and Navajo and El Paso. It also reversed a prior decision that litigation costs should be allocated between the East and West Lines based on throughput, and instead adopted SFPP's position that such expenses should be split equally between the two systems. As to reparations, Opinion No. 435-A held that no reparations would be awarded to West Line shippers and that only Navajo was eligible to recover reparations on the East Line. It reaffirmed that a 1989 settlement with SFPP barred Navajo from obtaining reparations prior to November 23, 1993, but allowed Navajo reparations for a one-month period prior to the filing of its December 23, 1993 complaint. Opinion No. 435-A also confirmed that FERC's indexing methodology should be used in determining rates for reparations purposes and made certain clarifications sought by Navajo. Opinion No. 435-A denied Chevron's request for modification of SFPP's prorationing policy. This policy requires customers to demonstrate a need for additional capacity if a shortage of available pipeline space exits. Finally, Opinion No. 435-A directed SFPP to revise its initial compliance filings to reflect the modified rulings. It eliminated the refund obligation for the compliance tariff containing the Watson Station gathering enhancement charge, but required SFPP to pay refunds to the extent that the compliance tariff East Line rates are higher than the rates produced under Opinion No. 435-A. In June 2000, several parties filed requests for rehearing of certain rulings made in Opinion No. 435-A. Chevron and RHC both sought reconsideration of the FERC's ruling that only Navajo is entitled to reparations for East Line shipments. SFPP sought rehearing of the FERC's: - decision to require use of the December 1988 partnership capital structure for the period 1994-98 in computing the starting rate base; - elimination of civil litigation costs; - refusal to allow any recovery of civil litigation settlement payments; and - failure to provide any allowance for regulatory expenses in prospective rates. ARCO, Chevron, Navajo, RHC, Texaco and SFPP sought judicial review of Opinion No. 435-A in the United States Court of Appeals for the District of Columbia Circuit. The FERC moved to: - consolidate those petitions with prior ARCO and RHC petitions to review Opinion No. 435; - dismiss the Chevron, RHC and SFPP petitions; and - hold the other petitions in abeyance pending ruling on the requests for rehearing of Opinion No. 435-A. On July 17, 2000, SFPP submitted a compliance filing implementing the rulings made in Opinion No. 435-A, together with a calculation of reparations due to Navajo and refunds due to other East Line shippers. SFPP also filed a tariff containing East Line rates based on those rulings. On August 16, 2000, the FERC directed SFPP to supplement its compliance filing by providing certain underlying workpapers and information; SFPP responded to that order on August 31, 2000. On September 19, 2000, the Court of Appeals dismissed Chevron's petition for lack of prosecution, and the court in an order issued January 19, 2001 denied a November 2, 2000 motion by Chevron for reconsideration of that dismissal. On October 20, 2000, the court dismissed the petitions for review filed by SFPP and RHC as premature in light of their pending requests for FERC rehearing, consolidated the ARCO, Navajo and Texaco petitions for review with the petitions for review of Opinion No. 435, and ordered that proceedings be held in abeyance until after FERC action on the rehearing requests. Pursuant to the Court's orders, the FERC has filed quarterly reports regarding the status of the proceedings pending before the Commission. On May 14, 2001, ARCO filed an Answer and Protest to the 127 FERC's May 4, 2001 status report, requesting the Court of Appeals to reactivate the petitions for review that are being held in abeyance and to initiate a briefing schedule. On May 24, 2001, the FERC filed an opposition to that motion. On July 6, 2001, ARCO, Chevron, Mobil, Navajo, RHC and Texaco filed a joint motion asking the FERC to expedite its action on their requests for rehearing, correction and clarification of Opinion No. 435-A and on SFPP's compliance filing and related protests. Ultramar filed a similar motion on July 10, 2001. On July 30, 2001, the Court of Appeals issued an order denying ARCO's motion without prejudice and directing the FERC to advise the Court in its next status report as to when the FERC expects to take final action with respect to the proceedings on rehearing. On August 2, 2001, the FERC filed a status report advising the Court that it intended to present the pending requests for rehearing of Opinion No. 435-A for consideration at the FERC's meeting scheduled for September 12, 2001. On September 13, 2001, the FERC issued Opinion No. 435-B ("Opinion on Rehearing and Directing Revised Compliance Filing"), which ruled on pending requests for rehearing and comments on SFPP's compliance filing implementing Opinion No. 435-A. Based on those rulings, the FERC directed SFPP to submit a revised compliance filing, including revised tariffs and revised estimates of reparations and refunds, by November 12, 2001. Opinion No. 435-B denied SFPP's requests for rehearing, which involved the capital structure to be used in computing starting rate base, SFPP's ability to recover litigation and settlement costs incurred in connection with the Navajo and El Paso civil litigation and the need for provision for regulatory costs in prospective rates. The decision also made modifications to the Commission's prior rulings on several other issues. In particular, Opinion No. 435-B reversed Opinion No. 435-A's ruling that Navajo was the sole party entitled to reparations, holding instead that Chevron, RHC, Tosco and Mobil are also eligible to recover reparations for East Line shipments. However, Opinion No. 435-B held that Ultramar is not eligible for reparations in the proceedings in which Opinions No. 435, 435-A and 435-B were issued. The decision also changed prior FERC rulings permitting SFPP to apply certain litigation, environmental and pipeline rehabilitation costs that were not recovered through the prescribed rates to offset overearnings (and potential reparations) and to recover any such costs that remained by means of a surcharge to shippers. In Opinion No. 435-B, the FERC required SFPP to pay reparations to each complainant without any offset for unrecovered costs. It went on to require that SFPP subtract from the total 1995-1998 supplemental costs allowed under Opinion No. 435-A any overearnings that are not paid out as reparations, and allowed SFPP to recover any remaining costs from shippers by means of a five-year surcharge beginning on August 1, 2000. Opinion No. 435-B also ruled that SFPP would only be permitted to recover certain regulatory litigation costs through the surcharge and that the surcharge could not recover environmental or pipeline rehabilitation costs. Opinion No. 435-B granted requests for late intervention as to the compliance filing review by Texaco, ARCO, Ultramar and Tosco; in addition, Navajo had made a timely intervention. On review, the FERC directed SFPP to make several changes in its revised compliance filing, including requiring SFPP to: - use a remaining useful life of 16.8 years in amortizing its starting rate base, instead of the 20.6 year period previously used; - remove the starting rate base component from its base rates as of August 1, 2001; - amortize its accumulated deferred income tax balance beginning in 1992, rather than 1988; - list the corporate unitholders that were the basis for the income tax allowance claimed in its compliance filing and certify that those companies are not Subchapter S corporations; and - "clearly exclude" civil litigation costs from its compliance filing and explain how it has limited litigation costs to FERC-related expenses and assigned them to appropriate periods in making reparations calculations. 128 On October 15, 2001, Chevron and RHC filed petitions for rehearing of Opinion No. 435-B. Chevron's petition asks the FERC to clarify: - the period for which Chevron is entitled to reparations; and - whether East Line shippers that have received the benefit of Commission-prescribed rates for 1994 and subsequent years must show that there has been a substantial divergence between the cost of service and the change in the Commission's rate index in order to have standing to challenge SFPP rates for those years in pending or subsequent proceedings. RHC's petition contends that Opinion No. 435-B erred, and should be modified on rehearing, to the extent it: - suggests that a "substantial divergence" standard applies to complaint proceedings, subsequent to those that led to Opinion No. 435-B, challenging the total level of SFPP's East Line rates; - requires a substantial divergence to be shown between SFPP's cost of service and the change in the FERC oil pipeline index in such subsequent complaint proceedings, rather than a substantial divergence between the cost of service and SFPP's revenues; and - permits SFPP to recover 1993 rate case litigation expenses through a surcharge mechanism. ARCO, Ultramar and SFPP filed petitions seeking judicial review of Opinion No. 435-B (and in SFPP's case, Opinion Nos. 435 and 435-A) in the U.S. Court of Appeals for the District of Columbia Circuit. The Court has consolidated the Ultramar and SFPP petitions with the consolidated cases that had been held in abeyance and has ordered that the consolidated cases be returned to its active docket. On October 24, 2001, the FERC filed a motion asking the court to consolidate ARCO's petition for review of Opinion No. 435-B as well and to hold the consolidated cases in abeyance pending FERC action on the Chevron and RHC petitions for rehearing. On November 7, 2001, the FERC issued an order ruling on the Chevron and RHC petitions for rehearing of Opinion No. 435-B. The Commission held that Chevron's eligibility for reparations should be measured from August 3, 1993, rather than September 23, 1992, as Chevron had sought. The Commission also clarified its prior ruling with respect to the "substantial divergence" test, holding that in order to be considered on the merits, complaints challenging the SFPP rates set by applying the Commission's indexing regulations to the 1994 cost of service derived under the Opinion No. 435 series of orders must demonstrate a substantial divergence between the indexed rates and the pipeline's actual cost of service. Finally, the FERC granted rehearing to hold that SFPP's 1993 regulatory costs should not be included in the surcharge permitted for the recovery of supplemental costs. On December 7, 2001, Chevron filed a petition for rehearing of the FERC's November 7, 2001 order. The petition requested the Commission to specify whether Chevron would be entitled to reparations for the two year period prior to the August 3, 1993 filing of its complaint. On January 7, 2002, SFPP and RHC filed petitions in the U.S. Court of Appeals for the District of Columbia Circuit for review of the FERC's November 7, 2001 order. On January 8, 2002, the Court consolidated those petitions with the petitions for review of Opinion Nos. 435, 435-A and 435-B. On January 24, 2002, the Court of Appeals ordered the consolidated proceedings to be held in abeyance until the FERC acts on the pending request for rehearing of the November 7, 2001 order. SFPP submitted its compliance filing and tariffs implementing Opinion No. 435-B and the Commission's November 7, 2001 order on November 20, 2001. Motions to intervene and protest were subsequently filed by ARCO, Mobil (which now submits filings under the name ExxonMobil), RHC, Navajo and Chevron, alleging that SFPP: - should have calculated the supplemental cost surcharge differently; - did not provide adequate information on the taxpaying status of its unitholders; and - failed to estimate potential reparations for ARCO. 129 On December 10, 2001, SFPP filed a response to those claims, explaining that it had computed the surcharge consistent with the Commission's rulings, provided all unitholder tax status information requested by Opinion No. 435-B and calculated estimated reparations for all complainants for which the FERC had directed it to do so. On December 14, 2001, SFPP filed a revised compliance filing and new tariff correcting an error that had resulted in understating the proper surcharge and tariff rates. On December 20, 2001, the FERC's Director of the Division of Tariffs and Rates Central issued two letter orders rejecting SFPP's November 20, 2001 and December 14, 2001 tariff filings because they were not made effective retroactive to August 1, 2000. On January 11, 2002, SFPP filed a request for rehearing of those orders by the Commission, on the ground that the FERC has no authority to require retroactive reductions to rates filed pursuant to its orders in complaint proceedings. On February 15, 2002, the FERC denied the motion for rehearing. SFPP is currently preparing a motion for reclarification of the order denying rehearing. Motions to intervene and protest the December 14, 2001 corrected submission were filed by Navajo, ARCO and Mobil. Ultramar requested leave to file an out-of-time intervention and protest of both the November 20, 2001 and December 14, 2001 submissions. On January 14, 2002, SFPP responded to those filings to the extent they were not mooted by the orders rejecting the tariffs in question. In December 1995, Texaco filed an additional FERC complaint, which involves the question of whether a tariff filing was required for movements on SFPP's Sepulveda Lines, which are upstream of its Watson, California station origin point, and, if so, whether those rates may be set in that proceeding and what those rates should be. Several other West Line shippers have filed similar complaints and/or motions to intervene in this proceeding, all of which have been consolidated into Docket Nos. OR96-2-000, et al. Hearings before an administrative law judge were held in December 1996 and the parties completed the filing of final post-hearing briefs in January 1997. On March 28, 1997, the administrative law judge issued an initial decision holding that the movements on the Sepulveda Lines are not subject to FERC jurisdiction. On August 5, 1997, the FERC reversed that decision and found the Sepulveda Lines to be subject to the jurisdiction of the FERC. The FERC ordered SFPP to make a tariff filing within 60 days to establish an initial rate for these facilities. The FERC reserved decision on reparations until it ruled on the newly-filed rates. On October 6, 1997, SFPP filed a tariff establishing the initial interstate rate for movements on the Sepulveda Lines from Sepulveda Junction to Watson Station at the preexisting rate of five cents per barrel, along with supporting cost of service documentation. Subsequently, several shippers filed protests and motions to intervene at the FERC challenging that rate. On December 24, 1997, FERC denied SFPP's request for rehearing of the August 5, 1997 decision. On December 31, 1997, SFPP filed an application for market power determination, which, if granted, will enable it to charge market-based rates for this service. Several parties protested SFPP's application. On September 30, 1998, the FERC issued an order finding that, based on SFPP's application, SFPP lacks market power in the Watson Station destination market served by the Sepulveda Lines. The FERC found that SFPP appeared to lack market power in the origin market served by the Sepulveda Lines as well, but established a hearing to permit the protesting parties to substantiate allegations that SFPP possesses market power in the origin market. Hearings before a FERC administrative law judge on this limited issue were held in February 2000. On December 21, 2000, the FERC administrative law judge issued his initial decision finding that SFPP possesses market power over the Sepulveda Lines origin market. SFPP and other parties have filed briefs opposing and supporting the initial decision with the FERC. The ultimate disposition of SFPP's market rate application is pending before the FERC. Following the issuance of the initial decision in the Sepulveda case, the FERC judge indicated an intention to proceed to consideration of the justness and reasonableness of the existing rate for service on the Sepulveda Lines. SFPP sought clarification from FERC on the proper disposition of that issue in light of the pendency of its market rate application and prior deferral of consideration of SFPP's tariff filing. On February 22, 2001, the FERC granted SFPP's motion and deferred consideration of the pending complaints against the Sepulveda Lines rate until after its final disposition of SFPP's market rate application. 130 On October 22, 1997, ARCO, Mobil and Texaco filed another complaint at the FERC (Docket No. OR98-1-000) challenging the justness and reasonableness of all of SFPP's interstate rates. The complaint again challenges SFPP's East and West Line rates and raises many of the same issues, including a renewed challenge to the grandfathered status of West Line rates, that have been at issue in Docket Nos. OR92-8-000, et al. The complaint includes an assertion that the acquisition of SFPP and the cost savings anticipated to result from the acquisition constitute "substantially changed circumstances" that provide a basis for terminating the "grandfathered" status of SFPP's otherwise protected rates. The complaint also seeks to establish that SFPP's grandfathered interstate rates from the San Francisco Bay area to Reno, Nevada and from Portland to Eugene, Oregon are also subject to "substantially changed circumstances" and, therefore, are subject to challenge. In November 1997, Ultramar Diamond Shamrock Corporation filed a similar complaint at the FERC (Docket No. OR98-2-000, et al.). The shippers are seeking both reparations and prospective rate reductions for movements on all of the lines. SFPP filed answers to both complaints, and on January 20, 1998, the FERC issued an order accepting the complaints and consolidating both complaints into one proceeding, but holding them in abeyance pending a FERC decision on review of the initial decision in Docket Nos. OR92-8-000, et al. In July 1998, some complainants amended their complaints to incorporate updated financial and operational data on SFPP. SFPP answered the amended complaints. In a companion order to Opinion No. 435, the FERC directed the complainants to amend their complaints, as may be appropriate, consistent with the terms and conditions of its orders, including Opinion No. 435. On January 10 and 11, 2000, the complainants again amended their complaints to incorporate further updated financial and operational data on SFPP. SFPP filed an answer to these amended complaints on February 15, 2000. On May 17, 2000, the FERC issued an order finding that the various complaining parties had alleged sufficient grounds for their complaints against SFPP's interstate rates to go forward to a hearing. At such hearing, the administrative law judge will assess whether any of the challenged rates that are grandfathered under the Energy Policy Act will continue to have such status and, if the grandfathered status of any rate is not upheld, whether the existing rate is just and reasonable. A hearing in this new proceeding commenced in October 2001 and continues. An initial decision by the administrative law judge is expected in the latter half of 2002. In August 2000, Navajo and RHC filed new complaints against SFPP's East Line rates and Ultramar filed an additional complaint updating its pre-existing challenges to SFPP's interstate pipeline rates. SFPP answered the complaints, and on September 22, 2000, the FERC issued an order accepting these new complaints and consolidating them with the ongoing proceeding in Docket No. OR96-2-000, et al. The complainants have alleged a variety of grounds for finding "substantially changed circumstances," including the acquisition of SFPP and cost savings achieved subsequent to the acquisition. Applicable rules and regulations in this field are vague, relevant factual issues are complex and there is little precedent available regarding the factors to be considered or the method of analysis to be employed in making a determination of "substantially changed circumstances," which is the showing necessary to make "grandfathered" rates subject to challenge. Given the newness of the grandfathering standard under the Energy Policy Act and limited precedent, we cannot predict how these allegations will be viewed by the FERC. If "substantially changed circumstances" are found, SFPP rates previously "grandfathered" under the Energy Policy Act may lose their "grandfathered" status. If these rates are found to be unjust and unreasonable, shippers may be entitled to a prospective rate reduction and a complainant may be entitled to reparations for periods from the date of its complaint to the date of the implementation of the new rates. In June 2001, ARCO and others protested SFPP's adjustment to its interstate rates in compliance with the Commission's indexing regulations. Following submissions by the protestants and SFPP, the Commission issued an order in September 2001 dismissing the protests and finding that SFPP had complied with the Commission's indexing regulations. 131 We are not able to predict with certainty the final outcome of the FERC proceedings, should they be carried through to their conclusion, or whether we can reach a settlement with some or all of the complainants. Although it is possible that current or future proceedings could be resolved in a manner adverse to us, we believe that the resolution of such matters will not have a material adverse effect on our business, financial position or results of operations. CALNEV PIPE LINE LLC We acquired CALNEV Pipe Line LLC in March 2001. CALNEV provides interstate and intrastate transportation from an interconnection with SFPP at Colton, California to destinations in and around Las Vegas, Nevada. On June 1, 2001, CALNEV filed to adjust its interstate rates upward pursuant to the FERC's indexing regulations. ARCO, ExxonMobil, Ultramar Diamond Shamrock and Ultramar, Inc. protested this adjustment. On June 29, 2001, the FERC accepted and suspended the rate adjustment and permitted it to go into effect subject to refund. The FERC withheld ruling on the protests pending submission by CALNEV of its FERC Form No. 6 annual report and responses from the protestants to data contained therein. In September 2001, following submission by CALNEV of its Form No. 6 annual report and further submissions by ARCO and CALNEV, the Commission dismissed the protests, finding that CALNEV's rate adjustment comported with the Commission's indexing regulations. In August 2001, ARCO filed a complaint against CALNEV's interstate rates alleging that they were unjust and unreasonable. Tosco and Ultramar filed interventions. In an October 15, 2001 order, the Commission set this claim for investigation and hearing. The matter has, however, first been referred to a settlement judge and such settlement process is currently ongoing. On November 14, 2001, CALNEV filed a motion for rehearing or, in the alternative, clarification of the Commission's October 15, 2001 order. CALNEV asserted that the Commission should have dismissed ARCO's complaint because it did not meet the standards of the Commission's regulations or, in the alternative, that the Commission should clarify the standards of pleading and proof applicable to ARCO's complaint. On January 14, 2002 Tosco Corporation filed a complaint claiming that CALNEV's rates are unjust and unreasonable and asking that its complaint be consolidated with the ARCO complaints for hearing. Ultramar filed a similar complaint on January 18, 2002. CALNEV answered both of these complaints on February 4, 2002. At a settlement conference on January 17, 2002 the parties made substantial progress toward reaching a settlement. They have agreed to a "standstill" in the litigation while they attempt to reach a comprehensive written settlement. The settlement judge has indicated that he anticipates that the parties will be able to submit a settlement agreement to the Commission on or before April 30, 2002. We are not able to predict with certainty the final outcome of this FERC proceeding, should it be carried through to its conclusion, or whether we can reach a settlement with the complainant. Although it is possible that current or future proceedings could be resolved in a manner adverse to us, we believe that the resolution of such matters will not have a material adverse effect on our business, financial position or results of operations. California Public Utilities Commission Proceeding ARCO, Mobil and Texaco filed a complaint against SFPP with the California Public Utilities Commission on April 7, 1997. The complaint challenges rates charged by SFPP for intrastate transportation of refined petroleum products through its pipeline system in the State of California and requests prospective rate adjustments. On October 1, 1997, the complainants filed testimony seeking prospective rate reductions aggregating approximately $15 million per year. On August 6, 1998, the CPUC issued its decision dismissing the complainants' challenge to SFPP's intrastate rates. On June 24, 1999, the CPUC granted limited rehearing of its August 1998 decision for the purpose of addressing the proper ratemaking treatment for partnership tax expenses, the calculation of environmental costs and the public utility status of SFPP's Sepulveda Line and its Watson Station gathering enhancement facilities. In pursuing these rehearing issues, complainants seek prospective rate reductions aggregating approximately $10 million per year. 132 On March 16, 2000, SFPP filed an application with the CPUC seeking authority to justify its rates for intrastate transportation of refined petroleum products on competitive, market-based conditions rather than on traditional, cost-of-service analysis. On April 10, 2000, ARCO and Mobil filed a new complaint with the CPUC asserting that SFPP's California intrastate rates are not just and reasonable based on a 1998 test year and requesting the CPUC to reduce SFPP's rates prospectively. The amount of the reduction in SFPP rates sought by the complainants is not discernible from the complaint. The rehearing complaint was heard by the CPUC in October 2000 and the April 2000 complaint and SFPP's market-based application were heard by the CPUC in February 2001. All three matters stand submitted as of April 13, 2001, and a decision addressing the submitted matters is expected at any time. We believe that the resolution of such matters will not have a material adverse effect on our business, financial position or results of operations. SOUTHERN PACIFIC TRANSPORTATION COMPANY EASEMENTS SFPP and Southern Pacific Transportation Company are engaged in a judicial reference proceeding to determine the extent, if any, to which the rent payable by SFPP for the use of pipeline easements on rights-of-way held by SPTC should be adjusted pursuant to existing contractual arrangements (Southern Pacific Transportation Company vs. Santa Fe Pacific Corporation, SFP Properties, Inc., Santa Fe Pacific Pipelines, Inc., SFPP, L.P., et al., Superior Court of the State of California for the County of San Francisco, filed August 31, 1994). Although SFPP received a favorable ruling from the trial court in May 1997, in September 1999, the California Court of Appeals remanded the case back to the trial court for further proceeding. SFPP is accruing amounts for payment of the rental for the subject rights-of-way consistent with our expectations of the ultimate outcome of the proceeding. We expect this matter to go to trial during the second quarter of 2002. FERC ORDER 637 Kinder Morgan Interstate Gas Transmission LLC On June 15, 2000, Kinder Morgan Interstate Gas Transmission LLC made its filing to comply with FERC's Orders 637 and 637-A. That filing contained KMIGT's compliance plan to implement the changes required by FERC dealing with the way business is conducted on interstate natural gas pipelines. All interstate natural gas pipelines were required to make such compliance filings, according to a schedule established by FERC. From October 2000 through June 2001, KMIGT held a series of technical and phone conferences to identify issues, obtain input, and modify its Order 637 compliance plan, based on comments received from FERC Staff and other interested parties and shippers. On June 19, 2001, KMIGT received a letter from FERC encouraging it to file revised pro-forma tariff sheets, which reflected the latest discussions and input from parties into its Order 637 compliance plan. KMIGT made such a revised Order 637 compliance filing on July 13, 2001. The July 13, 2001 filing contained little substantive change from the original pro-forma tariff sheets that KMIGT originally proposed on June 15, 2000. On October 19, 2001, KMIGT received an order from FERC, addressing its July 13, 2001 Order 637 compliance plan. In this Order addressing the July 13, 2001 compliance plan, KMIGT's plan was accepted, but KMIGT was directed to make several changes to its tariff, and in doing so, was directed that it could not place the revised tariff into effect until further order of the Commission. KMIGT filed its compliance filing with the October 19, 2001 Order on November 19, 2001 and also filed a request for rehearing/clarification of the FERC's October 19, 2001 Order on November 19, 2001. The November 19, 2001 Compliance filing has been protested by several parties. KMIGT filed responses to those protests on December 14, 2001. At this time, it is unknown when this proceeding will be finally resolved. KMIGT currently expects that it may not have a fully compliant Order 637 tariff approved and in effect until sometime in the first or second quarter of 2002. The full impact of implementation of Order 637 on the KMIGT system is under evaluation. We believe that these matters will not have a material adverse effect on our business, financial position or results of operations. 133 Separately, numerous petitioners, including KMIGT, have filed appeals of Order 637 in the D.C. Circuit, potentially raising a wide array of issues related to Order 637 compliance. Initial briefs were filed on April 6, 2001, addressing issues contested by industry participants. Oral arguments on the appeals were held before the courts in December 2001 and final action is pending. Trailblazer Pipeline Company On August 15, 2000, Trailblazer Pipeline Company made a filing to comply with FERC's Order Nos. 637 and 637-A. Trailblazer Pipeline Company's compliance filing reflected changes in: - segmentation; - scheduling for capacity release transactions; - receipt and delivery point rights; - treatment of system imbalances; - operational flow orders; - penalty revenue crediting; and - right of first refusal language. On October 15, 2001, FERC issued its order on Trailblazer Pipeline Company's Order No. 637 compliance filing. FERC approved Trailblazer Pipeline Company's proposed language regarding operational flow orders and the right of first refusal, but is requiring Trailblazer Pipeline Company to make changes to its tariff related to the other issues listed above. Most of the tariff provisions will have an effective date of January 1, 2002, with the exception of language related to scheduling and segmentation, which will become effective at a future date dependent on when KMIGT's Order No. 637 provisions go into effect. Trailblazer Pipeline Company anticipates no adverse impact on its business as a result of the implementation of Order No. 637. On November 14, 2001, Trailblazer Pipeline Company made its compliance filing pursuant to the FERC order of October 15, 2001. That compliance filing has been protested. Separately, also on November 14, 2001, Trailblazer Pipeline Company filed for rehearing of that FERC order. These pleadings are pending FERC action. STANDARDS OF CONDUCT RULEMAKING On September 27, 2001, FERC issued a Notice of Proposed Rulemaking in Docket No. RM01-10 in which it proposed new rules governing the interaction between an interstate natural gas pipeline and its affiliates. If adopted as proposed, the Notice of Proposed Rulemaking could be read to limit communications between KMIGT, Trailblazer Pipeline Company and their respective affiliates. In addition, the Notice could be read to require separate staffing of KMIGT and its affiliates, and Trailblazer and its affiliates. Comments on the Notice of Proposed Rulemaking were due December 20, 2001. We believe that these matters, as finally adopted, will not have a material adverse effect on our business, financial position or results of operations. CARBON DIOXIDE LITIGATION Kinder Morgan CO(2) Company, L.P. directly or indirectly through its ownership interest in the Cortez Pipeline Company, along with other entities, is a defendant in several actions in which the plaintiffs allege that the defendants undervalued carbon dioxide produced from the McElmo Dome field and overcharged for transportation costs, thereby allegedly underpaying royalties and severance tax payments. The plaintiffs, who are seeking monetary damages and injunctive relief, are comprised of royalty, overriding royalty and small share working interest owners who claim that they were underpaid by the defendants. These cases are: CO(2) Claims Coalition, LLC v. Shell Oil Co., et al., No. 96-Z-2451 (U.S.D.C. Colo. filed 8/22/96); Rutter & Wilbanks et al. v. Shell Oil Co., et al., No. 00-Z-1854 (U.S.D.C. Colo. filed 9/22/00); 134 Watson v. Shell Oil Co., et al., No. 00-Z-1855 (U.S.D.C. Colo. filed 9/22/00); Ainsworth et al. v. Shell Oil Co., et al., No. 00-Z-1856 (U.S.D.C. Colo. file 9/22/00); United States ex rel. Crowley v. Shell Oil Company, et al., No. 00-Z-1220 (U.S.D.C. Colo. filed 6/13/00); Ptasynski et al. v. Shell Western E&P Inc., et al., No. 99-11049 (U.S. Ct. App. 5th Cir. filed 5/21/97 ); Shell Western E&P Inc. v. Bailey, et al., No. 98-28630 (215th Dist. Ct. Harris County, Tex. filed 6/17/98); Shores, et al. v. Mobil Oil Corporation, et al., No. GC-99-01184 (Texas Probate Court, Denton County filed 12/22/99); First State Bank of Denton v. Mobil Oil Corporation, et al., No. PR-8552-01 (Texas Probate Court, Denton County filed 3/29/01); and Celeste C. Grynberg v. Shell Oil Company, et al., No. 98-CV-43 (Colo. Dist. Ct. Montezuma County filed 3/21/98). RSM Production Company et al. v. Kinder Morgan Energy Partners, L.P. et al. Cause No. 4519, in the District Court, Zapata County Texas, 49th Judicial District. On October 15, 2001, Kinder Morgan Energy Partners, L.P. was served with the First Supplemental Petition filed by RSM Production Corporation on behalf of the County of Zapata, State of Texas and Zapata County Independent School District as plaintiffs. Kinder Morgan Energy Partners, L.P. was sued in addition to 15 other defendants, including two other Kinder Morgan affiliates. The Petition alleges that these taxing units relied on the reported volume and analyzed heating content of natural gas produced from the wells located within the appropriate taxing jurisdiction in order to properly assess the value of mineral interests in place. The suit further alleges that the defendants undermeasured the volume and heating content of that natural gas produced from privately owned wells in Zapata County, Texas. The Petition further alleges that the County and School District were deprived of ad valorem tax revenues as a result of the alleged undermeasurement of the natural gas by the defendants. Defendants have sought an extension of time to answer, and have not yet responded to the Petition. There are no further pretrial proceedings at this time. Quinque Operating Company, et al. v. Gas Pipelines, et al. Cause No. 99-1390-CM, United States District Court for the District of Kansas. This action was originally filed in Kansas state court in Stevens County, Kansas as a class action against approximately 245 pipeline companies and their affiliates, including certain Kinder Morgan entities. The plaintiffs in the case seek to have the Court certify the case as a class action. The plaintiffs are natural gas producers and fee royalty owners who allege that they have been subject to systematic mismeasurement of natural gas by the defendants for more than 25 years. Among other things, the plaintiffs allege a conspiracy among the pipeline industry to under-measure natural gas and have asserted joint and several liability against the defendants. Subsequently, one of the defendants removed the action to Kansas Federal District Court. Thereafter, we filed a motion with the Judicial Panel for Multidistrict Litigation to consolidate this action for pretrial purposes with the Grynberg False Claim Act, styled as United States of America, ex rel., Jack J. Grynberg v. K N Energy, Civil Action No. 97-D-1233, filed in the United States District Court, District of Colorado, because of common factual questions. On April 10, 2000, the Multidistrict Litigation Panel ordered that this case be consolidated with the Grynberg federal False Claims Act cases. On January 12, 2001, the Federal District Court of Wyoming issued an oral ruling remanding the case back to the State Court in Stevens County, Kansas. A case management conference recently occurred in State Court in Stevens County, and a briefing schedule was established for preliminary matters. Personal jurisdiction discovery has commenced. Merits discovery has not commenced. Although no assurances can be given, we believe that we have meritorious defenses to all of these actions, that we have established an adequate reserve to cover potential liability, and that these matters will not have a material adverse effect on our business, financial position or results of operations. ENVIRONMENTAL MATTERS We are subject to environmental cleanup and enforcement actions from time to time. In particular, the federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) generally imposes joint and several liability for cleanup and enforcement costs on current or predecessor owners and operators of a site, without regard to fault or the legality of the original conduct. Our 135 operations are also subject to federal, state and local laws and regulations relating to protection of the environment. Although we believe our operations are in substantial compliance with applicable environmental regulations, risks of additional costs and liabilities are inherent in pipeline and terminal operations, and there can be no assurance that we will not incur significant costs and liabilities. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities to us. We are currently involved in the following governmental proceedings related to compliance with environmental regulations associated with our assets: - one cleanup ordered by the United States Environmental Protection Agency related to ground water contamination in the vicinity of SFPP's storage facilities and truck loading terminal at Sparks, Nevada; - several ground water hydrocarbon remediation efforts under administrative orders issued by the California Regional Water Quality Control Board and two other state agencies; and - groundwater and soil remediation efforts under administrative orders issued by various regulatory agencies on those assets purchased from GATX Corporation, comprising Kinder Morgan Liquids Terminals LLC, CALNEV Pipe Line LLC and Central Florida Pipeline LLC. In addition, we are from time to time involved in civil proceedings relating to damages alleged to have occurred as a result of accidental leaks or spills of refined petroleum products, natural gas liquids, natural gas and carbon dioxide. Review of assets related to Kinder Morgan Interstate Gas Transmission LLC includes the environmental impacts from petroleum and used oil releases to the soil and groundwater at nine sites. Additionally, review of assets related to Kinder Morgan Texas Pipeline includes the environmental impacts from petroleum releases to the soil and groundwater at six sites. Further delineation and remediation of these impacts will be conducted. Reserves have been established to address the closure of these issues. On October 2, 2001, the jury rendered a verdict in the case of Walter Chandler v. Plantation Pipe Line Company. The jury awarded the plaintiffs a total of $43.8 million. The verdict was divided with the following award of damages: - $0.3 million compensatory damages for property damage to the Evelyn Chandler Trust; - $5 million compensatory damages to Walter (Buster) Chandler; - $1.5 million compensatory damages to Clay Chandler; and - $37 million punitive damages. Plantation has filed post judgment motions and appeal of the verdict. The appeal of this case will be directly heard by the Alabama Supreme Court. It is anticipated that a decision by the Alabama Supreme Court will be received within the next twelve to eighteen months. This case was filed in April 1997 by the landowner (Evelyn Chandler Trust) and two residents of the property (Buster Chandler and his son, Clay Chandler). The suit was filed against Chevron, Plantation and two individuals. The two individuals were later dismissed from the suit. Chevron settled with the plaintiffs in December 2000. The property and residences are directly across the street from the location of a former Chevron products terminal. The Plantation pipeline system traverses the Chevron terminal property. The suit alleges that gasoline released from the terminal and pipeline contaminated the groundwater under the plaintiffs' property. A current remediation effort is taking place between Chevron, Plantation and Alabama Department of Environmental Management. Although no assurance can be given, we believe that the ultimate resolution of all these environmental matters set forth in this note will not have a material adverse effect on our business, financial position or 136 results of operations. We have recorded a total reserve for environmental claims in the amount of $75.8 million at December 31, 2001. OTHER We are a defendant in various lawsuits arising from the day-to-day operations of our businesses. Although no assurance can be given, we believe, based on our experiences to date, that the ultimate resolution of such items will not have a material adverse impact on our business, financial position or results of operations. 17. QUARTERLY FINANCIAL DATA (UNAUDITED)
BASIC DILUTED OPERATING OPERATING NET INCOME NET INCOME REVENUES INCOME NET INCOME PER UNIT PER UNIT ---------- --------- ---------- ---------- ---------- (IN THOUSANDS, EXCEPT PER UNIT AMOUNTS) 2001 First Quarter................... $1,028,645 $138,351 $101,667 $0.45 $0.45 Second Quarter.................. 735,755 138,596 104,226 0.36 0.36 Third Quarter................... 638,544 144,892 115,792 0.37 0.37 Fourth Quarter.................. 563,880 143,185 120,658 0.40 0.40 2000 First Quarter................... $ 157,358 $ 63,061 $ 59,559 $0.32 $0.32 Second Quarter.................. 193,758 79,976 71,810 0.35 0.35 Third Quarter................... 202,575 79,826 69,860 0.33 0.33 Fourth Quarter.................. 262,751 92,698 77,119 0.34 0.34
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