-----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, RZG5pAvfYkEFo/XYozuuFNqyS78TMBTLtR272z7YfHMuHAxZPBsV0O/5Eiuoa2cd HLNmdFZvRcleSFhMDbYMuQ== 0000950129-01-001954.txt : 20010410 0000950129-01-001954.hdr.sgml : 20010410 ACCESSION NUMBER: 0000950129-01-001954 CONFORMED SUBMISSION TYPE: 8-K/A PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 20010404 ITEM INFORMATION: ITEM INFORMATION: FILED AS OF DATE: 20010405 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: 8-K/A SEC ACT: SEC FILE NUMBER: 001-06446 FILM NUMBER: 1595845 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: K N ENERGY INC DATE OF NAME CHANGE: 19920703 FORMER COMPANY: FORMER CONFORMED NAME: KN ENERGY INC DATE OF NAME CHANGE: 19920430 FORMER COMPANY: FORMER CONFORMED NAME: KANSAS NEBRASKA NATURAL GAS CO INC DATE OF NAME CHANGE: 19830403 8-K/A 1 h85888a1e8-ka.txt KINDER MORGAN, INC. - 4/4/01 1 SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 8-K/A Amendment NO. 1 to CURRENT REPORT Dated February 16, 2001 Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 Date of Report: April 4, 2001 KINDER MORGAN, INC. (Exact name of registrant as specified in its charter) KANSAS 1-6446 48-0290000 (State or other jurisdiction (Commission (I.R.S. Employer of incorporation) File Number) Identification No.) 500 Dallas, Suite 1000 Houston, Texas 77002 (Address of principal executive offices, including zip code) 713-369-9000 (Registrant's telephone number, including area code) 2 Item 5. Other Events. The following financial information of Kinder Morgan, Inc., a Kansas corporation (the "Company"), is included herein: (1) Financial statements as of December 31, 2000 and 1999, and for the years ended December 31, 2000, 1999 and 1998, incorporated herein by reference from the Financial Statements and Supplementary Data set forth in Item 8 of the Company's filing on Form 10-K/A dated April 4, 2001, attached hereto as Exhibit 99.1; (2) Quarterly financial information (unaudited) for 2000 and 1999: incorporated herein by reference from the Quarterly Financial Information (Unaudited) set forth in Item 8 of the Company's filing on Form 10-K/A dated April 4, 2001, attached hereto as Exhibit 99.1; (3) Selected financial data for each of the five years in the period ended December 31, 2000; incorporated herein by reference from the Selected Financial Data set forth in Item 6 of the Company's filing on Form 10-K/A dated April 4, 2001, attached hereto as Exhibit 99.1; (4) Management's discussion and analysis of financial condition and results of operation; incorporated herein by reference from Management's Discussion and Analysis of Financial Condition and Results of Operations set forth in Item 7 of the Company's filing on Form 10-K/A dated April 4, 2001, attached hereto as Exhibit 99.1; (5) Quantitative and qualitative disclosures about market risk; incorporated herein by reference from Quantitative and Qualitative Disclosures About Market Risk set forth in Item 7A of the Company's filing on Form 10-K/A dated April 4, 2001, attached hereto as Exhibit 99.1; and (6) Schedule II - Valuation and Qualifying Accounts; incorporated herein by reference from Schedule II -- Valuation and Qualifying Accounts set forth in Item 14 of the Company's filing on Form 10-K/A dated April 4, 2001, attached hereto as Exhibit 99.1. The consolidated financial statements and related notes of Kinder Morgan Energy Partners, L.P. (an equity method investee of Kinder Morgan, Inc.) are incorporated herein by reference from the Financial Statements and Supplementary Data described in Item 8 and set forth on pages F-1 through F-40 of Kinder Morgan Energy Partners, L.P.'s filing on Form 10-K/A dated April 4, 2001, attached hereto as Exhibit 99.2. Item 7. Financial Statements and Exhibits 99.1 Form 10-K/A of Kinder Morgan, Inc. dated April 4, 2001. 99.2 Form 10-K/A of Kinder Morgan Energy Partners, L.P. dated April 4, 2001. 3 SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized. KINDER MORGAN, INC. Dated: April 4, 2001 By: /s/ JOSEPH LISTENGART ------------------------------- Joseph Listengart Vice President and General Counsel 4 EXHIBIT INDEX ------------- Exhibit No. Description ------ ----------- 99.1 Form 10-K/A of Kinder Morgan, Inc. dated April 4, 2001. 99.2 Form 10-K/A of Kinder Morgan Energy Partners, L.P. dated April 4, 2001. EX-99.1 2 h85888a1ex99-1.txt FORM 10-K/A OF KINDER MORGAN, INC. - 4/1/01 1 ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, DC 20549 FORM 10-K/A (AMENDMENT NO. 1) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended DECEMBER 31, 2000 ----------------- 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 on (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 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. [ ] The aggregate market value of the voting stock held by non-affiliates of the registrant was $4,650,370,529 as of March 1, 2001. 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 115,001,452 shares as of March 1, 2001. Documents Incorporated by Reference Part III of this report incorporates by reference specific portions of the Registrant's Proxy Statement relating to the 2001 Annual Meeting of Stockholders. 2 KINDER MORGAN, INC. AND SUBSIDIARIES CONTENTS
Page Number ------ PART I ITEMS 1&2: BUSINESS AND PROPERTIES..................................................... 3-12 ITEM 3: LEGAL PROCEEDINGS........................................................... 12-15 ITEM 4: SUBMISSION OF MATTERS TO A VOTE OF THE SECURITY HOLDERS..................... 15 EXECUTIVE OFFICERS OF THE REGISTRANT........................................ 16-17 PART II ITEM 5: MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS...................................................... 18 ITEM 6: SELECTED FINANCIAL DATA..................................................... 19 ITEM 7: MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS...................................... 20-38 ITEM 7A QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS................. 38 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA................................. 39-84 ITEM 9: CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE...................................... 84 PART III ITEM 10: DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.......................... 85 ITEM 11: EXECUTIVE COMPENSATION...................................................... 85 ITEM 12: SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.............. 85 ITEM 13: CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.............................. 85 PART IV ITEM 14: EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K............. 86-92 SIGNATURES............................................................................. 93
Note: Individual financial statements of the parent Company are omitted pursuant to the provisions of Accounting Series Release No. 302. 2 3 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, and 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 "Mcf" means thousand cubic feet, the term "MMcf" means million cubic feet, the term "Bcf" means billion cubic feet, the term "Tcf" means trillion 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 Description Our common stock is traded on the New York Stock Exchange under the symbol "KMI." We are one of the largest midstream energy companies in America, operating more than 30,000 miles of natural gas and products pipelines in 26 states. We also have significant retail natural gas distribution, electric generation and bulk terminal operations. We own the general partner of Kinder Morgan Energy Partners, L.P., America's largest pipeline master limited partnership, traded on the New York Stock Exchange under the symbol "KMP" and referred to in this report as "Kinder Morgan Energy Partners." We also hold a significant limited partner interest in Kinder Morgan Energy Partners. Combined, we and Kinder Morgan Energy Partners had an enterprise value of approximately $15 billion at December 31, 2000. Our executive offices are located at 500 Dallas, Suite 1000, Houston Texas 77002 and our telephone number is (713) 369-9000. We employed 3,801 people at December 31, 2000, including employees of Kinder Morgan G.P., Inc. that are dedicated to the operations of Kinder Morgan Energy Partners. 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. After inclusion of incremental units resulting from the sale of certain of our assets to Kinder Morgan Energy Partners as discussed below, we own approximately 14.0 million limited partner units of Kinder Morgan Energy Partners, representing approximately 20.7% of its total outstanding units. 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 Kinder Morgan G.P., Inc. as the general partner, we currently are entitled to receive approximately 49% of all quarterly cash distributions from Kinder Morgan Energy Partners. 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. 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" together with the associated "Amortization of Excess Investment" in our consolidated income statement in the period in which such earnings are reported by Kinder Morgan Energy Partners. Kinder Morgan Energy Partners is the largest publicly traded master limited partnership in the pipeline industry and the second largest products pipeline system in the United States in terms of volumes delivered. Kinder 3 4 ITEMS 1 and 2: BUSINESS and PROPERTIES (continued) Morgan Energy Partners manages a diverse group of assets used in the transportation, storage and processing of energy products, including six refined products/liquids pipeline systems with more than 10,000 miles of pipeline and over 20 truck loading terminals. Additional assets include 10,000 miles of natural gas transportation pipelines and natural gas gathering and storage facilities. Kinder Morgan Energy Partners also operates more than 25 bulk terminal facilities that transfer over 40 million tons of coal, petroleum coke and other products annually. In addition, Kinder Morgan Energy Partners owns 51% of and operates Plantation Pipeline Company and 100% of Kinder Morgan CO2 Company, L.P., formerly Shell CO2 Company, Ltd. In November 2000, Kinder Morgan Energy Partners announced that it had signed a definitive agreement to purchase the U.S. pipeline and terminal businesses of GATX Corporation for $1.15 billion. On March 1, 2001, Kinder Morgan Energy Partners closed the acquisition of these businesses except for CALNEV Pipeline Company, the closing of which awaits approval from the California Public Utilities Commission. Kinder Morgan G.P.'s cash incentive distributions provide it with a strong incentive to increase unitholder distributions through the successful management and business growth of Kinder Morgan Energy Partners. Effective December 31, 2000, we sold approximately $300 million of assets to Kinder Morgan Energy Partners consisting of (i) Kinder Morgan Texas Pipeline, L.P., a 2,600-mile natural gas pipeline system that extends from south Texas to Houston along the Texas Gulf Coast, (ii) the Casper and Douglas Natural Gas Gathering and Processing Systems, (iii) our 50 percent interest in Coyote Gas Treating, LLC and (iv) our 25 percent interest in Thunder Creek Gas Services, L.L.C., a joint venture engaged in natural gas gathering and processing activities. As consideration for the assets, we received $150 million in cash (with an additional cash payment for working capital), 0.6 million of Kinder Morgan Energy Partners' common limited partner units and 2.7 million Class-B limited partner units of Kinder Morgan Energy Partners. Effective December 31, 1999, we sold over $700 million of assets to Kinder Morgan Energy Partners consisting of (i) Kinder Morgan Interstate Gas Transmission LLC (formerly K N Interstate Gas Transmission Co.), (ii) a 49 percent interest in Red Cedar Gathering Company and (iii) a subsidiary that owns a one-third interest in Trailblazer Pipeline Company. As consideration for the assets, we received 9.81 million Kinder Morgan Energy Partners common units representing limited partner interests and approximately $330 million in cash. Additional information concerning the business of Kinder Morgan Energy Partners, including the acquisitions of properties discussed above, is contained in Kinder Morgan Energy Partners' 2000 Annual Report on Form 10-K. (B) Narrative Description of Business OVERVIEW We are an energy services provider whose principal business units are: (1) Natural Gas Pipeline Company of America (NGPL) and certain affiliates, a major interstate natural gas pipeline and storage system, (2) retail natural gas distribution, 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 and (3) power generation 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. The operations of Kinder Morgan Energy Partners, a 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 terminals. In 1999, we discontinued our wholesale natural gas marketing, non-energy retail marketing services and natural gas gathering and processing businesses. Note 19 of the accompanying Notes to Consolidated Financial Statements contains financial information for each of our business segments. As discussed following, certain of our operations are regulated by various federal and state entities. 4 5 ITEMS 1 and 2: BUSINESS and PROPERTIES (continued) NATURAL GAS PIPELINE COMPANY OF AMERICA 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 60 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, 24 intrastate pipelines and 54 local distribution companies and end users, thereby providing significant flexibility in the receipt and delivery of natural gas. One of Natural Gas Pipeline Company of America's primary pipelines, the 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 and producers, industrial end users, affiliates 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 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 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 2000, Natural Gas Pipeline Company of America delivered an average of 1.9 trillion Btus per day of natural gas to this market. Given its strategic location at the center of the North American pipeline grid, 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. As of January 1, 2001, approximately 75% of the total transportation volume committed under Natural Gas Pipeline Company of America's long-term firm transportation contracts 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. In January 2000, we announced the signing of contracts with Peoples Energy for approximately 300 MMcf per day of firm transportation (generally through 2005) and 20 Bcf of storage services (generally through 2003). Nicor Gas and Peoples Energy are Natural Gas Pipeline Company of America's two largest customers. As of March 1, 2001, contracts representing 20% of Natural Gas Pipeline Company of America's total long-term contracted firm transport capacity are scheduled to expire during the remainder of 2001. 5 6 ITEMS 1 and 2: BUSINESS and PROPERTIES (continued) Through Natural Gas Pipeline Company of America, we are one of the nation's largest natural gas storage operators with approximately 600 Bcf of total natural gas storage capacity, 210 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 Natural Gas Pipeline Company of America serves. Natural Gas Pipeline Company of America owns and operates eight underground storage fields in four states. These storage assets complement Natural Gas Pipeline Company of America's 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. On February 9, 2000, we jointly announced with Nicor, Inc. (an energy and transportation holding company whose subsidiary, Nicor Gas, is a major customer of Natural Gas Pipeline Company of America as discussed preceding) the signing of an agreement to become equal partners in the Horizon Pipeline. The Horizon Pipeline is a $75 million natural gas pipeline that will originate in Joliet, Illinois and extend 74 miles into northern Illinois, connecting the emerging supply hub at Joliet with Nicor Gas' distribution system and an existing Natural Gas Pipeline Company of America pipeline. The initial capacity of the pipeline, expected to be completed in spring of 2002, is 380 MMcf per day, which is fully subscribed and of which 300 MMcf per day has been committed to by Nicor Gas. COMPETITION: Natural Gas Pipeline Company of America is in competition 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 supplies 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 although, at the same time, new pipelines 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. Thus, the overall impact has been to increase the amount of pipeline capacity into the Chicago area but, with additional take-away capacity and the increased demand in the area, the situation 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 market and supply areas, allowing it to offer varied storage services to customers. Natural Gas Pipeline Company of America faces competition from independent storage providers as well as storage services offered by other natural gas pipelines. The competition faced by Natural Gas Pipeline Company of America is generally price-based, although there is also a significant component related to the variety and 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. With respect to its storage services, there can be significant environmental concerns and capital costs associated with the creation of new natural gas storage facilities, providing barriers to entry for potential 6 7 ITEMS 1 and 2: BUSINESS and PROPERTIES (continued) competitors. However, 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 As of December 31, 2000, through Kinder Morgan Retail, our retail natural gas distribution business served approximately 218,000 customers in Colorado, Nebraska and Wyoming through approximately 7,500 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 agriculturally based 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 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 owned by our wholly owned subsidiary, Northern Gas Company, one facility in Colorado operated by Rocky Mountain Natural Gas Company and owned by Slurco Corporation, both of which are wholly owned subsidiaries, 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 100 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 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. COMPETITION: The Kinder Morgan Retail natural gas distribution business unit operates in areas with varying service area rules, including state utility commission certificated areas, non-exclusive municipal franchises and competitive areas. Limited competitive natural gas distribution pipelines exist within the service areas. The primary competition for Kinder Morgan Retail's products is from alternative fuels such as electric power and 7 8 ITEMS 1 and 2: BUSINESS and PROPERTIES (continued) propane for heating use and electric power, propane and diesel fuel for our agriculture use customers. We compete primarily on the basis of price and service. Kinder Morgan Retail currently has unbundled the regulated commodity natural gas supply in Nebraska and eastern Wyoming under Choice Gas Programs, which allow for competitive commodity natural gas providers to sell natural gas to approximately half of our total customers. In the unbundled areas, our Kinder Morgan Retail business unit competes as one of five natural gas marketing companies to provide the customer with natural gas commodity offerings. Our Kinder Morgan Retail business unit currently provides the commodity product for 75% of the end use customers in the unbundled areas. KINDER MORGAN POWER Kinder Morgan Power develops power project sites, designs power plants, constructs power projects and operates electric generation facilities as an independent power producer. Kinder Morgan Power is a fee-for-service business that develops power projects for the benefit of long-term, off-take customers. These customers take the commodity benefits and risks in the market place and pay Kinder Morgan Power a fee for converting energy into electricity. 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) in a combined cycle mode. Thermo has interests in four independent natural gas-fired LM projects in Colorado representing 380 megawatts of electric generation capacity. This LM knowledge was used to develop Kinder Morgan Power's proprietary "Orion" technology, which we are now deploying into the power market. In May 2000, Kinder Morgan Power and the Southern Company 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. Natural gas transportation service for the plant will be provided by Natural Gas Pipeline Company of America. Construction is in process on the facility, for which Kinder Morgan Power is the general contractor. Completion of construction is expected by June 1, 2002. On February 20, 2001, Kinder Morgan Power announced an agreement under which Williams Energy Marketing and Trading will supply natural gas to and market 3,300 megawatts of capacity for 16 years for 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. Kinder Morgan Power is the general contractor for the Jackson power plant, which is expected to begin commercial operation on July 1, 2002. COMPETITION: Kinder Morgan Power's competitors are other companies that develop power projects. 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. RECENT DEVELOPMENTS Filing by Kinder Morgan Management, LLC Kinder Morgan Management, LLC, an indirect wholly owned subsidiary of Kinder Morgan, Inc., has filed a registration statement with the Securities and Exchange Commission to issue and sell shares. Upon completion of that proposed offering, Kinder Morgan Management, LLC would become a partner in Kinder Morgan Energy Partners, L.P. and would manage and control its business and affairs. The net proceeds from the offering would be used to buy i-units from Kinder Morgan Energy Partners. The i-units would be a new class 8 9 ITEMS 1 and 2: BUSINESS and PROPERTIES (continued) of Kinder Morgan Energy Partners' limited partner interests and would be issued only to Kinder Morgan Management, LLC. After the 45th day following the closing of the proposed offering discussed above, holders of the shares of Kinder Morgan Management, LLC may exchange their shares for common units of Kinder Morgan Energy Partners, L.P. owned by us. This right to exchange is subject to our election to settle the exchange in cash rather than in common units. We currently own 11,312,000 Kinder Morgan Energy Partners common units. Upon the occurrence of certain events, we will be required to purchase all of the then outstanding shares of Kinder Morgan Management, LLC at a price equal to the higher of the average market price of such shares or the common units of Kinder Morgan Energy Partners, L.P. as determined for a 10 trading day period ending on the trading day immediately prior to the date of the applicable event. If our affiliates and we ever own 80% or more of the outstanding shares of Kinder Morgan Management, LLC, we will have the right to purchase all of the shares owned by other holders at 110% of the market price. If our affiliates and we ever own 80% or more in the aggregate of outstanding Kinder Morgan Energy Partners, L.P.'s common units and Kinder Morgan Management, LLC's shares, we will have the right to purchase all of the shares and units owned by others at the higher of the average closing prices of the shares and common units. We can give no assurance that this proposed issuance of Kinder Morgan Management, LLC shares will occur or that it will not be modified from the description given above if it is ultimately completed. Early Extinguishment of Debt On March 1, 2001 we retired $400 million of Reset Put Securities due March 1, 2021, utilizing a combination of cash and incremental short-term borrowings. We expect to report an extraordinary after-tax loss of approximately $12 million in the first quarter associated with this early extinguishment of debt. REGULATION FEDERAL AND STATE REGULATION 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 natural gas companies, including interstate 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 pipelines that perform open access transportation under blanket certificates to "unbundle" or separate their traditional merchant sales services from their transportation and storage services and to provide comparable transportation and storage services with respect to all gas supplies, whether purchased from the pipeline or from other merchants such as marketers or producers. The pipelines must now separately state the applicable rates for each unbundled service. 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 pipelines from using their gas transportation and storage facilities to market gas to sales customers, Natural Gas Pipeline Company of America no longer had a sales market for the gas it is 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 gas suppliers. Under settlement agreements between Natural Gas Pipeline Company of America and its former sales customers, Natural Gas Pipeline 9 10 ITEMS 1 and 2: BUSINESS and PROPERTIES (continued) Company of America recovered from these customers a significant amount of the gas supply realignment costs over a four-year period beginning December 1, 1993. These settlement agreements were approved by the FERC. The FERC also permitted Natural Gas Pipeline Company of America to implement a tariff mechanism to recover additional portions of its 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 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 gas supply realignment costs over the period from December 1, 1998 through November 30, 2001. 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 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 transportation and sales services within the state. Rocky Mountain also performs certain 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 transportation and sales services within the state. Northern Gas also performs certain 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. INTERSTATE TRANSPORTATION AND STORAGE SERVICES Facilities that we use in the transportation of natural gas in interstate commerce and for natural gas storage services in interstate commerce are subject to regulation by the FERC under the Natural Gas Act and the Natural Gas Policy Act. 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 pipeline of its marketing affiliates and govern, in particular, the provision of information by an interstate pipeline to its marketing affiliates. On March 29, 2000, we announced that we had reached a settlement with the FERC regarding issues surrounding the interpretation of FERC Order No. 497 (which governs the conduct of interstate pipelines and affiliated gas marketers on their systems) relative to Natural Gas Pipeline Company of America, Kinder Morgan Interstate Gas Transmission LLC and Westar Transmission Company. Kinder Morgan Interstate has been sold to Kinder Morgan Energy Partners, and Westar has been sold to ONEOK, Inc. Combined, we agreed to pay a civil penalty and refunds totaling $5.75 million in conjunction with the settlement, which also eliminated the potential for any civil action or prolonged regulatory proceedings. The matters resolved related to periods prior to the October 1999 K N Energy-Kinder Morgan merger and, to some extent, periods prior to K N Energy's January 1998 acquisition of MidCon Corp., including the January 1997 complaint of Amoco Production Company and Amoco Energy Trading Corporation against Natural Gas Pipeline Company of America. The payment had no detrimental effect on our earnings due to the existence of previously established reserves for this matter. 10 11 ITEMS 1 and 2: BUSINESS and PROPERTIES (continued) 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, 2000, the plan had been adopted by 178 of 181 communities, representing approximately 91,000 customers served by us in Nebraska. 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 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 difficult and costly to comply with and which carry substantial penalties for failure to comply. These laws and regulations can also impose liability for remedial costs on the owner or operator of properties or the generators of waste materials, regardless of fault. Moreover, the recent trends toward stricter standards in environmental legislation and regulation are likely to continue. On December 20, 1999, the U.S. Department of Justice filed a Complaint against Natural Gas Pipeline Company of America on behalf of the U.S. Environmental Protection Agency in the Federal District Court of Colorado, Civil Action 99-S-2419. The Complaint alleged that Natural Gas Pipeline Company of America failed to obtain all of the necessary air quality permits in 1979 when it constructed the Akron Compressor Station, which consisted of three compressor engines in Weld County, Colorado. Natural Gas Pipeline Company of America and the Environmental Protection Agency, through the Department of Justice, have settled this issue. On December 17, 1999, the State of Colorado notified us of air quality permit compliance issues for several Kinder Morgan facilities. On September 21, 2000, we entered into a consent order with the State of Colorado to resolve the outstanding issues. In 1998, the Environmental Protection Agency published a final rule addressing transport of ground level ozone. The rule affected 22 Eastern and Midwestern states, including Illinois and Missouri, in which we operate gas compression facilities. The rule required reductions in emissions of nitrogen oxide, a precursor to ozone formation, from various emission sources, including utility and non-utility sources. The rule required that the affected states prepare and submit State Implementation Plans to the Environmental Protection Agency 11 12 ITEMS 1 and 2: BUSINESS and PROPERTIES (continued) by September 1999, reflecting how the required emissions reductions would be achieved. Emission controls are required to be installed by May 1, 2003. The State Implementation Plans which will effectuate this rule have yet to be proposed or promulgated, and will require detailed analysis before their final economic impact can be ascertained. On March 3, 2000, the Washington D.C. Circuit Court issued a decision regarding the rule. The Circuit Court remanded certain issues back to the Environmental Protection Agency. On January 5, 2001, the Environmental Protection Agency proposed regulations concerning the remanded issues. The final regulations are expected to be promulgated later this year. While additional capital costs are likely to result from this rule, based on currently available information, we do not believe that these costs will have a material adverse effect on our business, cash flows, financial position or results of operations. On June 17, 1999, the Environmental Protection Agency published a final rule creating a standard to limit emissions of hazardous air pollutants from oil and natural gas production as well as from natural gas transmission and storage facilities. The standard requires that the affected facilities reduce emissions of hazardous air pollutants by 95 percent. This standard will require us to achieve this reduction either by process modifications or by installing new emissions control technology. The standard will affect our competitors and us in a like manner. The rule allows affected sources three years from the publication date to come into compliance. We have conducted a detailed analysis of the final rule to determine its overall effect. While additional capital costs are likely to result from this rule, the rule will not have a material adverse effect on our business, cash flows, financial position or results of operations. We have an established environmental reserve of approximately $19 million to address remediation issues associated with 38 projects. Based on current information and taking into account reserves established for environmental matters, we do not believe that compliance with federal, state and local environmental laws and regulations will have a material adverse effect on our business, cash flows, financial position or results of operations. In addition, the clean-up programs in which we are engaged are not expected to interrupt or diminish our operational ability to gather or transport natural gas. However, there can be no assurances that future events, such as changes in existing laws, the promulgation of new laws, or the development of new facts or conditions will not cause us to incur significant costs. Other Amounts we spent during 2000, 1999, and 1998 on research and development activities were not material. (C) Financial Information About Foreign and Domestic Operations and Export Sales Substantially all of our operations are in the contiguous 48 states. 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 and several of its 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, tortuous 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 stems from Questar's failure to support the TransColorado partnership, together with its decision to seek regulatory approval for a project that competes with the Partnership, in breach of 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 certain of our entities and us for claims arising out of the construction and operation of the 12 13 ITEM 3: LEGAL PROCEEDINGS (continued) 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. On December 15, 2000, 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. On January 31, 2001, 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. Discovery has commenced. "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. No trial date has been set. However, recent settlement conferences have occurred. "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 gas, mismeasured gas, delayed his development of gas reserves, and other claims arising out of a contract to purchase gas from a field in northwest Colorado. On February 13, 1997, the trial judge entered partial summary judgment for Mr. Grynberg on his contract claim that he failed to receive the proper price for his 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 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 gas to interstate commerce. The background of that proceeding is described in the immediately following paragraph. On March 15, 1999, an Administrative Law Judge for the FERC ruled, after an evidentiary hearing, that Mr. Grynberg had illegally diverted the 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. Grynberg recently filed a Notice of Appeal of the FERC's decision to the D.C. Circuit Court of Appeals. The action in Colorado remains stayed pending final resolution of these proceedings. "Jack J. Grynberg v. Rocky Mountain Natural Gas Company," Docket No. GP91-8-008. "Rocky Mountain Natural Gas Company v. Jack J. Grynberg," Docket No. GP91-10-008. On May 8, 1991, Grynberg filed a petition for declaratory order with the FERC seeking a determination whether he was entitled to the price he seeks in the Jefferson County District Court proceeding referred to in the immediately preceding paragraph. While 13 14 ITEM 3: LEGAL PROCEEDINGS (continued) Grynberg initially received a favorable decision from the FERC, that decision was reversed by the Court of Appeals for the District of Columbia Circuit on June 6, 1997. This matter has been remanded to the FERC for subsequent proceedings. The matter was set for an expedited evidentiary hearing, and an Initial Decision favorable to Rocky Mountain was issued on March 15, 1999. That decision determined that Grynberg had intentionally diverted gas from an earlier dedication to interstate commerce in violation of the Natural Gas Act and denied him equitable administrative relief. On November 21, 2000, the FERC upheld the Administrative Law Judge's factual findings and denial of retroactive abandonment. Grynberg recently filed a Notice of Appeal of the FERC's decision to the D.C. Circuit Court of Appeals. "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 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. "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 purport to represent a class of natural gas producers and fee royalty owners who allege that they have been subject to systematic gas mismeasurement by the defendants for more than 25 years. 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 Motion to Reconsider the remand was filed and is currently pending. "Dirt Hogs, Inc. v. Natural Gas Pipeline Company of America, et al." There have been several related cases with Dirt Hogs, Inc. with allegations of breach of contract, false representations, improper requests for kickbacks and other improprieties. Essentially, the plaintiff claims that it should have been awarded extensive pipeline reclamation work without having to qualify or bid as a qualifying contractor. Case No. Civ-98-231-R, is a case which was dismissed in the U.S. District Court for the Western District of Oklahoma because of pleading deficiencies and is now on appeal to the 10th Circuit (Case No. 99-6-026). On April 10, 2000, the 10th Circuit upheld the dismissal of this action. Another case, arising out of the same factual allegations, was filed by Dirt Hogs in the District Court, Caddo County, Oklahoma (Case No. CJ-99-92), on March 29, 1999. By agreement of all parties, this action is currently stayed. A third related case, styled "Natural Gas Pipeline Company of America, et al. v. Dirt Hogs, Inc." (Case No. 99-360-R), resulted in a default judgment against Dirt Hogs. After initially appealing the default judgment, Dirt Hogs dismissed their appeal on September 1, 1999. "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. Defendants counterclaimed and filed third party claims against several of our former officers and/or directors. Messrs. Rode and McDonald are former principal shareholders 14 15 ITEM 3: LEGAL PROCEEDINGS (continued) 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. 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 February 23, 2001, the federal district court dismissed this Complaint with prejudice. 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 other remaining claims, without prejudice. 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 business, cash flows, financial position or results of operations. ITEM 4: SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None 15 16 EXECUTIVE OFFICERS OF THE REGISTRANT (A) Identification and Business Experience of Executive Officers Name Age Position and Business Experience ---- --- -------------------------------- Richard D. Kinder................ 56 Director, Chairman and Chief Executive Officer since October 1999. Director, Chairman and Chief Executive Officer of Kinder Morgan G.P., Inc. since February 1997. From 1992 to 1994, Chairman of Kinder Morgan G.P., Inc. From October 1990 until December 1996, President of Enron Corp. Mr. Kinder was employed by Enron and its affiliates and predecessors for over 16 years. William V. Morgan................ 57 Director, Vice Chairman and President since October 1999. Director of Kinder Morgan G.P., Inc. since June 1994. Vice Chairman of Kinder Morgan G.P., Inc. since February 1997. President of Kinder Morgan G.P., Inc. since November 1998. President of Morgan Associates, Inc., an investment and pipeline management company, since February 1987. Legal and management positions in the energy industry since 1975, including the presidencies of three major interstate natural gas companies, which are now part of Enron Corp.: Florida Gas Transmission Company, Transwestern Pipeline Company and Northern Natural Gas Company. Prior to joining Florida Gas in 1975, Mr. Morgan was engaged in the private practice of law in Washington, D.C. William V. Allison............... 53 President, Natural Gas Pipeline Operations since September 1999. President, Pipeline Operations of Kinder Morgan Energy Partners from February 1999 to September 1999. Vice President and General Counsel of Kinder Morgan Energy Partners from April 1998 to February 1999. From 1997 to April 1998, Mr. Allison was employed at Enron Corp. where he held various executive positions, including President of Enron Liquid Services Corporation, Florida Gas Transmission Company and Houston Pipeline Company and Vice President and Associate General Counsel of Enron Corp. Prior to joining Enron Corp. he was an attorney at the FERC. David G. Dehaemers, Jr........... 40 Vice President of Corporate Development since January 2000. Vice President and Chief Financial Officer from October 1999 to January 2000. Also Vice President, Corporate Development of Kinder Morgan G.P., Inc. since January 2000. Treasurer of Kinder Morgan G.P., Inc. from February 1997 to January 2000. Vice President and Chief Financial Officer of Kinder Morgan G.P., Inc. from July 1997 to January 2000. Secretary of Kinder Morgan G.P., Inc. from February 1997 to August 1997. Chief Financial Officer of Morgan Associates, Inc., an energy investment and pipeline management company, from October 1992 to January 1997. 16 17 EXECUTIVE OFFICERS OF THE REGISTRANT (continued) Joseph Listengart................ 32 Vice President, General Counsel and Secretary since October 1999. Also Vice President and General Counsel of Kinder Morgan G.P., Inc. since October 1999. Mr. Listengart became an employee of Kinder Morgan G.P., Inc. in March 1998 and was elected its Secretary in November 1998. From March 1995 through February 1998, Mr. Listengart worked as an attorney for Hutchins, Wheeler & Dittmar, a Professional Corporation. Michael C. Morgan................ 32 Vice President, Strategy and Investor Relations since January 2000. Also Vice President, Strategy and Investor Relations of Kinder Morgan G.P., Inc. since January 2000. Vice President of Corporate Development of Kinder Morgan G.P., Inc. from February 1997 to January 2000. From August 1995 until February 1997, an associate with McKinsey & Company, an international management consulting firm. Son of William V. Morgan. C. Park Shaper................... 32 Vice President and Chief Financial Officer since January 2000. Treasurer since April 2000. Also Vice President, Treasurer and Chief Financial Officer of Kinder Morgan G.P., Inc. since January 2000. Previously, President and Director of Altair Corporation, an enterprise focused on the distribution of web-based investment research for the financial services industry. Vice President and Chief Financial Officer of First Data Analytics, a subsidiary of First Data Corporation, from 1997 to June 1999. From 1995 to 1997, a consultant with The Boston Consulting Group. Previous experience with TeleCheck Services, Inc. and as a management consultant with the Strategic Services Division of Andersen Consulting. James E. Street.................. 44 Vice President of Human Resources and Administration since August 1999. Also Vice President, Human Resources and Administration of Kinder Morgan G.P., Inc., since August 1999. Senior Vice President, Human Resources and Administration for Coral Energy, a subsidiary of Shell Oil Company, from October 1996 to August 1999. Vice President, Human Resources of Enron Corp. from July 1989 to August 1992. These officers generally serve until April of each year. (B) Involvement in Certain Legal Proceedings None. 17 18 PART II ITEM 5: MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER 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 DATA -------------------------------------------------------------------------------------- 2000 1999 --------------------------------------- -------------------------------------- LOW HIGH CLOSE LOW HIGH CLOSE --- ---- ----- --- ---- ----- Quarter Ended: March 31 $19.875 $34.500 $34.500 $19.813 $21.375 $19.938 June 30 $29.188 $34.938 $34.563 $12.188 $22.438 $13.375 September 30 $31.625 $41.688 $40.938 $12.188 $24.688 $22.438 December 31 $37.063 $54.250 $52.188 $17.125 $24.500 $20.188 Dividends Quarter Ended: March 31 $0.05 $0.20 June 30 $0.05 $0.20 September 30 $0.05 $0.20 December 31 $0.05 $0.05 Common Stockholders at Year-end 9,326 10,397
18 19 ITEM 6: SELECTED FINANCIAL DATA FIVE-YEAR REVIEW KINDER MORGAN, INC. AND SUBSIDIARIES (In Thousands Except Per Share Amounts)
YEAR ENDED DECEMBER 31, ----------------------------------------------------------------------------------- 2000 1999 (1,)(3) 1998 (1,)(4) 1997 1996 ---------- ------------ ------------ ---------- ---------- Operating Revenues $2,713,737 $1,836,368 $1,660,259 $ 340,685 $ 299,608 Gas Purchases and Other Costs of Sales 1,960,083 1,050,250 836,614 134,476 102,725 ---------- ---------- ---------- ---------- ---------- Gross Margin 753,654 786,118 823,645 206,209 196,883 Other Operating Expenses 358,511 490,416 427,953 128,059 128,895 ---------- ---------- ---------- ---------- ---------- OPERATING INCOME 395,143 295,702 395,692 78,150 67,988 Other Income and (Expenses) (88,701) (49,311) (172,787) (21,039) (14,798) ---------- ---------- ---------- ---------- ---------- Income From Continuing Operations Before Income Taxes 306,442 246,391 222,905 57,111 53,190 Income Taxes 122,727 90,733 82,710 12,777 17,304 ---------- ---------- ---------- ---------- ---------- INCOME FROM CONTINUING OPERATIONS 183,715 155,658 140,195 44,334 35,886 Gain (Loss) From Discontinued Operations, Net of Tax (31,734) (395,319) (77,984) 33,163 27,933 ---------- ---------- ---------- ---------- ---------- NET INCOME (LOSS) 151,981 (239,661) 62,211 77,497 63,819 Less-Preferred Dividends -- 129 350 350 398 Less-Premium Paid on Preferred Stock Redemption -- 350 -- -- -- ---------- ---------- ---------- ---------- ---------- EARNINGS (LOSS) AVAILABLE FOR COMMON STOCK $ 151,981 $ (240,140) $ 61,861 $ 77,147 $ 63,421 ========== ========== ========== ========== ========== Number of Shares Used in Computing Basic Earnings Per Common Share 114,063 80,284 64,021 46,589 43,653 ========== ========== ========== ========== ========== BASIC EARNINGS (LOSS) PER COMMON SHARE: Continuing Operations $ 1.61 $ 1.93 $ 2.19 $ 0.95 $ 0.81 Discontinued Operations (0.28) (4.92) (1.22) 0.71 0.64 ---------- ---------- ---------- ---------- ---------- Total Basic Earnings (Loss) Per Common Share $ 1.33 $ (2.99) $ 0.97 $ 1.66 $ 1.45 ========== ========== ========== ========== ========== Number of Shares Used in Computing Diluted Earnings Per Common Share 115,030 80,358 64,636 47,307 44,436 ========== ========== ========== ========== ========== DILUTED EARNINGS (LOSS) PER COMMON SHARE: Continuing Operations $ 1.60 $ 1.93 $ 2.17 $ 0.93 $ 0.80 Discontinued Operations (0.28) (4.92) (1.21) 0.70 0.63 ---------- ---------- ---------- ---------- ---------- Total Diluted Earnings (Loss) Per Common Share $ 1.32 $ (2.99) $ 0.96 $ 1.63 $ 1.43 ========== ========== ========== ========== ========== DIVIDENDS PER COMMON SHARE $ 0.20 $ 0.65 $ 0.76 $ 0.73 $ 0.70 ========== ========== ========== ========== ========== CAPITAL EXPENDITURES (2) $ 137,477 $ 97,644 $ 120,881 $ 230,814 $ 88,755 ========== ========== ========== ========== ========== TOTAL ASSETS (5) $8,418,105 $9,425,674 $9,623,779 $2,305,805 $1,629,720 ========== ========== ========== ========== ========== CAPITALIZATION (5): Common Stockholders' Equity $1,797,421 40% $1,669,846 32% $1,219,043 25% $ 606,132 48% $ 519,794 55% Preferred Stock -- -- -- -- 7,000 -- 7,000 -- 7,000 1% Preferred Capital Trust Securities 275,000 6% 275,000 5% 275,000 6% 100,000 8% -- -- Long-Term Debt 2,478,983 54% 3,293,326 63% 3,300,025 69% 553,816 44% 423,676 44% ---------- --- ---------- --- ---------- --- ---------- --- ---------- --- Total Capitalization $4,551,404 100% $5,238,172 100% $4,801,068 100% $1,266,948 100% $ 950,470 100% ========== === ========== === ========== === ========== === ========== === BOOK VALUE PER COMMON SHARE(5) $ 15.70 $ 14.82 $ 17.77 $ 12.63 $ 11.44 ========== ========== ========== ========== ==========
(1) Restated, see Note 2 of the accompanying Notes to Consolidated Financial Statements. (2) Capital Expenditures shown are for continuing operations only. (3) Reflects the acquisition of Kinder Morgan Delaware on October 7, 1999. See Note 2 of the accompanying Notes to Consolidated Financial Statements. (4) Reflects the acquisition of MidCon Corp. on January 30, 1998. See Note 2 of the accompanying Notes to Consolidated Financial Statements. (5) At December 31 of each respective year 19 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 and 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 2, 5 and 6 of the accompanying Notes to Consolidated Financial Statements, we have engaged in acquisitions (including the October 1999 acquisition of Kinder Morgan (Delaware), Inc., a Delaware corporation and 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 midstream 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 have effectively completed the disposition of these assets and operations, all as more fully described in Note 6 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 1999 and 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, have 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, 2000, we owned approximately 14.0 million limited partner units of Kinder Morgan Energy Partners, representing approximately 20.7% 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 49% 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. By increasing our stake in Kinder Morgan Energy Partners, we expect to receive additional future cash distributions from Kinder Morgan Energy Partners through incremental general partner incentive distributions as well as increased limited partner distributions due to our ownership of additional common units received as compensation in the transfers. 20 21 ITEM 7: MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) After the dispositions discussed above, our largest business unit and our primary source of operating income is Natural Gas Pipeline Company of America (NGPL), a major interstate natural gas pipeline system 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 agreements to fully utilize the transportation and storage capacity of Natural Gas Pipeline Company of America with the result that Natural Gas Pipeline Company of America sold out its capacity through the year 2000-2001 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 remaining business operations consist of the retail distribution of natural gas to approximately 218,000 customers in several Western and Midwestern states and the construction and operation of electric power generation facilities. Our retail natural gas distribution properties are located, in part, in areas where significant growth is occurring and we expect to participate in that growth through increased natural gas demand. The nation's demand for additional electric power generation is significant and immediate. Our power generation business has a beneficial master turbine purchase agreement that it plans to utilize in constructing a number of natural gas-fired electric generation facilities to help meet this need. 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. Even though we have made significant progress to date, we believe that opportunities remain for increasing shareholder value through cost reductions and other efficiency improvements with respect to both existing assets and future acquisitions. One measure intended to increase shareholder value is the All Employee Stock Option Plan implemented in October 1999. Through this plan, virtually all employees, with the exception of Richard D. Kinder and William V. Morgan (each of whom is currently a major shareholder), have received options to purchase shares of our common stock. Richard D. Kinder, our Chairman and Chief Executive Officer, and William V. Morgan, our Vice Chairman and President, each receive only $1 per year in salary and do not receive bonuses. By aligning employee incentives with shareholder value, we expect to increase employee productivity, retention and satisfaction. We believe these factors ultimately contribute to increased earnings and overall shareholder value. To reduce debt and provide funds for future growth, we reduced the regular quarterly common dividend from $0.20 per share to $0.05 per share in the fourth quarter of 1999 and have maintained it at that level. The final aspect of our strategy is benefiting 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 population of potential acquisition candidates being driven by consolidation in the energy industry, as well as rationalization of asset portfolios by major corporations. 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, acquire natural gas distribution properties that fit well with the current profile and build and acquire incremental power generation facilities. 21 22 ITEM 7: MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) CONSOLIDATED FINANCIAL RESULTS
YEAR ENDED DECEMBER 31, ----------------------------------------------------- 2000 1999 1998 ---- ---- ---- (In Thousands Except Per Share Amounts) Operating Revenues $ 2,713,737 $ 1,836,368 $ 1,660,259 =========== =========== =========== Gross Margin(1) $ 753,654 $ 786,118 $ 823,645 =========== =========== =========== Operating Income: Before Merger-related and Severance Costs $ 395,143 $ 333,145 $ 401,455 Merger-related and Severance Costs -- (37,443) (5,763) ----------- ----------- ----------- Consolidated Operating Income $ 395,143 $ 295,702 $ 395,692 =========== =========== =========== Income from Continuing Operations: Before Merger-related and Severance Costs and Gains from Sales of Assets, Net of Tax $ 146,735 $ 58,848 $ 131,416 Merger-related and Severance Costs, Net of Tax -- (23,327) (3,518) Gains from Sales of Assets, Net of Tax 36,980 120,137 12,297 ----------- ----------- ----------- Income from Continuing Operations 183,715 155,658 140,195 ----------- ----------- ----------- Discontinued Operations, Net of Tax: Loss from Discontinued Operations -- (50,941) (77,984) Loss on Disposal of Discontinued Operations (31,734) (344,378) -- ----------- ----------- ----------- Discontinued Operations, Net of Tax (31,734) (395,319) (77,984) ----------- ----------- ----------- Net Income (Loss) $ 151,981 $ (239,661) $ 62,211 =========== =========== =========== Diluted Earnings (Loss) Per Share: From Continuing Operations Before Merger-related and Severance Costs and Gains from Sales of Assets $ 1.28 $ 0.73 $ 2.03 Merger-related and Severance Costs -- (0.29) (0.05) Gains from Sales of Assets 0.32 1.49 0.19 Loss from Discontinued Operations -- (0.63) (1.21) Loss on Disposal of Discontinued Operations (0.28) (4.29) -- ----------- ----------- ----------- Diluted Earnings (Loss) Per Share $ 1.32 $ (2.99) $ 0.96 =========== =========== =========== Number of Shares Used in Computing Diluted Earnings Per Common Share 115,030 80,358 64,636 =========== =========== ===========
(1) Gross margin equals total operating revenues less gas purchases and other costs of sales. Our results for 2000, in comparison to 1999, reflect an increase of $877.4 million in operating revenues, a decrease of $32.5 million in gross margin and an increase of $62.0 million in operating income before merger-related and severance costs. The increase in operating revenues is principally due to (i) increased natural gas sales volumes and prices on the Kinder Morgan Texas Pipeline, L.P. system (transferred to Kinder Morgan Energy Partners in December 2000), (ii) weather-related increases in natural gas sales and transportation volumes on Kinder Morgan Retail's system and (iii) increased storage service revenues and operational gas sales from Natural Gas Pipeline Company of America, partially offset by the exclusion from 2000 results of the operations of Kinder Morgan Interstate Gas Transmission LLC. Kinder Morgan Interstate Gas Transmission was contributed to Kinder Morgan Energy Partners at December 31, 1999, while Kinder Morgan Texas Pipeline was contributed to Kinder Morgan Energy Partners at December 31, 2000. These transactions are described in Note 5 of the accompanying Notes to Consolidated Financial Statements. The decrease in gross margin that occurred from 1999 to 2000, despite the increased operating revenues, was principally due to the fact that 2000 results do not include the results of Kinder Morgan Interstate Gas Transmission LLC. Results for 1999 and 1998 included merger-related and severance costs as further discussed in Note 3 of the accompanying Notes to Consolidated Financial Statements. The individual business unit sections that follow contain more details concerning the comparison of these results down to the level of operating income. 22 23 ITEM 7: MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) Below the operating income line, results for 2000, 1999 and 1998 included significant gains from the sale of assets. Results for 2000 and 1999 included equity in earnings (and associated amortization of excess investment) associated with our October 1999 acquisition of Kinder Morgan Delaware. Interest expense increased significantly in 1999 due, in large part, to the January 1998 acquisition of MidCon Corp., and declined in 2000 largely due to reduced short-term borrowing levels as a result of applying cash received from asset sales. Additional information on these non-operating income and expense items is included under "Other Income and (Expenses)" following, and information concerning the acquisitions and asset sales is contained in Notes 2 and 5 of the accompanying Notes to Consolidated Financial Statements. Diluted earnings per common share from continuing operations before merger-related and severance costs and gains from sales of assets increased from $0.73 per share in 1999 to $1.28 per share in 2000. In addition to the operating and financing factors described preceding, this increase also reflects an increase of 34.7 million (43.1%) in average diluted shares outstanding, largely due to shares issued in conjunction with the acquisition of Kinder Morgan Delaware discussed above. Diluted earnings per common share increased from a loss of $2.99 per common share in 1999 to earnings of $1.32 per common share in 2000, reflecting, in addition to the factors discussed preceding, the impact of discontinued operations, including losses on disposal of discontinued operations, in each period. See "Discontinued Operations" following and Note 6 of the accompanying Notes to Consolidated Financial Statements. RESULTS OF OPERATIONS We manage our various businesses by, among other things, allocating capital and monitoring operating performance. This management process includes dividing the overall Company into business units 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 units:
BUSINESS UNIT BUSINESS CONDUCTED REFERRED TO AS: - ------------- ------------------ --------------- Natural Gas Pipeline Company of Major interstate natural gas pipeline and Natural Gas Pipeline America and certain affiliates storage system Company of America Retail Natural Gas Distribution The regulated sale of natural gas to Kinder Morgan Retail residential, commercial and industrial customers and non-utility sales of natural gas to certain utility customers under the Choice Gas Program Power Generation and Other The construction and operation of natural Power and Other 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, 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 sale of Kinder Morgan Interstate Gas Transmission LLC, referred to in this report as "Kinder Morgan Interstate," to Kinder Morgan Energy Partners and (ii) the December 2000 sale of Kinder Morgan Texas Pipeline, L.P., referred to in this report as "Kinder Morgan Texas Pipeline," 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 under "General" in this portion of the Form 10-K and in Note 5 of the accompanying Notes to Consolidated Financial Statements. 23 24 ITEM 7: MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) The accounting policies applied in the generation of business unit information are generally the same as those described in Note 1 to the accompanying Consolidated Financial Statements, except that items below the "Operating Income" line are either not allocated to business units or are not considered by Management in its evaluation of business unit performance. An exception to this is that 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 business unit operating results. These equity-method earnings are included in "Other Income and (Expenses)" in our consolidated income statement. In addition, certain items included in consolidated operating income (such as merger-related and severance costs and general and administrative expenses) are not allocated to individual business units. With adjustment for these items, we currently evaluate business unit performance primarily based on operating income in relation to the level of assets employed. Sales between business units are accounted for at market prices. For comparative purposes, prior period results and balances have been reclassified as necessary to conform to the current presentation. Following are operating results by individual business unit (before intersegment eliminations), including explanations of significant variances between the periods presented. NATURAL GAS PIPELINE COMPANY OF AMERICA Operating results for Natural Gas Pipeline Company of America are included in our consolidated results beginning with the January 30, 1998 acquisition of MidCon Corp. See Note 2 of the accompanying Notes to Consolidated Financial Statements for more information regarding this acquisition.
YEAR ENDED DECEMBER 31, --------------------------------------------------- 2000 1999 1998 ---- ---- ---- (In Thousands Except Systems Throughput) Operating Revenues $656,017 $626,888 $556,961 -------- -------- -------- Operating Costs and Expenses: Gas Purchases and Other Costs of Sales 145,431 115,481 24,273 Operations and Maintenance 62,582 72,979 59,055 Depreciation and Amortization 84,975 109,346 121,008 Taxes, Other Than Income Taxes 20,142 22,575 15,800 -------- -------- -------- 313,130 320,381 220,136 -------- -------- -------- Operating Income Before Corporate Costs $342,887 $306,507 $336,825 ======== ======== ======== Systems Throughput (Trillion Btus) 1,459.3 1,449.9 1,296.6 ======== ======== ========
Natural Gas Pipeline Company of America's operating income before corporate costs increased by $36.4 million (11.9%) 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 gas prices on Natural Gas Pipeline Company of America's operational 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 4 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 both existing and planned competing pipeline capacity (with the attendant reduced value of transportation) 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. Note 5 of the accompanying Notes to Consolidated Financial Statements contains additional information concerning asset sales. 24 25 ITEM 7: MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) Natural Gas Pipeline Company of America's operating income before corporate costs decreased by $30.3 million (9.0%) from 1998 to 1999. Natural Gas Pipeline Company of America was negatively impacted in 1999, relative to 1998, by (i) a decrease in the margin per MMBtu of throughput from $0.41 in 1998 to $0.35 in 1999 resulting from (1) two recent mild winters, including the impact of the resultant high levels of gas in underground storage and (2) increased competitive pressures in Midwest markets due to actual or projected supply increases and (ii) increased operations and maintenance expenses and property taxes. These negative impacts were partially offset by (i) an increase in average monthly throughput volumes from 118 trillion Btus in 1998 to 121 trillion Btus in 1999 (although, in general, interstate pipelines receive the majority of their transportation revenues from demand charges, which are not affected by the level of throughput), (ii) reduced amortization expense in 1999 resulting from a change in the estimated useful life of Natural Gas Pipeline Company of America's assets (see Note 4 of the accompanying Notes to Consolidated Financial Statements) and (iii) the fact that our 1999 results included 12 months of the operations of Natural Gas Pipeline Company of America, while our 1998 results included only 11 months. KINDER MORGAN INTERSTATE We transferred Kinder Morgan Interstate Gas Transmission LLC to Kinder Morgan Energy Partners effective December 31, 1999. See Note 5 of the accompanying Notes to Consolidated Financial Statements for more information regarding this transaction.
YEAR ENDED DECEMBER 31, ---------------------------------------- 1999 1998 ---- ---- (In Thousands Except Systems Throughput) Operating Revenues: Transportation and Storage $112,732 $105,160 Other 475 417 -------- -------- 113,207 105,577 -------- -------- Operating Costs and Expenses: Gas Purchases and Other Costs of Sales 13,954 3,763 Operations and Maintenance 23,737 20,026 Depreciation and Amortization 16,985 19,474 Taxes, Other Than Income Taxes 4,607 4,308 -------- -------- 59,283 47,571 -------- -------- Operating Income Before Corporate Costs $ 53,924 $ 58,006 ======== ======== Systems Throughput (Trillion Btus) 203.1 216.6 ======== ========
Kinder Morgan Interstate's operating income before corporate costs decreased by $4.1 million (7.0%) from 1998 to 1999. This business unit was negatively impacted in 1999, relative to 1998, by (i) the 1999 write-off of approximately $5.8 million of deferred fuel tracker costs that had accumulated since the initial implementation of FERC Order No. 636 and were deemed unrecoverable due to the settlement of the general rate case; (see Note 8 of the accompanying Notes to Consolidated Financial Statements for more information regarding Kinder Morgan Interstate's general rate case), (ii) a decrease in shipper supplied fuel requirements under the terms of Kinder Morgan Interstate's general rate case which, in conjunction with normal system fuel and loss requirements, caused Kinder Morgan Interstate to purchase additional system fuel supplies and (iii) increased operations and maintenance expenses, primarily related to the Pony Express Pipeline. These negative impacts were partially offset by (i) increased revenues in 1999 due to higher transportation rates under the terms of the general rate case and (ii) reduced depreciation expense in 1999 resulting from the assets of Kinder Morgan Interstate being classified as assets held for sale effective November 1, 1999, at which time further depreciation of these assets was suspended in accordance with the provisions of SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of". 25 26 ITEM 7: MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) KINDER MORGAN RETAIL
YEAR ENDED DECEMBER 31, -------------------------------------------------- 2000 1999 1998 ---- ---- ---- (In Thousands Except Systems Throughput) Operating Revenues: Gas Sales $171,696 $134,208 $186,527 Transportation 41,371 34,919 27,309 Other 16,442 13,785 20,470 -------- -------- -------- 229,509 182,912 234,306 -------- -------- -------- Operating Costs and Expenses: Gas Purchases and Other Costs of Sales 128,811 107,264 123,099 Operations and Maintenance 36,627 40,807 41,093 Depreciation and Amortization 11,776 11,382 11,014 Taxes, Other Than Income Taxes 2,563 3,355 2,886 -------- -------- -------- 179,777 162,808 178,092 -------- -------- -------- Operating Income Before Corporate Costs $ 49,732 $ 20,104 $ 56,214 ======== ======== ======== Systems Throughput (Trillion Btus) 72.6 56.6 61.7 ======== ======== ========
Kinder Morgan Retail's operating income before corporate costs increased by $29.6 million (147.4%) 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, (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. Kinder Morgan Retail's operating income before corporate costs decreased by $36.1 million (64.2%) from 1998 to 1999. This business unit was negatively impacted in 1999, relative to 1998, by (i) the fact that 1998 results include three months of the operations of distribution assets in Kansas that were sold in March 1998 (see Note 5 of the accompanying Notes to Consolidated Financial Statements) and (ii) reduced margins from sales and transportation due primarily to (1) weather-related reductions in 1999 irrigation demand and (2) reduced margins related to the Nebraska Choice Gas program. KINDER MORGAN TEXAS PIPELINE Operating results for Kinder Morgan Texas Pipeline are included in our consolidated results beginning with the January 30, 1998 acquisition of MidCon Corp. See Note 2 of the accompanying Notes to Consolidated Financial Statements for more information regarding this acquisition. In December 2000, we transferred Kinder Morgan Texas Pipeline to Kinder Morgan Energy Partners. See Note 5 of the accompanying Notes to Consolidated Financial Statements for more information regarding this transaction. 26 27 ITEM 7: MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
YEAR ENDED DECEMBER 31, ------------------------------------------------------ 2000 1999 1998 ---- ---- ---- (In Thousands Except Systems Throughput) Operating Revenues: Gas Sales $1,675,206 $ 815,557 $ 704,190 Transportation 25,468 23,971 19,192 Other 46,825 32,633 15,819 ---------- ---------- ---------- 1,747,499 872,161 739,201 ---------- ---------- ---------- Operating Costs and Expenses: Gas Purchases and Other Costs of Sales 1,666,169 804,674 680,766 Operations and Maintenance 45,401 45,778 51,067 Depreciation and Amortization 2,211 2,466 1,615 Taxes, Other Than Income Taxes 4,400 2,689 3,624 ---------- ---------- ---------- 1,718,181 855,607 737,072 ---------- ---------- ---------- Operating Income Before Corporate Costs $ 29,318 $ 16,554 $ 2,129 ========== ========== ========== Systems Throughput (Trillion Btus) 654.4 575.3 581.6 ========== ========== ==========
Operating revenues for Kinder Morgan Texas Pipeline increased by $875.3 million (100.4%) from 1999 to 2000. The $859.6 million (105.4%) increase in natural gas sales reflected a 75% increase in the average sales price during 2000, together with a 17% increase in sales volumes. The $14.2 million increase in other revenues was principally due to a 55% increase in the average sales price of natural gas liquids during 2000. Gross margin (operating revenues minus gas purchases and other costs of sales) increased by $13.8 million (20.5%) from 1999 to 2000, as the increased operating revenues were offset approximately proportionally by the increased cost of natural gas purchased. Operating income before corporate costs increased by $12.8 million (77.1%) from 1999 to 2000 as the increase in gross margin discussed preceding was partially offset by increased ad valorem taxes. Kinder Morgan Texas Pipeline's operating income before corporate costs increased by $14.4 million from 1998 to 1999. This business unit was positively impacted in 1999, relative to 1998, by (i) the fact that 1999 results include 12 months of the operations of Kinder Morgan Texas Pipeline, while 1998 results include only 11 months, (ii) increased per unit margins from sales and transportation in 1999, (iii) increased 1999 margins from natural gas liquids sales due to an improved pricing environment, (iv) reduced 1999 operations and maintenance expenses and (v) reduced 1999 ad valorem taxes. These positive impacts were partially offset by (i) reduced 1999 overall systems throughput volumes and (ii) increased 1999 depreciation expense reflecting the cumulative impact of capital expenditures made in 1998 and 1999. 27 28 TEM 7: MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) POWER AND OTHER
YEAR ENDED DECEMBER 31, ------------------------------------------------- 2000 1999 1998 ---- ---- ---- (In Thousands) Operating Revenues $80,697 $59,305 $47,380 Equity in Earnings of Equity Investments 3,669 10,511 8,675 ------- ------- ------- 84,366 69,816 56,055 ------- ------- ------- Operating Costs and Expenses: Gas Purchases and Other Costs of Sales 19,653 12,921 19,441 Operations and Maintenance 19,680 15,648 7,232 Depreciation and Amortization 9,203 7,754 2,252 Taxes, Other Than Income Taxes 868 1,335 1,672 ------- ------- ------- 49,404 37,658 30,597 ------- ------- ------- Income Before Corporate Costs $34,962 $32,158 $25,458 ======= ======= =======
Results of power generation operations are included in Power and Other beginning with the acquisition of interests in power plants from the Denver-based Thermo Companies, which acquisition was completed in the third quarter of 1998. See Note 2 of the accompanying Notes to Consolidated Financial Statements for more information concerning this acquisition. Income before corporate costs from Power and Other increased $2.8 million (8.7%) from 1999 to 2000. Operating results for 2000 were positively impacted, relative to 1999, by profits from development of a 550-megawatt electric generating plant currently being constructed by Power near Little Rock, Arkansas. Kinder Morgan Power is receiving a development fee and profit from turn-key construction of the plant (which is owned by a unit of the Southern Company), which is being recorded as revenue over the two-year construction period. The positive impact related to profits from construction of the Little Rock, Arkansas power generation facility was partially offset 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 agreement with HS Resources, Inc. and certain telecommunications assets used primarily by internal business units. As we announced on November 30, 1999, we have entered into agreements with HS Resources, Inc. for the sale of certain assets in the Wattenberg field area of the Denver-Julesberg Basin. Under the terms of the agreements, HS Resources, Inc. commenced operating these assets. We are receiving payments from HS Resources, Inc. during 2000 and 2001, with the legal transfer of ownership expected to occur on or before December 15, 2001. Loss before Corporate Costs for our international activities, included in this business unit, was $1.9 million, $1.9 million and $0.4 million in 2000, 1999 and 1998, respectively. Income before corporate costs from Power and Other increased $6.7 million (26.3%) from 1998 to 1999. Operating results for 1999 were positively impacted, relative to 1998, by (i) 1999 results include a full year of power generation activities, while 1998 includes only partial year results and (ii) increased 1999 operating income from our agreement with HS Resources, as described above. 28 29 ITEM 7: MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) OTHER INCOME AND (EXPENSES)
YEAR ENDED DECEMBER 31, --------------------------------------------------- 2000 1999 1998 ---- ---- ---- (In Thousands) Interest Expense, Net $(243,155) $(251,920) $(205,840) --------- --------- --------- Equity in Earnings: Kinder Morgan Energy Partners - Earnings 140,913 15,733 -- Kinder Morgan Energy Partners - Amortization (28,317) (7,335) -- Power Segment(1) 3,669 10,511 8,675 Other (10,255) 14,140 22,466 --------- --------- --------- Total Equity in Earnings 106,010 33,049 31,141 --------- --------- --------- Minority Interests (24,121) (24,845) (19,483) Gains from Sales of Assets 61,684 189,778 19,552 Other, Net 10,881 4,627 1,843 --------- --------- --------- $ (88,701) $ (49,311) $(172,787) ========= ========= =========
(1) See discussion under the heading "Power and Other." The increase of $39.4 million (79.9%) 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 $158.8 million from the sale of Kinder Morgan Interstate 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. 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. Kinder Morgan Energy Partners' Form 10-K for the year ended December 31, 2000 contains additional information about its results of operations. The decrease in other equity in earnings from 1999 to 2000 is principally due to the sale of various equity 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 Trust Securities. These securities are described in Note 12 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. The decrease of $123.5 million in net expense reported under "Other Income and (Expenses)" from 1998 to 1999 is principally due to increased 1999 gains from the sale of assets, partially offset by increased interest expense. The increased 1999 gains from the sale of assets reflects the fact that 1999 includes the gain from the sale of Kinder Morgan Gas Transmission and other assets as discussed above, while 1998 includes (i) a gain of $10.9 million from the sale of certain microwave towers and (ii) a gain of $8.5 million from the sale of Kansas natural gas distribution properties. The increase of $46.1 million (22.4%) in "Interest Expense, Net" from 1998 to 1999 is principally due to the incremental debt outstanding as a result of the January 1998 acquisition of MidCon Corp. and decreased capitalized interest in 1999 due to the reduced level of capital spending (see "Net Cash Flows from Investing Activities"). 29 30 ITEM 7: MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) INCOME TAXES - CONTINUING OPERATIONS
YEAR ENDED DECEMBER 31, ------------------------------------------------------------- 2000 1999 1998 ---- ---- ---- (Dollars In Thousands) Income Tax Provision $ 122,727 $ 90,733 $ 82,710 ========= ========= ========= Effective Tax Rate 40.0% 36.8% 37.1% ========= ========= =========
The increase of $32.0 million in the income tax provision from 1999 to 2000 is composed of (i) an increase of $22.1 million due to an increase in pretax income and (ii) an increase of $9.9 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. The increase of $8.0 million in income tax expense from 1998 to 1999 reflected an increase of $8.7 million due to an increase in 1999 pre-tax income, partially offset by a decrease of $0.7 million due to a decrease in the 1999 effective tax rate. The decrease in the 1999 effective tax rate was principally due to the impact of asset sales and dispositions of certain lines of business. DISCONTINUED OPERATIONS
YEAR ENDED DECEMBER 31, ------------------------------------------------ 2000 1999 1998 ---- ---- ---- (In Thousands) Loss from Discontinued Operations, Net of Tax $ -- $ (50,941) $ (77,984) ========== ========= ========= 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 $23.7 million at December 31, 2000 associated with these discontinued operations, principally consisting of (i) indemnification obligations under the various sale agreements and (ii) retained liabilities, which were settled in cash in early 2001. We do not expect significant additional financial impacts associated with these matters. Note 6 of the accompanying Notes to Consolidated Financial Statements contains certain additional financial information with respect to these discontinued operations. Losses from discontinued operations, net of tax benefits of $31.6 million and $41.4 million in 1999 and 1998, respectively, decreased by $27.0 million from 1998 to 1999. Operating results were positively impacted in 1999, relative to 1998, by (i) improvement in the natural gas liquids pricing environment in 1999 and (ii) the fact that 1998 operating results included (1) $6.4 million of adjustments to write down certain natural gas due from third parties and in underground storage to their current market values, (2) $3.7 million of increased provision for uncollectible accounts receivable, (3) natural gas liquids storage inventory write-downs and (4) operating losses associated with gas processing facilities that were sold in the fourth quarter of 1998. These factors serving to create a favorable period to period variance were partially offset by the fact that 1998 results included $6.0 million in margin from sales of storage gas. 30 31 ITEM 7: MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) LIQUIDITY AND CAPITAL RESOURCES The following table illustrates the sources of our invested capital. The balances at December 31, 1999 reflect the impacts associated with the acquisition of Kinder Morgan Delaware and the sale of certain assets to Kinder Morgan Energy Partners, while the balances at December 31, 2000 also reflect the impact of the sale of additional assets to Kinder Morgan Energy Partners effective as of that date. Notes 2 and 5 of the accompanying Notes to Consolidated Financial Statements contain additional information on these transactions, while Note 12 contains information concerning our outstanding debt securities, short-term borrowing facilities and financing activities.
DECEMBER 31, ---------------------------------------------------- 2000 1999 1998 ---------- ---------- ---------- (Dollars In Thousands) Long-term Debt $2,478,983 $3,293,326 $3,300,025 Common Equity 1,797,421 1,669,846 1,219,043 Preferred Stock -- -- 7,000 Capital Trust Securities 275,000 275,000 275,000 ---------- ---------- ---------- Capitalization 4,551,404 5,238,172 4,801,068 Short-term Debt 908,167 581,567 1,702,013(1) ---------- ---------- ---------- Invested Capital $5,459,571 $5,819,739 $6,503,081 ========== ========== ========== Capitalization: Long-term Debt 54.5% 62.9% 68.7% Common Equity 39.5% 31.9% 25.4% Preferred Stock -- -- 0.2% Capital Trust Securities 6.0% 5.2% 5.7% Invested Capital: Total Debt 62.0%(3) 66.6% 76.9%(2) Equity, Including Capital Trust Securities 38.0%(3) 33.4% 23.1%
(1) Includes the $1,394,846 Substitute Note assumed in conjunction with the acquisition of MidCon Corp. This note was repaid on January 4, 1999. (2) If the government securities then held as collateral were offset against the related debt, the ratio of total debt to invested capital at December 31, 1998, would have been 72.3 percent. (3) As adjusted to reflect the November 2001 maturity of the Premium Equity Participating Units (see "Net Cash Flows from Financing Activities") and the associated $460 million increase in equity and decrease in debt, the ratios would be: Debt - 53.6%, Equity - 46.4%. 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" decreased from $321.2 million in 1999 to $167.1 million in 2000, a decline of $154.1 million (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 (see Note 2 of the accompanying Notes to Consolidated Financial Statements and the discussion following) and (ii) a decrease in cash used in 2000 to make interest payments reflecting the decreased average debt balance outstanding. Partially offsetting this increase were (i) an increase in cash used for working capital of $84.6 million and (ii) January 2000 payments associated with December 1999 gas supply purchases. 31 32 ITEM 7: MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) "Net Cash Flows Provided by Operating Activities" increased from $95.3 million in 1998 to $321.2 million in 1999, an increase of $225.9 million or 237 percent. This increase was principally attributable to (i) cash provided by reductions in working capital for continuing operations in 1999 and (ii) increased 1999 operating cash flows associated with discontinued operations reflecting, among other things, improved operating results and the sale of accounts receivable, partially offset by (i) reduced 1999 earnings from continuing operations before asset sales and (ii) the inclusion in 1998 results of $27.5 million of proceeds from the buyout of certain contractual gas obligations. 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 declaration month. Therefore, the accompanying Statement of Consolidated Cash Flows for 2000 reflects the receipt of a total of $121.3 million of cash distributions from Kinder Morgan Energy Partners for the fourth quarter of 1999 and the first nine months of 2000. The cash distributions attributable to our interest for the three months and twelve months ended December 31, 2000 total $44.5 million and $149.9 million, respectively. The increase in distributions during 2000 reflects, among other factors, the December 31, 1999 transfer of certain properties from us to Kinder Morgan Energy Partners (see Note 5 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 $1.0 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 the Substitute 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, which was principally a result of the $163.9 million of proceeds received from ONEOK for the sale of gathering and processing businesses in Oklahoma, Kansas and West Texas. "Net Cash Flows Provided by (Used in) Investing Activities" increased from a net outflow of $3.5 billion in 1998 to a net inflow of $1.0 billion in 1999. This increase was principally attributable to the net impact of (i) a net cash outflow of $2.2 billion in 1998 for the purchase of MidCon Corp., (ii) net purchases of U.S. Government securities of $1.1 billion in 1998, principally to act as collateral for the Substitute Note assumed in the acquisition of MidCon Corp., (iii) net sales of U.S. government securities of $1.1 billion in 1999, which proceeds were used, together with proceeds of additional short-term borrowings, to repay the Substitute Note, (iv) additional cash used in 1999 for other acquisitions, principally the cash portion of consideration paid for the Thermo acquisition, (v) the 1999 receipt of $28.7 million of proceeds from the sale of Tom Brown, Inc. preferred stock, (vi) increased proceeds from sales of assets in 1999 and (vi) decreased net cash outflows for investing activities of discontinued operations in 1999. 32 33 ITEM 7: MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) During the year 2000, major asset sales included (i) Kinder Morgan Texas Pipeline, L.P., 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) Wildhorse Energy Partners, LLC to Tom Brown, Inc. Total proceeds received in 2000 from asset sales were $730.6 million of which $330 million represented proceeds from the 1999 transfer of assets to Kinder Morgan Energy Partners. Major asset sales during 1999 included (i) Kinder Morgan Interstate, 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 2, 5 and 6 of the accompanying Notes to Consolidated Financial Statements and "Net Cash Flows from Financing Activities" following contain more information concerning these investments and sales. Net Cash Flows from Financing Activities "Net Cash Flows (Used in) Provided by Financing Activities" decreased from approximately $1.3 billion in 1999 to $550.3 million in 2000, a decline of approximately $786.7 million. This decrease was principally due to the first-quarter 1999 repayment of the $1.39 billion Substitute 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. "Net Cash Flows (Used in) Provided by Financing Activities" decreased from a net inflow of $3.4 billion in 1998 to a net outflow of $1.3 billion in 1999. This decrease was principally the result of the 1998 financings associated with the acquisition of MidCon Corp. and the repayment of the Substitute Note in 1999, in each case as described following. In addition, we retired $158.9 million of long-term debt in 1999, compared to $35.8 million in 1998. The long-term debt retired in 1999 included $148.6 million of debt assumed in conjunction with the acquisition of Kinder Morgan Delaware. Our principal sources of short-term liquidity are our revolving bank facilities. As of December 31, 2000, we had available a $500 million 364-day facility dated October 25, 2000, 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. At December 31, 2000, we had $100 million of bank borrowings and commercial paper (which is backed by the bank facilities) issued and outstanding. The corresponding amount outstanding was $50 million at February 9, 2001. After inclusion of applicable letters of credit, the remaining available borrowing capacity under the bank facilities was $796.7 million and $846.7 million at December 31, 2000 and February 9, 2001, 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 upon issuance of common stock to the holders of the premium equity participating security units at the maturity of the security units (November 2001), 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. 33 34 ITEM 7: MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) Our short-term debt of $908.2 million at December 31, 2000 consisted of (i) $100 million of borrowings under our revolving credit facilities, (ii) the $400 million of Reset Put Securities that are scheduled to be either remarketed or retired as of March 1, 2001, (iii) the $400 million of 6.45% Senior Notes, due November 2001 and (iv) $8.2 million of miscellaneous current maturities of long-term debt. We expect to retire the Reset Put Securities at March 1, 2001 utilizing a combination of cash on hand and incremental short-term borrowings, which will result in an extraordinary loss on early extinguishments of debt expected to total approximately $15 million. We expect that the $400 million of 6.45% Senior Notes will be retired at maturity with a portion of the $460 million of cash to be received from the issuance of common stock upon maturity of the Premium Equity Participating Securities, which occurs concurrently as discussed following. Apart from these items, our current assets and current liabilities are approximately equal. Given our expected cash flows from operations and our unused debt capacity, including our five-year revolving credit facility, we do not expect any liquidity issues in the foreseeable future. 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 February 2000, we reduced our participation in this receivables sales program by $124.9 million, 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. In November 1998, we sold $460 million principal amount of premium equity participating securities in a public offering. The proceeds from the security units offering was used to purchase U.S. Treasury Notes on behalf of the security unit holders, which notes are the property of the security unit holders and will be held as collateral to fund the obligation of the security unit holders to purchase our common stock at the end of a three-year period. In November 2001, the maturity of these securities will result in our receipt of $460 million in cash as discussed above and, based on the market price of our common stock as of November 30, 2001, the issuance of approximately 13.4 million shares of common stock. The cash proceeds are expected to be used to retire the $400 million of 6.45% Senior Notes that mature concurrently with the premium equity participating securities and to repay a portion of short-term borrowings then outstanding. In March 1998, we issued 12.5 million shares (18.75 million shares after adjustment for the December 1998 three-for-two stock split) of common stock in an underwritten public offering, receiving net proceeds of approximately $624.6 million. Also in March 1998, we issued $2.35 billion principal amount of debt securities of varying maturities and interest rates in an underwritten public offering, receiving net proceeds of approximately $2.34 billion. The net proceeds from these two offerings were used to refinance borrowings under the MidCon Corp. acquisition financing arrangements and to purchase U.S. government securities to collateralize a portion of the Substitute Note (assumed in conjunction with the acquisition). In April 1998, we sold $175 million of 7.63% Capital Securities due April 15, 2028, in an underwritten offering, with the net proceeds of $173.1 million used to purchase U.S. government securities to further collateralize the Substitute Note. In November 1998, we completed the underwritten public offering of $400 million of three-year senior notes concurrently with the $460 million principal amount of premium equity participating security units discussed above. The $397.4 million of net proceeds from the senior notes offering were used to retire a portion of our then-outstanding short-term borrowings. For additional information on each of these financings, including terms of the specific securities and the associated accounting treatment, see Note 12 of the accompanying Notes to Consolidated Financial Statements. 34 35 ITEM 7: MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) On January 4, 1999, we repaid the $1.4 billion Substitute Note payable to Occidental Petroleum as part of the MidCon Corp. acquisition. 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 2000 were $137.5 million and $3.2 million for continuing operations and discontinued operations, respectively. The 2001 capital expenditure budget totals approximately $197 million, before expenditures which may be made on the Horizon Pipeline project. We expect that funding for the budget will be provided from internal sources and, if necessary, incremental borrowings. Approximately $5.5 million of this amount had been committed for the purchase of plant and equipment at December 31, 2000. Additional information on commitments is contained in Note 17 of the accompanying Notes to Consolidated Financial Statements. LITIGATION AND ENVIRONMENTAL Our anticipated environmental capital costs and expenses for 2001, including expected costs for remediation efforts, are approximately $7 million, compared to $5.8 million of such costs and expenses incurred in 2000. A substantial portion of our environmental costs are either recoverable through insurance and indemnification provisions or have previously recorded liabilities associated with them. Refer to Notes 9(A) and 9(B) to 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 8 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 14 of the accompanying Notes to Consolidated Financial Statements, which contains additional information on our risk management activities. To minimize the risk of price changes in the natural gas and associated transportation markets, we use certain financial instruments for hedging purposes. These instruments include energy products traded on the New York Mercantile Exchange, the Kansas City Board of Trade and over-the-counter markets including, but not limited to, futures and options contracts and fixed-price swaps. 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. Pursuant to a policy approved by our Board of Directors, we are to engage in these activities only as a hedging mechanism against price volatility associated with (i) pre-existing or anticipated physical gas sales, (ii) physical gas purchases and (iii) system use and storage in order to protect profit margins, and not to engage in speculative trading. Commodity-related activities of the risk management group are monitored by our Risk Management Committee, which is charged with the review and enforcement of the Board of Directors' risk management policy. The Risk Management Committee reviews the types of hedging instruments used, contract limits and approval levels and may review the pricing and hedging of any or all commodity transactions. All energy futures, swaps and options are recorded at fair value. The fair value of these risk management instruments reflects the estimated amounts that 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 financial instruments we use. 35 36 ITEM 7: MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) Through December 31, 2000, gains and losses on hedging positions have been deferred and recognized as gas purchases expense in the periods in which the underlying physical transactions occur. On January 1, 2001, we began accounting for derivative instruments under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities", (after amendment by SFAS 137 and SFAS 138, the "Statement"). As discussed preceding, our principal use of derivative financial instruments is to mitigate the market price risk associated with anticipated transactions for the purchase and sale of natural gas. The Statement allows these transactions to continue to be treated as hedges for accounting purposes, although the changes in the market value of these instruments will affect comprehensive income in the period in which they occur and any ineffectiveness in the risk mitigation performance of the hedge will affect net income currently. The change in the market value of these instruments representing effective hedge operation will continue to affect net income in the period in which the associated physical transactions are consummated. Adoption of the Statement has resulted in $14.4 million of deferred net loss as of January 1, 2001, being reported as part of other comprehensive income in 2001, as well as subsequent changes in the market value of these derivatives prior to consummation of the transaction being hedged. We measure the risk of price changes in the natural gas and natural gas liquids markets utilizing a Value-at-Risk model. 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 utilize a closed form model to evaluate risk on a daily basis. The Value-at-Risk computations utilize a confidence level of 97.7 percent for the resultant price movement and a holding period of one day chosen for the calculation. The confidence level used means that there is a 97.7 percent probability that the mark-to-market losses for a single day will not exceed the Value-at-Risk number presented. Instruments evaluated by the model include forward physical gas, storage and transportation contracts and financial products including commodity futures and options contracts, fixed price swaps, basis swaps and over-the-counter options. During 2000, Value-at-Risk reached a high of $5.4 million and a low of $1.5 million. Value-at-Risk at December 31, 2000, was $5.3 million and averaged $4.5 million for 2000. 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. As a result of our recent divestiture of certain lines of business, including our wholesale natural gas and liquids marketing and natural gas gathering, processing and associated businesses, we expect that our portfolio of financial instruments held for the purposes of hedging, and corresponding exposure to loss from such instruments, will be smaller in the future. Given our portfolio of businesses as of December 31, 2000, our principal uses of derivative financial instruments will be to mitigate the risk associated with market movements in the price of natural gas associated with (i) the sale of in-kind fuel recoveries in excess of fuel used on Natural Gas Pipeline Company of America's pipeline system and (ii) the purchase of natural gas by Kinder Morgan Retail to serve its customers in the Choice Gas program. From time to time, our treasury department manages interest rate exposure utilizing interest rate swaps, caps or similar derivatives within Board-established policy. None of these interest rate derivatives is leveraged. We are currently not hedging our interest rate exposure resulting from short-term borrowings. The market risk related to short-term borrowings from a one percent change in interest rates would result in a $0.5 million annual impact on pre-tax income, based on short-term borrowing levels as of February 9, 2001. 36 37 ITEM 7: MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) Significant Operating Variables 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 and Kinder Morgan Retail segments. "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 additional supplies into the Chicago market area, although incremental "take away" capacity 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 for capacity on Natural Gas Pipeline Company of America. In addition, as discussed under "Risk Management" elsewhere in this document and in Note 14 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. 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; - national, international, regional and local economic, competitive and regulatory conditions and developments; - the various factors which affect Kinder Morgan Energy Partners, L.P.'s 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; 37 38 ITEM 7: MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) - 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." 38 39 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Index Page - -------------------------------------------------------------------------------- Report of Independent Accountants......................................... 40-41 Consolidated Statements of Income......................................... 42 Consolidated Statements of Comprehensive Income........................... 43 Consolidated Balance Sheets............................................... 44 Consolidated Statements of Stockholders' Equity........................... 45 Consolidated Statements of Cash Flows..................................... 46 Notes to Consolidated Financial Statements................................ 47-81 Selected Quarterly Financial Data (unaudited)............................. 82-83 - -------------------------------------------------------------------------------- 39 40 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) 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, 2000 and 1999, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index 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. We also audited the adjustments described in Note 2 that were applied to restate the 1998 consolidated financial statements. In our opinion, these adjustments are appropriate and have been properly applied. /s/PricewaterhouseCoopers LLP Houston, Texas February 14, 2001 40 41 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To Kinder Morgan, Inc.: We have audited the accompanying consolidated statements of income, comprehensive income, stockholders' equity, and cash flows of Kinder Morgan, Inc. (formerly K N Energy, Inc. and a Kansas corporation) and subsidiaries for the year ended December 31, 1998 prior to the restatement (and, therefore, are not presented herein) for the retroactive application of the equity method of accounting for an investment as described in Note 2 to the restated financial statements. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the results of operations and cash flows of Kinder Morgan, Inc. and subsidiaries for the year ended December 31, 1998, in conformity with accounting principles generally accepted in the United States. /s/ Arthur Andersen LLP Denver, Colorado February 2, 1999 (except with respect to the matters discussed in Note 6, as to which the dates are March 16, 2000 and February 14, 2001) 41 42 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) CONSOLIDATED STATEMENTS OF INCOME KINDER MORGAN, INC. AND SUBSIDIARIES
YEAR ENDED DECEMBER 31, -------------------------------------------------- RESTATED - SEE NOTE 2 ----------------------------- 2000 1999 1998 ---- ---- ---- (In Thousands Except Per Share Amounts) OPERATING REVENUES: Natural Gas Sales $ 1,999,648 $ 1,004,097 $ 955,254 Natural Gas Transportation and Storage 596,774 745,179 640,906 Other 117,315 87,092 64,099 ----------- ----------- ----------- Total Operating Revenues 2,713,737 1,836,368 1,660,259 ----------- ----------- ----------- OPERATING COSTS AND EXPENSES: Gas Purchases and Other Costs of Sales 1,960,083 1,050,250 836,614 Operations and Maintenance 164,286 184,888 170,035 General and Administrative 58,087 85,591 68,502 Depreciation and Amortization 108,165 147,933 155,363 Taxes, Other Than Income Taxes 27,973 34,561 28,290 Merger-related and Severance Costs -- 37,443 5,763 ----------- ----------- ----------- Total Operating Costs and Expenses 2,318,594 1,540,666 1,264,567 ----------- ----------- ----------- OPERATING INCOME 395,143 295,702 395,692 ----------- ----------- ----------- OTHER INCOME AND (EXPENSES): Kinder Morgan Energy Partners: Equity in Earnings 140,913 15,733 -- Amortization of Excess Investment (28,317) (7,335) -- Equity in Earnings (Losses) of Other Equity Investments (6,586) 24,651 31,141 Interest Expense, Net (243,155) (251,920) (205,840) Minority Interests (24,121) (24,845) (19,483) Other, Net 72,565 194,405 21,395 ----------- ----------- ----------- Total Other Income and (Expenses) (88,701) (49,311) (172,787) ----------- ----------- ----------- INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 306,442 246,391 222,905 Income Taxes 122,727 90,733 82,710 ----------- ----------- ----------- INCOME FROM CONTINUING OPERATIONS 183,715 155,658 140,195 ----------- ----------- ----------- DISCONTINUED OPERATIONS, NET OF TAX: Loss from Discontinued Operations -- (50,941) (77,984) Loss on Disposal of Discontinued Operations (31,734) (344,378) -- ----------- ----------- ----------- Total Loss From Discontinued Operations (31,734) (395,319) (77,984) ----------- ----------- ----------- NET INCOME (LOSS) 151,981 (239,661) 62,211 Less - Preferred Dividends -- 129 350 Less - Premium Paid on Preferred Stock Redemption -- 350 -- ----------- ----------- ----------- EARNINGS (LOSS) AVAILABLE FOR COMMON STOCK $ 151,981 $ (240,140) $ 61,861 =========== =========== =========== Number of Shares Used in Computing Basic Earnings Per Common Share (Thousands) 114,063 80,284 64,021 =========== =========== =========== BASIC EARNINGS (LOSS) PER COMMON SHARE: Continuing Operations $ 1.61 $ 1.93 $ 2.19 Loss from Discontinued Operations -- (0.63) (1.22) Loss on Disposal of Discontinued Operations (0.28) (4.29) -- ----------- ----------- ----------- Total Basic Earnings (Loss) Per Common Share $ 1.33 $ (2.99) $ 0.97 =========== =========== =========== Number of Shares Used in Computing Diluted Earnings Per Common Share (Thousands) 115,030 80,358 64,636 =========== =========== =========== DILUTED EARNINGS (LOSS) PER COMMON SHARE: Continuing Operations $ 1.60 $ 1.93 $ 2.17 Loss from Discontinued Operations -- (0.63) (1.21) Loss on Disposal of Discontinued Operations (0.28) (4.29) -- ----------- ----------- ----------- Total Diluted Earnings (Loss) Per Common Share $ 1.32 $ (2.99) $ 0.96 =========== =========== =========== DIVIDENDS PER COMMON SHARE $ 0.20 $ 0.65 $ 0.76 =========== =========== ===========
The accompanying notes are an integral part of these statements. 42 43 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME KINDER MORGAN, INC. AND SUBSIDIARIES
YEAR ENDED DECEMBER 31, --------------------------------------------------- RESTATED - SEE NOTE 2 ------------------------------- 2000 1999 1998 ---- ---- ---- (In Thousands) NET INCOME (LOSS) $ 151,981 $(239,661) $ 62,211 Realized Gain on Equity Securities, Net of Tax 1,602 852 -- Unrealized Loss on Equity Securities, Net of Tax -- -- (6,697) --------- --------- --------- COMPREHENSIVE INCOME (LOSS) $ 153,583 $(238,809) $ 55,514 ========= ========= =========
The accompanying notes are an integral part of these statements. 43 44 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) CONSOLIDATED BALANCE SHEETS KINDER MORGAN, INC. AND SUBSIDIARIES
DECEMBER 31, --------------------------------- RESTATED SEE NOTE 2 ------------ 2000 1999 ----------- ------------ (In Thousands) ASSETS CURRENT ASSETS: Cash and Cash Equivalents $ 141,923 $ 26,378 Restricted Deposits 14,063 51 Customer Accounts Receivable, Net 104,209 298,805 Receivable From Kinder Morgan Energy Partners -- 330,000 Other Receivables 64,309 7,646 Inventories 19,600 50,328 Gas Imbalances 40,838 51,024 Other 48,700 19,154 Net Current Assets of Discontinued Operations -- 58,991 ----------- ----------- 433,642 842,377 ----------- ----------- INVESTMENTS: Kinder Morgan Energy Partners 1,850,397 1,791,768 Other 143,698 132,971 ----------- ----------- 1,994,095 1,924,739 ----------- ----------- PROPERTY, PLANT AND EQUIPMENT, NET 5,724,617 5,789,564 ----------- ----------- DEFERRED CHARGES AND OTHER ASSETS 265,751 209,758 ----------- ----------- NET NON-CURRENT ASSETS OF DISCONTINUED OPERATIONS -- 659,236 ----------- ----------- TOTAL ASSETS $ 8,418,105 $ 9,425,674 =========== =========== LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES: Current Maturities of Long-term Debt $ 808,167 $ 7,167 Notes Payable 100,000 574,400 Accounts Payable 126,267 224,625 Accounts Payable - Kinder Morgan Energy Partners 13,534 -- Accrued Interest 72,222 73,000 Accrued Taxes 26,584 36,075 Gas Imbalances 39,496 74,992 Payable for Purchase of Thermo Companies 15,000 44,320 Reserve for Loss on Disposal of Discontinued Operations 23,694 535,630 Other 143,761 133,620 ----------- ----------- 1,368,725 1,703,829 ----------- ----------- OTHER LIABILITIES AND DEFERRED CREDITS: Deferred Income Taxes 2,284,496 2,231,224 Other 208,570 242,926 ----------- ----------- 2,493,066 2,474,150 ----------- ----------- LONG-TERM DEBT 2,478,983 3,293,326 ----------- ----------- 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 4,910 9,523 ----------- ----------- COMMITMENTS AND CONTINGENT LIABILITIES (NOTES 9 AND 17) STOCKHOLDERS' EQUITY: Preferred Stock (Note 13) -- -- Common Stock- Authorized - 150,000,000 Shares, Par Value $5 Per Share Outstanding - 114,578,800 and 112,838,379 Shares, Before Deducting 96,140 and 172,402 Shares Held in Treasury 572,894 564,192 Additional Paid-in Capital 1,189,270 1,203,008 Retained Earnings (Deficit) 37,584 (91,610) Other, Including Shares Held in Treasury (2,327) (5,744) ----------- ----------- Total Stockholders' Equity 1,797,421 1,669,846 ----------- ----------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 8,418,105 $ 9,425,674 =========== ===========
The accompanying notes are an integral part of these statements. 44 45 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY KINDER MORGAN, INC. AND SUBSIDIARIES
YEAR ENDED DECEMBER 31, ------------------------------------------------------------------------------------- 2000 1999 1998 ---- ---- ---- SHARES AMOUNT SHARES AMOUNT SHARES AMOUNT ------ ------ ------ ------ ------ ------ (Dollars In Thousands) PREFERRED STOCK: Beginning Balance -- $ -- 70,000 $ 7,000 70,000 $ 7,000 Redemption of Preferred Stock -- -- (70,000) (7,000) -- -- ----------- ----------- ----------- ----------- ----------- ----------- Ending Balance -- -- -- -- 70,000 7,000 =========== ----------- =========== ----------- =========== ----------- COMMON STOCK: Beginning Balance 112,838,379 564,192 68,645,906 343,230 32,024,557 160,123 Sale of Common Stock, Net -- -- -- -- 12,500,000 62,500 Acquisition of Kinder Morgan Delaware -- -- 41,683,323 208,417 - - - Acquisitions/Sales of Other Businesses 946,207 4,731 2,065,909 10,330 689,810 3,449 Employee and Executive Benefit Plans 794,214 3,971 443,241 2,215 549,570 2,758 Common Stock Split -- -- -- -- 22,881,969 114,400 ----------- ----------- ----------- ----------- ----------- ----------- Ending Balance 114,578,800 572,894 112,838,379 564,192 68,645,906 343,230 ----------- ----------- ----------- ----------- ----------- ----------- ADDITIONAL PAID-IN CAPITAL: Beginning Balance 1,203,008 694,223 266,435 Sale of Common Stock, Net -- -- 558,053 Costs Related to PEPS Offering (1,151) (514) (62,150) Revaluation of KMEP Investment (Note 5) (51,074) -- -- Acquisition of Kinder Morgan Delaware -- 470,831 -- Acquisition of Other Businesses 23,824 34,670 30,985 Employee and Executive Benefit Plans 14,663 3,798 15,371 Common Stock Split -- -- (114,471) ----------- ----------- ----------- Ending Balance 1,189,270 1,203,008 694,223 ----------- ----------- ----------- RETAINED EARNINGS (DEFICIT): Beginning Balance - as Previously Reported (95,615) 193,925 185,658 Restatement (Note 2) 4,005 2,222 -- ----------- ----------- ----------- Beginning Balance - As Restated (91,610) 196,147 185,658 Net Income (Loss) - as Previously Reported 151,981 (241,444) 59,989 Restatement (Note 2) -- 1,783 2,222 Cash Dividends: Common (22,787) (47,967) (51,372) Preferred -- (129) (350) ----------- ----------- ----------- Ending Balance 37,584 (91,610) 196,147 ----------- ----------- ----------- OTHER: DEFERRED COMPENSATION: Beginning Balance -- (10,686) (9,203) Executive Benefit Plans -- 10,686 (1,483) ----------- ----------- ----------- Ending Balance -- -- (10,686) ----------- ----------- ----------- TREASURY STOCK, AT COST: Beginning Balance (172,402) (4,142) (48,598) (1,417) (28,482) (1,124) Treasury Stock Acquired (1,743) (62) (135,510) (2,956) (60,994) (2,834) Treasury Stock Issued 78,005 1,877 -- -- -- -- Acquisition of Businesses -- -- -- -- 39,970 1,801 Dividend Reinvestment Plan -- -- 11,706 231 17,135 740 Common Stock Split -- -- -- -- (16,227) -- ----------- ----------- ----------- ----------- ----------- ----------- Ending Balance (96,140) (2,327) (172,402) (4,142) (48,598) (1,417) ----------- ----------- ----------- ----------- ----------- ----------- ACCUMULATED OTHER COMPREHENSIVE INCOME (NET OF TAX): Beginning Balance (1,602) (2,454) 4,243 Sale of Tom Brown, Inc. Common Stock 1,602 -- -- Unrealized Gain (Loss) on Equity Securities -- 852 (6,697) ----------- ----------- ----------- Ending Balance -- (1,602) (2,454) ----------- ----------- ----------- TOTAL OTHER (96,140) (2,327) (172,402) (5,744) (48,598) (14,557) ----------- ----------- ----------- ----------- ----------- ----------- TOTAL STOCKHOLDERS' EQUITY 114,482,660 $ 1,797,421 112,665,977 $ 1,669,846 68,597,308 $ 1,226,043 =========== =========== =========== =========== =========== ===========
The accompanying notes are an integral part of these statements. 45 46 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) CONSOLIDATED STATEMENTS OF CASH FLOWS KINDER MORGAN, INC. AND SUBSIDIARIES
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS YEAR ENDED DECEMBER 31, ------------------------------------------- 2000 1999 1998 ---- ---- ---- CASH FLOWS FROM OPERATING ACTIVITIES: (In Thousands) Net Income (Loss) $ 151,981 $ (239,661) $ 62,211 Adjustments to Reconcile Net Income (Loss) to Net Cash Flows from Operating Activities: Loss from Discontinued Operations, Net of Tax 31,734 395,319 77,984 Depreciation and Amortization 108,165 147,933 155,363 Deferred Income Taxes 105,424 57,609 24,516 Equity in Earnings of Kinder Morgan Energy Partners (112,596) (8,398) -- Distributions from Kinder Morgan Energy Partners 121,323 15,000 -- Deferred Purchased Gas Costs 2,685 6,646 468 Net Gains on Sales of Facilities (61,684) (189,778) (19,552) Proceeds from Buyout of Contractual Gas Obligations -- -- 27,500 Changes in Other Working Capital Items [Note 1(M)] (48,466) 36,119 (40,506) Changes in Deferred Revenues (4,457) (15,641) 6,300 Other, Net (16,622) 21,540 (7,242) ----------- ----------- ----------- Net Cash Flows Provided by Continuing Operations 277,487 226,688 287,042 Net Cash Flows Provided by (Used in) Discontinued Operations (110,399) 94,488 (191,773) ----------- ----------- ----------- NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES 167,088 321,176 95,269 ----------- ----------- ----------- CASH FLOWS FROM INVESTING ACTIVITIES: Capital Expenditures (137,477) (97,644) (120,881) Proceeds from Sales to Kinder Morgan Energy Partners 500,302 -- -- Cash Paid for Acquisition of MidCon Corp., Net of Cash Acquired -- -- (2,191,555) Other Acquisitions (19,412) (34,565) 1,086 Investments (28,688) (10,044) (9,179) Proceeds from Sale of Tom Brown, Inc. Stock 14,823 28,650 -- Sale of U.S. Government Securities -- 1,092,415 1,062,453 Purchase of U.S. Government Securities -- -- (2,154,868) Proceeds from Sales of Other Assets 14,998 87,949 38,634 ----------- ----------- ----------- Net Cash Flows Provided by (Used in) Continuing Investing Activities 344,546 1,066,761 (3,374,310) Net Cash Flows Provided by (Used in) Discontinued Investing Activities 154,176 (46,568) (119,100) ----------- ----------- ----------- NET CASH FLOWS PROVIDED BY (USED IN) INVESTING ACTIVITIES 498,722 1,020,193 (3,493,410) ----------- ----------- ----------- CASH FLOWS FROM FINANCING ACTIVITIES: Short-Term Debt, Net (474,400) (1,117,446) (32,687) Long-Term Debt - Issued -- -- 2,750,000 Long-Term Debt - Retired (14,055) (158,934) (35,787) Common Stock Issued in Public Offering -- -- 650,000 Other Common Stock Issued 17,773 8,323 13,437 Other Financing, Net (45,239) -- -- Mandatorily Redeemable Trust Securities Issued -- -- 175,000 Preferred Stock Redeemed -- (7,350) -- Treasury Stock, Issued 1,877 231 740 Treasury Stock, Acquired (62) (2,956) (2,834) Cash Dividends, Common and Preferred (22,787) (48,096) (51,722) Minority Interests, Net (2,436) 379 9,697 Premium Equity Participating Securities Contract Fee and Securities Issuance Costs (10,936) (11,097) (78,219) ----------- ----------- ----------- NET CASH FLOWS (USED IN) PROVIDED BY FINANCING ACTIVITIES (550,265) (1,336,946) 3,397,625 ----------- ----------- ----------- Net Increase (Decrease) in Cash and Cash Equivalents 115,545 4,423 (516) Cash and Cash Equivalents at Beginning of Year 26,378 21,955 22,471 ----------- ----------- ----------- Cash and Cash Equivalents at End of Year $ 141,923 $ 26,378 $ 21,955 =========== =========== ===========
The accompanying notes are an integral part of these statements. 46 47 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (A) Nature of Operations Kinder Morgan, Inc. is one of the largest midstream energy companies in America, operating more than 30,000 miles of natural gas and products pipelines. Our common stock is traded on the New York Stock Exchange under the ticker symbol "KMI." We are an energy services provider and have operations in 16 states in the Rocky Mountain and mid-continent regions, with principal operations in Arkansas, Colorado, Illinois, Iowa, Kansas, Nebraska, Oklahoma, Texas and Wyoming. Energy services we offer include: storing, transporting and selling natural gas, providing retail natural gas distribution services, and generating and selling electricity. We have both regulated and nonregulated operations. During 1999, we made significant acquisitions, including Kinder Morgan Delaware. As a result, through our general partner interest, we operate 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 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 and, accordingly, we decided to retain them. Additional information concerning these discontinued operations is contained in Note 6. (B) Basis of Presentation The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the reported amounts of revenues and expenses. Actual results could differ from these estimates. The consolidated financial statements include the accounts of 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 2. All material intercompany transactions and balances have been eliminated. Certain prior year amounts have been reclassified to conform to the current presentation. (C) Accounting for Regulatory Activities Our regulated public utilities are accounted for in accordance with the provisions of Statement of Financial Accounting Standards ("SFAS") No. 71, Accounting for the Effects of Certain Types of Regulation, which prescribes the circumstances in which the application of generally accepted accounting principles is affected by the economic effects of regulation. 47 48 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges and credits that will be recovered from or refunded to customers through the ratemaking process. The following regulatory assets and liabilities are reflected in the accompanying Consolidated Balance Sheets:
DECEMBER 31, --------------------------------- 2000 1999 -------- -------- (In Thousands) REGULATORY ASSETS: Employee Benefit Costs $ 6,576 $ 6,909 Debt Refinancing Costs 1,664 1,992 Deferred Income Taxes 16,801 16,853 Purchased Gas Costs 23,470 27,043 Plant Acquisition Adjustments 454 454 Rate Regulation and Application Costs 3,040 3,095 -------- -------- Total Regulatory Assets 52,005 56,346 -------- -------- REGULATORY LIABILITIES: Employee Benefit Costs 5,967 5,967 Deferred Income Taxes 28,930 31,235 Purchased Gas Costs 14,415 25,926 -------- -------- Total Regulatory Liabilities 49,312 63,128 -------- -------- NET REGULATORY ASSETS (LIABILITIES) $ 2,693 $ (6,782) ======== ========
As of December 31, 2000, $45.0 million of our regulatory assets and $43.3 million of our regulatory liabilities were being recovered from or refunded to customers through rates over periods ranging from 1 to 13 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. (E) Earnings Per Share Basic earnings per share is computed based on the monthly weighted-average number of common shares outstanding during each period. Diluted earnings per share is computed based on the monthly weighted-average number of common shares outstanding during the periods, 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.
2000 1999 1998 ---------- ---------- ---------- (In Thousands) Weighted Average Common Shares Outstanding 114,063 80,284 64,021 Dilutive Common Stock Options 967 74 615 ---------- ---------- ---------- Shares Used to Compute Diluted Earnings Per Share 115,030 80,358 64,636 ========== ========== ==========
Remaining stock options outstanding totaling 307,100 for 2000, 3,824,000 for 1999 and 785,000 for 1998 were not included in the earnings per share calculation because to do so would have been antidilutive. Shares issuable upon conversion of the premium equity participating security units were not included in earnings per share calculations because to do so would have been antidilutive for all periods presented. Preferred stock dividends and premiums paid on preferred stock redemptions totaling $479 thousand in 1999, and Preferred Stock dividends of $350 thousand in 1998 were deducted from net income in arriving at the balance available to common stockholders. Note 12(B) contains more information regarding premium equity participating security units, while Note 16 contains more information regarding stock options. 48 49 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) (F) Restricted Deposits Restricted Deposits consist of monies on deposit with brokers that are restricted to meet exchange trading requirements; see Note 14. (G) Inventories
DECEMBER 31, ------------------------- 2000 1999 --------- --------- (In Thousands) Gas in Underground Storage (Current) $ 5,145 $ 38,499 Materials and Supplies 14,455 11,829 --------- --------- $ 19,600 $ 50,328 ========= =========
Inventories are accounted for using the following methods, with the percent of the total dollars at December 31, 2000 shown in parentheses: average cost (85.32%), last-in, first-out (10.26%) and first-in, first-out (4.42%). All non-utility inventories held for resale are valued at the lower of cost or market. 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. The excess of current cost over the reported last-in, first-out value of gas in underground storage valued under that method was approximately $7.4 million at December 31, 2000. (H) Other Investments
DECEMBER 31, -------------------------------- 2000 1999 ---------- ---------- (In Thousands) Thermo Companies $ 72,457 $ 63,528 TransColorado Pipeline Company 34,824 31,160 Tom Brown, Inc. Common Stock (Note 5) -- 12,283 Other 36,417 26,000 ---------- ---------- $ 143,698 $ 132,971 ========== ==========
Investments consist primarily of equity method investments in unconsolidated subsidiaries and joint ventures, and include ownership interests in net profits and net cash flows. At December 31, 2000, "Other" included a $13.5 million investment in Wrightsville Development, LLC, a $6.0 million investment in Igasamex USA, Ltd., a $5.3 million investment in Front Range Holding, LLC, and approximately $4.5 million in assets held for deferred employee compensation, among other individually insignificant items. At December 31, 1999, "Other" included a $10.4 million investment in Front Range Holding, LLC, a $6.3 million investment in Igasamex USA, Ltd., and approximately $4.9 million in assets held for deferred employee compensation, among other individually insignificant items. (I) Property, Plant and Equipment Property, plant and equipment is stated at historical cost, which for constructed plant includes indirect costs such as payroll taxes, fringe benefits, administrative and general costs. Expenditures that increase capacities, improve efficiencies or extend useful lives are capitalized. Routine maintenance, repairs and renewal costs are expensed as incurred. The cost of normal retirements of depreciable utility property, plant and equipment, plus the cost of removal less salvage, is 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. 49 50 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) 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. (J) 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
(K) Interest Expense, Net "Interest Expense, Net" as presented in the accompanying Consolidated Statements of Income is net of (i) the debt component of the allowance for funds used during construction ("AFUDC - Interest"), (ii) in 1999, interest income related to government securities associated with the acquisition of MidCon Corp. and (iii) in 2000, interest income attributable to (i) our note receivable from Kinder Morgan Energy Partners associated with the sale of certain interests (see Note 5) and (ii) interest income associated with settlement of our net cash position with ONEOK, Inc.; see (N).
YEAR ENDED DECEMBER 31, ------------------------------------------------ 2000 1999 1998 ---- ---- ---- (In Millions) AFUDC - Interest $ 2.6 $ 1.9 $ 2.3 Interest Income $ 2.6 $ 0.5 $ 46.4
As discussed in Note 2, in conjunction with the January 30, 1998, acquisition of MidCon Corp., we were required by the definitive stock purchase agreement to assume the Substitute Note for $1.4 billion and to collateralize the Substitute Note with bank letters of credit, a portfolio of government securities or a combination of the two. As a result, we had a significant amount of interest income during 1998 associated with the issuance of the Substitute Note, which has been reported together with the related interest expense as described above. In conjunction with our sale of certain assets to ONEOK as discussed in Note 6, 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 reported the interest income attributable to our net receivable resulting from this transaction together with the related interest expense as described above. 50 51 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) (L) Other, Net "Other, Net" as presented in the accompanying Consolidated Statements of Income includes $61.7 million, $189.8 million and $19.6 million in 2000, 1999 and 1998, respectively, attributable to gains from sales of assets. These transactions are discussed in Note 5. (M) 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. 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, ----------------------------------------------- 2000 1999 1998 ---------- ---------- ---------- (In Thousands) Accounts Receivable $ (172,781) $ (16,483) $ (19,626) Material and Supplies Inventory (2,626) 2,894 (962) Gas in Underground Storage - Current 32,453 (17,626) 6,598 Other Current Assets (27,737) 114 3,329 Accounts Payable 114,908 37,506 (68,774) Other Current Liabilities 7,317 29,714 38,929 ---------- ---------- ---------- $ (48,466) $ 36,119 $ (40,506) ========== ========== ==========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
YEAR ENDED DECEMBER 31, ----------------------------------------------- 2000 1999 1998 ---------- ---------- ---------- (In Thousands) CASH PAID FOR: Interest (Net of Amount Capitalized) $ 248,177 $ 284,762 $ 189,929 ========== ========== ========== Distributions on Preferred Capital Trust Securities $ 21,913 $ 21,913 $ 14,754 ========== ========== ========== Income Taxes Paid (Received) $ 7,674 $ (10,883) $ 39,756 ========== ========== ==========
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; see Note 5. In October 1999, we acquired Kinder Morgan Delaware in a non-cash transaction. During 1998, we acquired MidCon Corp. and interests in assets from the Thermo Companies in transactions that included both cash and non-cash components. For additional information on these transactions, see Note 2. (N) Accounts Receivable The caption "Customer Accounts Receivable, Net" in the accompanying Consolidated Balance Sheets is presented net of allowances for doubtful accounts of $2.3 million and $1.7 million at December 31, 2000 and 1999, respectively. The caption "Other Receivables" 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 6. 51 52 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) (O) 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. (P) Accounting for Certain Equity Transactions by Affiliates 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 being recognized as gains or losses. Two such transactions are described in Note 5. (Q) 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 14, as is our new policy, which is based on the accounting standard which became effective for us on January 1, 2001, SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." (R) 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. 2. 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. Kinder Morgan Energy Partners is the nation's largest pipeline master limited partnership. It owns and operates one of the largest product pipeline systems in the United States, delivering gasoline, diesel and jet fuel to customers through more than 10,000 miles of pipeline and over 20 associated terminals. Additional assets include 10,000 miles of natural gas transportation pipelines; natural gas gathering and storage facilities; 28 bulk terminal facilities, which transload more than 40 million tons of coal, petroleum coke and other products annually; and Kinder Morgan CO2 Company, L.P. 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. In addition, we issued 200,000 shares of our common stock to Petrie Parkman & Co., Inc. in consideration for Petrie Parkman's advisory services rendered in connection with the acquisition of Kinder Morgan Delaware. The issuance of these shares was exempt from registration under Section 4(2) of the Securities Act of 1933, as amended. 52 53 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) The 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 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 The Total Purchase Price Consisted of the Following: dollars) 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)." 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 of each year presented. 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 the dates indicated, nor should it necessarily be viewed as an indicator of future financial results. UNAUDITED PRO FORMA FINANCIAL INFORMATION
YEAR ENDED DECEMBER 31, --------------------------------------------- 1999 1998 ---- ---- (Dollars in Millions Except Per Share Amounts) Operating Revenues $ 1,745.5 $ 1,660.9 Net Income (Loss) $ (233.9) $ 62.5 Diluted Earnings (Loss) Per Common Share $ (2.09) $ 0.58 Number of Shares Used in Computing Diluted Earnings Per Common Share (In Thousands) 112,334 106,319
53 54 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) During the third quarter of 1998, we completed our acquisition of interests in four independent power plants in Colorado from the Denver-based Thermo Companies, representing approximately 380 megawatts of electric generation capacity and access to approximately 130 Bcf of natural gas reserves. These generating facilities are located in Ft. Lupton, Colorado (272 megawatts) and Greeley, Colorado (108 megawatts) and sell their power output to Public Service Company of Colorado under long-term agreements. The acquisition was accounted for as a purchase for accounting purposes and, accordingly, the Thermo assets acquired and liabilities assumed were recorded at their fair market values as of the 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 The Total Purchase Price Consisted of the Following: dollars) Cash Paid $ 35 Note Payable to Seller 119 Transaction Fees 2 --------- Total $ 156 ========= The Purchase Price was Allocated as Follows: Investments $ 109 Property, Plant and Equipment 38 Minority Interest (2) Liabilities Assumed and Other (14) Goodwill 25 --------- Total $ 156 =========
Payments for the Thermo interests were made over a two-year period, with the initial payment of 1,034,715 shares of our common stock having been made on October 21, 1998. Additional payments were made on January 4, 1999, consisting of 833,623 shares of our common stock and $15 million in cash, on April 20, 1999, consisting of 1,232,286 shares of our common stock and $20 million in cash and on April 20, 2000, with 961,153 shares of our common stock. Under the purchase agreement, we were entitled, as soon as the consent of the other partner was obtained, to become a partner in a 50/50 joint venture in which Thermo had previously been a partner and, in the interim, to receive cash distributions from Thermo's former owners in lieu of our share of the joint venture's earnings. In the fourth quarter of 2000, we obtained the consent, became a partner in the venture and adopted the equity method of accounting for this investment. We restated all prior periods to reflect the equity method of accounting as required by the authoritative accounting guidelines. This restatement had the effect of decreasing operating revenues by $7.4 million and $4.9 million, increasing equity in earnings of unconsolidated subsidiaries by $10.5 million and $8.7 million, and increasing income from continuing operations by $1.8 million and $2.2 million, in each case for 1999 and 1998, respectively. On January 30, 1998, we acquired all of the outstanding shares of capital stock of MidCon Corp. from Occidental Petroleum Corporation for $2.1 billion in cash and the assumption of a $1.4 billion short-term note (which was repaid in January, 1999), at which time MidCon Corp. became our wholly owned subsidiary. MidCon was an energy company engaged in the purchase, gathering, processing, transmission and storage of natural gas and whose principal asset was Natural Gas Pipeline Company of America (NGPL). The assets, liabilities and results of operations of MidCon are included with those of Kinder Morgan beginning with the January 30, 1998 acquisition date. The acquisition was initially financed through a combination of credit agreements; see Note 12. The acquisition was accounted for as a purchase for accounting purposes and, accordingly, the MidCon assets acquired and liabilities assumed were recorded at their fair market values as of the 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: 54 55 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
(millions of The Total Purchase Price Consisted of the Following: dollars) Cash Consideration Paid at Closing $ 2,104 Assumption of Short-term Note 1,395 Transaction Fees 60 Working Capital Adjustment 25 ----------- Total $ 3,584 =========== The Purchase Price was Allocated as Follows: Cash and Cash Equivalents $ 14 Restricted Deposits 19 Accounts Receivable 479 Inventories 51 Gas Imbalances and Other Current Assets 112 Investments 50 Other Non-current Assets 14 Property, Plant and Equipment, Net 5,308 Accounts Payable (317) Gas Imbalances and Other Current Liabilities (366) Deferred Income Taxes (1,588) Other Non-current Liabilities (185) Minority Interest (7) ----------- Total $ 3,584 ===========
The allocation of purchase price resulted in the recognition of a gas plant acquisition adjustment of approximately $4.0 billion, principally representing the excess of the assigned fair market value of the assets of Natural Gas Pipeline Company of America over the historical cost for ratemaking purposes. This gas plant acquisition adjustment, none of which is currently being recognized for rate-making purposes, is being amortized over 55 years (see Note 4), approximately the estimated remaining useful life of Natural Gas Pipeline Company of America's interstate pipeline system. For the years ended December 31, 2000, 1999 and 1998, $73.3 million, $96.0 million and $97.9 million of such amortization, respectively, was charged to expense; see Note 4. The following pro forma information gives effect to our acquisition of MidCon Corp. as if the business combination had occurred at January 1, 1998. 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 the date indicated, nor is it necessarily comparable to subsequent financial results nor should it necessarily be viewed as an indicator of future financial results. UNAUDITED PRO FORMA FINANCIAL INFORMATION
YEAR ENDED (Dollars in Millions Except Per Share Amounts) DECEMBER 31, -------------- 1998 ---- Operating Revenues $ 4,655.9 Net Income $ 65.6 Diluted Earnings Per Common Share $ 1.01 Number of Shares Used in Computing Diluted Earnings Per Common Share (In Thousands) 64,636
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. 55 56 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) 3. 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 Income Statement 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. The $5.8 million pre-tax expense ($3.6 million after tax or $0.06 per diluted share) included under the same caption for the year ended December 31, 1998 represents costs associated with our January 30, 1998 acquisition of MidCon Corp. For additional information on these business combinations, see Note 2. 4. 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). 5. INVESTMENTS AND SALES See Note 6 for information regarding sales of assets and businesses included in discontinued operations. In December 2000, we sold approximately $300 million of assets to Kinder Morgan Energy Partners effective December 31, 2000. The largest asset we sold was our wholly owned subsidiary Kinder Morgan Texas Pipeline, L.P. and certain associated entities (a major intrastate natural gas pipeline system). We also sold 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 sale, we received approximately $150 million in cash (with an additional cash payment for working capital), 0.6 million Kinder Morgan Energy Partners' common limited partner units and 2.7 million Class-B Kinder Morgan Energy Partners' common limited partner units. 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. In August 2000, Kinder Morgan Power Company, one of our wholly owned subsidiaries, announced plans to build a 550-megawatt electric power plant in Jackson, Michigan. All necessary regulatory permits and approvals have been obtained, and construction on the $250 million natural gas-fired plant has begun. The plant is expected to begin commercial operation in July 2002. In May 2000, Kinder Morgan Power announced another 550-megawatt facility that is currently being constructed near Little Rock, Arkansas. 56 57 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) In April 2000, Kinder Morgan Energy Partners issued 4.5 million limited partnership units in a public offering at a price of $39.75 per unit, receiving total net proceeds (after underwriting discount) of $171.3 million. We did not acquire any of these units. This transaction reduced our 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) the monthly amortization of the excess investment by approximately $176 thousand. In February 2000, Kinder Morgan Energy Partners issued approximately 0.6 million common units as consideration for acquiring all the capital stock of Milwaukee Bulk Terminals, Inc. and Dakota Bulk Terminals, 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(P) and 2. 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 share). 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 sold 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 9,810,000 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 $158.8 million (approximately $100.9 million after tax or $1.25 per diluted share) in conjunction with the sale of 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 pretax 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, realizing a gain of $2.2 million (approximately $1.3 million after tax or $0.02 per diluted share). In May 1999, we announced plans to build the Horizon Pipeline, which, through our wholly owned subsidiary Natural Gas Pipeline Company of America, we planned to own jointly with one or more other partners. An open season closed in June 1999 with service requests from shippers of more than 800 MMcf of natural gas per day, including 300 MMcf per day from Nicor Gas. In February 2000, Nicor, Inc. announced that it had signed an agreement to become an equal partner in the planned Horizon Pipeline with Natural Gas Pipeline Company of America. The Horizon Pipeline is a $75 million natural gas pipeline that will originate in Joliet, Illinois and extend 74 miles into northern Illinois, connecting the emerging supply hub at Joliet with Nicor Gas' distribution system and an existing Natural Gas Pipeline Company of America pipeline. 57 58 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) 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. On October 14, 1998, TransColorado entered into a $200 million revolving credit agreement with a group of commercial banks. We provide a corporate guarantee for one-half of all amounts borrowed under the agreement. 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 9. In September 1998, we sold some of our microwave towers and associated land and equipment to American Tower Corp., recognizing a pre-tax gain of $10.9 million ($6.7 million after tax or $0.10 per diluted share). In March 1998, we sold our Kansas retail natural gas distribution properties to Midwest Energy, Inc., recognizing a pre-tax gain of $8.5 million ($5.2 million after tax or $0.08 per diluted share). Concurrently with the sale, we received $27.5 million in cash in exchange for release of the purchaser from certain contractual gas purchase obligations, which amount is being amortized as an offset to gas purchases over a period of years as the associated volumes are sold. 6. 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 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. 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 Income. The following table contains additional information concerning our international operations. INTERNATIONAL OPERATIONS
YEAR ENDED DECEMBER 31, -------------------------------------------- 2000 1999 1998 ---- ---- ---- (Thousands of dollars) Total Assets (at December 31) $32,347 $25,325 $12,838 Total Liabilities (at December 31) $ 3,984 $ 29 $ 779 Operating Revenues $ 5,699 $ 1,129 $ 4,249 Operating Loss $ 2,071 $ 2,523 $ 631
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 Income, Consolidated Balance Sheets 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 Current Assets of Discontinued Operations"; "Net Non-current Assets of Discontinued Operations"; "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. 58 59 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) Summarized financial data of discontinued operations are as follows:
YEAR ENDED DECEMBER 31, --------------------------------------------- 2000 1999 1998 ---- ---- ---- Income Statement Data (In Thousands) Operating Revenues: Wholesale Natural Gas and Liquids Marketing $ 580,159 $3,550,568 $2,580,459 Gathering and Processing, Including Field Services and Short-haul Intrastate Pipelines $ 436,979 $ 630,005 $ 640,623 Loss From Discontinued Operations, Net of Tax: Wholesale Marketing, Net of Tax Benefits of $9,300 and $7,869 $ (15,046) $ (14,837) Gathering and Processing, Net of Tax Benefits of $18,177 and $30,733 $ (29,404) $ (57,949) EN*able/Orcom, Net of Tax Benefits of $4,150 and $2,757 $ (6,491) $ (5,198) 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 $23.7 million at December 31, 2000 associated with these discontinued operations, principally consisting of (i) indemnification obligations under the various sale agreements and (ii) retained liabilities, which were settled in cash in early 2001. 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 our gathering and processing businesses in Oklahoma, Kansas and West Texas. In addition, ONEOK purchased our marketing and trading business, as well as certain storage 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 (subject to post-closing adjustment). In addition, ONEOK assumed (i) the operating lease associated with the Bushton, Kansas processing plant and (ii) long-term throughput capacity commitments on Natural Gas Pipeline Company of America and Kinder Morgan Interstate. 59 60 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) 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. During the fourth quarter of 2000, Wildhorse Energy Partners, LLC distributed all of its assets to the members and was dissolved. Formed in 1996, Wildhorse was owned 55 percent by us and 45 percent by Tom Brown. 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 5. 7. 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 in accordance with SFAS No. 125, "Accounting for Transfer and Servicing of Financial Assets and Extinguishment of Liabilities." Accordingly, our accompanying Consolidated Balance Sheet at December 31, 1999, reflects the portion of receivables transferred to the financial institution as a reduction of Accounts Receivable. Losses from the sale of these receivables are included in "Other, Net" in the accompanying Consolidated Statements of Income 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 on September 30, 1999. The proceeds were subsequently used to retire notes payable of Kinder Morgan Delaware that were outstanding when we acquired it. 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. In February 2000, we reduced our participation in this receivables sale program by approximately $120 million, 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 this agreement. 8. REGULATORY MATTERS On July 17, 2000, Natural Gas Pipeline Company of America filed its Compliance Plan, including pro forma tariff sheets, pursuant to the Federal Energy Regulatory Commission'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. Natural Gas Pipeline Company of America's filing is currently pending FERC action and any changes to its tariff provisions are not expected to take effect until after the entire Order 637 process is finished for all interstate pipelines. 60 61 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) On May 10, 2000, Chesapeake Panhandle Limited Partnership filed a complaint with the FERC against Natural Gas Pipeline Company of America, MidCon Gas Products Corp., MidCon Gas Services Corp., K N Energy, Inc. and us. The complaint alleges that Natural Gas Pipeline Company of America collected an unlawful gathering rate from Chesapeake for the period March 1998 through December 1999. Chesapeake is seeking a refund totaling $5.2 million. We have responded and denied the allegations. On July 27, 2000, the FERC issued an order commencing a preliminary non-public investigation into the complaint. We believe that we have meritorious defenses to the claim. On January 23, 1998, Kinder Morgan Interstate filed a general rate case with the FERC, requesting a $30.2 million increase in annual revenues. As a result of the FERC's action, Kinder Morgan Interstate was allowed to place its rates into effect on August 1, 1998, subject to refund, and provisions for refund were recorded based on expected ultimate resolution. On November 3, 1999, Kinder Morgan Interstate filed a comprehensive Stipulation and Agreement to resolve all issues in this proceeding. The FERC approved the Stipulation and Agreement on December 22, 1999, and the settlement rates have been placed in effect. Kinder Morgan Interstate was sold to Kinder Morgan Energy Partners effective December 31, 1999; see Note 5. In November 1997, we announced a plan to give residential and small commercial customers in Nebraska a choice of natural gas suppliers. This program, the Nebraska Choice Gas program, became effective June 1, 1998. This program separates, or "unbundles," the consumer's natural gas purchases from other utility services. As of December 31, 2000, the plan had been approved by 178 of the 181 Nebraska municipalities we serve, representing approximately 91,000 customers served by us in Nebraska. 9. ENVIRONMENTAL AND LEGAL MATTERS (A) Environmental Matters On December 20, 1999, the U.S. Department of Justice filed a Complaint against Natural Gas Pipeline Company of America on behalf of the U.S. Environmental Protection Agency in the Federal District Court of Colorado, Civil Action 99-S-2419. The Complaint alleged that Natural Gas Pipeline Company of America failed to obtain all of the necessary air quality permits in 1979 when it constructed the Akron Compressor Station, which consisted of three compressor engines in Weld County, Colorado. Natural Gas Pipeline Company of America and the Environmental Protection Agency, through the Department of Justice, have settled this issue. On December 17, 1999, the State of Colorado notified us of air quality permit compliance issues for several Kinder Morgan facilities. On September 21, 2000, we entered into a consent order with the State of Colorado to resolve the outstanding issues. In 1998, the Environmental Protection Agency published a final rule addressing transport of ground level ozone. The rule affected 22 Eastern and Midwestern states, including Illinois and Missouri, in which we operate gas compression facilities. The rule required reductions in emissions of nitrogen oxide, a precursor to ozone formation, from various emission sources, including utility and non-utility sources. The rule required that the affected states prepare and submit State Implementation Plans to the Environmental Protection Agency by September 1999, reflecting how the required emissions reductions would be achieved. Emission controls are required to be installed by May 1, 2003. The State Implementation Plans which will effectuate this rule have yet to be proposed or promulgated, and will require detailed analysis before their final economic impact can be ascertained. On March 3, 2000, the Washington D.C. Circuit Court issued a decision regarding the rule. The Circuit Court remanded certain issues back to the Environmental Protection Agency. On January 5, 2001, the Environmental Protection Agency proposed regulations concerning the remanded issues. The final regulations are expected to be promulgated later this year. While additional capital costs are likely to result from this rule, based on currently available information, we do not believe that these costs will have a material adverse effect on our business, cash flows, financial position or results of operations. 61 62 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) On June 17, 1999, the Environmental Protection Agency published a final rule creating a standard to limit emissions of hazardous air pollutants from oil and natural gas production as well as from natural gas transmission and storage facilities. The standard requires that the affected facilities reduce emissions of hazardous air pollutants by 95 percent. This standard will require us to achieve this reduction either by process modifications or by installing new emissions control technology. The standard will affect our competitors and us in a like manner. The rule allows affected sources three years from the publication date to come into compliance. We have conducted a detailed analysis of the final rule to determine its overall effect. While additional capital costs are likely to result from this rule, the rule will not have a material adverse effect on our business, cash flows, financial position or results of operations. We have an established environmental reserve of approximately $19 million to address remediation issues associated with 38 projects. Based on current information and taking into account reserves established for environmental matters, we do not believe that compliance with federal, state and local environmental laws and regulations will have a material adverse effect on our business, cash flows, financial position or results of operations. In addition, the clean-up programs in which we are engaged are not expected to interrupt or diminish our operational ability to gather or transport natural gas. However, there can be no assurances that future events, such as changes in existing laws, the promulgation of new laws, or the development of new facts or conditions will not cause 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 and several of its 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, tortuous 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 stems from Questar's failure to support the TransColorado partnership, together with its decision to seek regulatory approval for a project that competes with the Partnership, in breach of 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 certain of our entities and us 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. On December 15, 2000, 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. On January 31, 2001, 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. Discovery has commenced. "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. No trial date has been set. However, recent settlement conferences have occurred. 62 63 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) "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 gas, mismeasured gas, delayed his development of gas reserves, and other claims arising out of a contract to purchase gas from a field in northwest Colorado. On February 13, 1997, the trial judge entered partial summary judgment for Mr. Grynberg on his contract claim that he failed to receive the proper price for his 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 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 gas to interstate commerce. The background of that proceeding is described in the immediately following paragraph. On March 15, 1999, an Administrative Law Judge for the FERC ruled, after an evidentiary hearing, that Mr. Grynberg had illegally diverted the 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. Grynberg recently filed a Notice of Appeal of the FERC's decision to the D.C. Circuit Court of Appeals. The action in Colorado remains stayed pending final resolution of these proceedings. "Jack J. Grynberg v. Rocky Mountain Natural Gas Company," Docket No. GP91-8-008. "Rocky Mountain Natural Gas Company v. Jack J. Grynberg," Docket No. GP91-10-008. On May 8, 1991, Grynberg filed a petition for declaratory order with the FERC seeking a determination whether he was entitled to the price he seeks in the Jefferson County District Court proceeding referred to in the immediately preceding paragraph. While Grynberg initially received a favorable decision from the FERC, that decision was reversed by the Court of Appeals for the District of Columbia Circuit on June 6, 1997. This matter has been remanded to the FERC for subsequent proceedings. The matter was set for an expedited evidentiary hearing, and an Initial Decision favorable to Rocky Mountain was issued on March 15, 1999. That decision determined that Grynberg had intentionally diverted gas from an earlier dedication to interstate commerce in violation of the Natural Gas Act and denied him equitable administrative relief. On November 21, 2000, the FERC upheld the Administrative Law Judge's factual findings and denial of retroactive abandonment. Grynberg recently filed a Notice of Appeal of the FERC's decision to the D.C. Circuit Court of Appeals. "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 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. 63 64 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) "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 purport to represent a class of natural gas producers and fee royalty owners who allege that they have been subject to systematic gas mismeasurement by the defendants for more than 25 years. 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 Motion to Reconsider the remand was filed and is currently pending. "Dirt Hogs, Inc. v. Natural Gas Pipeline Company of America, et al." There have been several related cases with Dirt Hogs, Inc. with allegations of breach of contract, false representations, improper requests for kickbacks and other improprieties. Essentially, the plaintiff claims that it should have been awarded extensive pipeline reclamation work without having to qualify or bid as a qualifying contractor. Case No. Civ-98-231-R, is a case which was dismissed in the U.S. District Court for the Western District of Oklahoma because of pleading deficiencies and is now on appeal to the 10th Circuit (Case No. 99-6-026). On April 10, 2000, the 10th Circuit upheld the dismissal of this action. Another case, arising out of the same factual allegations, was filed by Dirt Hogs in the District Court, Caddo County, Oklahoma (Case No. CJ-99-92), on March 29, 1999. By agreement of all parties, this action is currently stayed. A third related case, styled "Natural Gas Pipeline Company of America, et al. v. Dirt Hogs, Inc." (Case No. 99-360-R), resulted in a default judgment against Dirt Hogs. After initially appealing the default judgment, Dirt Hogs dismissed their appeal on September 1, 1999. "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. 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. 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 February 23, 2000, the federal district court dismissed this Complaint with prejudice. 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, 2000, the federal district court dismissed several claims raised by the plaintiff, with prejudice, and dismissed the remaining claims, without prejudice. 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 business, cash flows, financial position or results of operations. 64 65 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) 10. 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, 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 79,696 2,608 77,088 General and Other 142,773 56,745 86,028 ------------ ------------ ------------ PP&E Related to Continuing Operations $ 6,137,009 $ 412,392 $ 5,724,617 ============ ============ ============
DECEMBER 31, 1999 -------------------------------------------------------------- PROPERTY, PLANT ACCUMULATED AND EQUIPMENT D&A NET ------------- --- --- (In Thousands) Natural Gas Pipelines $ 5,768,566 $ 240,949 $ 5,527,617 Retail Natural Gas Distribution 248,998 83,010 165,988 Electric Power Generation 27,873 1,915 25,958 General and Other 121,814 51,813 70,001 ------------ ------------ ------------ PP&E Related to Continuing Operations $ 6,167,251 $ 377,687 $ 5,789,564 ============ ============ ============
11. 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, ----------------------------------------------------- 2000 1999 1998 ---- ---- ---- (Dollars in thousands) TAXES CURRENTLY PAYABLE: Federal $ 3,212 $ 19,340 $ 49,630 State 14,091 13,784 8,564 --------- --------- --------- Total 17,303 33,124 58,194 --------- --------- --------- TAXES DEFERRED: Federal 94,435 64,086 25,068 State 10,989 (6,477) (552) --------- --------- --------- Total 105,424 57,609 24,516 --------- --------- --------- TOTAL TAX PROVISION $ 122,727 $ 90,733 $ 82,710 ========= ========= ========= EFFECTIVE TAX RATE 40.0% 36.8% 37.1% ===== ===== =====
65 66 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) The difference between the statutory federal income tax rate and our effective income tax rate is summarized as follows:
YEAR ENDED DECEMBER 31, --------------------------------------- 2000 1999 1998 ---- ---- ---- FEDERAL INCOME TAX RATE 35.0% 35.0% 35.0% INCREASE (DECREASE) AS A RESULT OF: State Income Tax, Net of Federal Benefit 5.6% 1.9% 2.1% Other (0.6%) (0.1%) - ----- ----- ----- EFFECTIVE TAX RATE 40.0% 36.8% 37.1% ===== ===== =====
Deferred tax assets and liabilities result from the following:
DECEMBER 31, ---------------------------------- 2000 1999 ---- ---- (Dollars In Thousands) DEFERRED TAX ASSETS: Post-retirement Benefits $ 14,776 $ 28,299 Gas Supply Realignment Deferred Receipts 17,101 15,847 State Taxes 138,976 112,049 Book Accruals 39,505 29,186 Alternative Minimum Tax Credits 9,098 8,222 Net Operating Loss Carryforwards 107,033 112,080 Discontinued Operations 9,584 208,317 Capital Loss Carryforwards 42,914 - Other 4,269 6,765 ----------- ----------- TOTAL DEFERRED TAX ASSETS 383,256 520,765 ----------- ----------- DEFERRED TAX LIABILITIES: Property, Plant and Equipment 2,009,086 2,087,109 Investments 654,263 656,781 Other 4,403 8,099 ----------- ----------- TOTAL DEFERRED TAX LIABILITIES 2,667,752 2,751,989 ----------- ----------- NET DEFERRED TAX LIABILITIES $ 2,284,496 $ 2,231,224 =========== ===========
For tax purposes we had available, at December 31, 2000, net operating loss carryforwards for regular federal income tax purposes of approximately $306 million which will expire as follows: $66 million in the year 2018, $211 million in the year 2019 and $29 million in the year 2020. We also had available, at December 31, 2000, capital loss carryforwards of $122 million which will expire in the year 2005. We believe it is more likely than not that all of the net operating loss carryforwards and capital loss carryforwards will be utilized prior to their expiration; therefore no valuation allowance is necessary. We also had available, at December 31, 2000, approximately $9 million of alternative minimum tax credit carryforwards which are available indefinitely. 12. FINANCING (A) Notes Payable At December 31, 2000, we had available a $500 million 364-day facility dated October 25, 2000, 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 upon issuance of common stock to the holders of the premium equity participating security units at the maturity of the security units (November 2001), 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 rating. Facility fees paid in 2000 and 1999 were $1.6 million and $1.9 million, respectively. At December 31, 2000 and 1999, $100 million and $300 million, respectively, was outstanding under the bank facilities. 66 67 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 2000, all commercial paper was redeemed within 52 days, with interest rates ranging from 5.60 percent to 7.50 percent. No commercial paper was outstanding at December 31, 2000. Commercial paper outstanding at December 31, 1999 was $274.4 million. The weighted-average interest rate on short-term borrowings outstanding at December 31, 1999 was 7.00 percent. Average short-term borrowings outstanding during 2000 and 1999 were $310.6 million and $620.9 million, respectively. During 2000 and 1999, the weighted-average interest rates on short-term borrowings outstanding were 6.52 percent and 5.56 percent (excluding the Substitute Note as described below), respectively. Effective with the acquisition of MidCon Corp. on January 30, 1998, we entered into a $4.5 billion credit facility consisting of (i) a $1.4 billion 364-day credit facility to support the note issued to Occidental Petroleum Corporation in conjunction with the purchase of MidCon Corp., (ii) a $2.1 billion 364-day revolving facility, (iii) the $400 million facility, providing for loans and letters of credit, of which the letter of credit usage may not exceed $100 million and (iv) a 364-day $600 million revolving credit facility. The $1.4 billion and $2.1 billion facilities could be used only in conjunction with the acquisition of MidCon Corp. In addition to the working capital and acquisition components of the $4.5 billion facility, we assumed a short-term note for $1.4 billion payable to Occidental referred to as the "Substitute Note," which was initially collateralized by letters of credit issued under the $1.4 billion facility. In March 1998, we received net proceeds of approximately $2.34 billion from the public offerings of senior debt securities of varying maturities with principal totaling $2.35 billion. The net proceeds from these offerings were used to refinance borrowings under the $4.5 billion facility and to purchase U.S. government securities to replace a portion of the letters of credit that collateralized the Substitute Note. The $2.1 billion facility was repaid in its entirety and cancelled on March 10, 1998. The Substitute Note was repaid on January 4, 1999. On January 5, 1999, we cancelled the remaining letters of credit used to collateralize the Substitute Note. On January 8, 1999, the $600 million facility was replaced with a new $600 million 364-day facility, which was essentially the same as the previous agreement. On November 18, 1999, we replaced our then-existing $600 million 364-day facility with a new $550 million 364-day facility, which has subsequently been replaced with a new $500 million 364-day facility dated October 25, 2000 as discussed above. 67 68 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) (B) Long-term Debt and Premium Equity Participating Security Units
DECEMBER 31, ------------------------------------ 2000 1999 ---- ---- (In Thousands) DEBENTURES: 6.50% Series, Due 2013 $ 50,000 $ 50,000 7.85% Series, Due 2022 24,943 25,731 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 493,000 500,000 7.45% Series, Due 2098 150,000 150,000 SINKING FUND DEBENTURES: 9.95% Series, Due 2020 20,000 20,000 9.625% Series, Due 2021 45,000 45,000 8.35% Series, Due 2022 35,000 35,000 SENIOR NOTES: 6.45% Series, Due 2001 400,000 400,000 7.27% Series, Due 2002 10,000 15,000 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 Reset Put Securities, 6.30%, Due 2021 400,000 400,000 Other 13,617 14,883 Unamortized Debt Discount (4,410) (5,121) Current Maturities of Long-term Debt (808,167) (7,167) ---------- ---------- TOTAL LONG-TERM DEBT $2,478,983 $3,293,326 ========== ==========
Maturities of long-term debt (in thousands) for the five years ending December 31, 2005 are $808,167, $10,417, $507,167, $7,167 and $507,167, respectively. The 2013 Debentures and the 2001, 2003 and 2005 Senior Notes are not redeemable prior to maturity. The 2022, 2028 and 2098 Debentures, the 2020 Sinking Fund 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 2021 and 2022 Sinking Fund Debentures are redeemable in whole or in part, at our option after August 1, 2001 and September 15, 2002, respectively, at redemption prices defined in the associated prospectus supplements. In November 1998 we sold $460 million principal amount of premium equity participating security units in an underwritten public offering. The net cash proceeds from the sale of the security units, together with additional funds we provided, were used to purchase U.S. Treasury Notes on behalf of the security unit holders. The Treasury Notes are the property of the security unit holders and are pledged to the collateral agent, for our benefit, to secure the obligation of the security unit holders to purchase our common stock. These security units obligate the holders to purchase a certain amount of our common stock, depending on the market price at November 30, 2001 (unless earlier terminated or settled at the option of the holders of the security units), and provide for the holders to receive interest at the rate of 8.25 percent per year during the three-year period. The interest is paid by the agent, which receives part of the necessary funds from the collateral agent, which holds 5.875% U.S. Treasury Notes purchased with the proceeds of the initial investment by the security unit holders. We pay the remaining 2.375 percent. We may defer the payment of all or any part of our portion of the contract fees until no later than the end of the three-year period. Any portion so deferred will accrue interest at the annual rate of 8.25 percent until paid. The face value of the security units is not recorded in the accompanying Consolidated Balance Sheets. The $29.4 million present value of the contract fee payable to the security unit holders has been recorded as a liability and as a reduction to paid-in capital. During the period in which the 2.375 percent contract fees are payable, accretion of the $3.4 million of discount initially recorded will increase the liability and further decrease paid-in capital. In addition, paid-in capital has been reduced for the issuance costs associated with the security units and the premium paid upon purchase of the Treasury Notes pledged to the collateral agent, which amounts total approximately $32.8 million. 68 69 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) The $400 million of Reset Put Securities due March 1, 2021 are subject to mandatory redemption from the then-existing holders on March 1, 2001, either (i) through the exercise of a call option by Morgan Stanley & Co. International Limited or (ii) in the event Morgan Stanley does not exercise the call option, the automatic exercise of a mandatory put by First Trust National Association on behalf of the holders. The $12 million of proceeds we received from Morgan Stanley as consideration for the call option are being amortized as an adjustment to the effective interest rate on the Reset Put Securities. We currently expect that these securities will not be remarketed but, instead, will be retired utilizing a combination of cash and incremental short-term borrowings. This retirement is expected to result in an extraordinary loss, net of tax, of approximately $15 million. At December 31, 2000 and 1999, the carrying amount of our long-term debt was $3.3 billion and $3.3 billion, respectively. The estimated fair values of our long-term debt at December 31, 2000 and 1999 are shown in Note 18. (C) Capital Securities In April 1998, we sold $175 million of 7.63% Capital Trust Securities maturing on April 15, 2028, and in April 1997, we sold $100 million of 8.56% Capital Trust Securities maturing on April 15, 2027, each in an underwritten public offering. We created wholly owned business trusts, K N Capital Trust I and K N Capital Trust III, to make the sales. 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 Income. See Note 18 for the fair value of these securities. (D) Common Stock 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. On November 9, 1998, our Board of Directors approved a three-for-two split of our common stock. The stock split was distributed on December 31, 1998, to shareholders of record at the close of business on December 15, 1998. The par value of the stock did not change. In March 1998, we received net proceeds of approximately $624.6 million from a public offering of 12.5 million shares (18.75 million shares after adjustment for the December 1998 three-for-two stock split) of our common stock. The net proceeds from this offering were used to refinance borrowings under the $4.5 billion Facility and to purchase U.S. government securities to replace a portion of the letters of credit that collateralized the Substitute Note. 69 70 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) 13. 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, 2000 and 1999, we did not have any outstanding shares of Class A $5.00 Cumulative Series Preferred Stock. At December 31, 1998, we had 70,000 shares of Class A $5.00 Cumulative Series Preferred Stock outstanding. (B) Class B Preferred Stock We did not have any outstanding shares of Class B Preferred Stock at December 31, 2000, 1999 or 1998. 14. RISK MANAGEMENT We use energy financial instruments to reduce our risk of price changes in the spot and fixed price natural gas markets as discussed following. We are exposed to credit-related losses in the event of nonperformance by counterparties to these financial instruments but, given their existing credit ratings, 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. Market quotes are available for substantially all financial instruments we use. Energy risk management products we use include commodity futures and options contracts, fixed-price swaps and basis swaps. Pursuant to our Board of Director'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 gas sales, gas purchases, system use and storage in order to protect profit margins, and are prohibited from engaging in speculative trading. Commodity-related activities of the risk management group are monitored by our Risk Management Committee, which is charged with the review and enforcement of the Board of Director's risk management policy. Gains and losses on hedging positions are deferred and recognized as gas purchases expense in the periods in which the underlying physical transactions occur. Purchases or sales of commodity contracts require a dollar amount to be placed in margin accounts. In addition, 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. At December 31, 2000, we had $10.0 million in margin deposits associated with commodity contract positions and $4.0 million in margin deposits associated with over-the-counter swaps. These amounts are shown as "Restricted Deposits" in the accompanying Consolidated Balance Sheets. The differences between the current market value and the original physical contracts value, associated with hedging activities, are reflected, depending on maturity, as deferred charges or credits and other current assets or liabilities in the accompanying Consolidated Balance Sheets but, in 2001, will be included with "Other Comprehensive Income" as discussed following. 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. 70 71 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) Given our portfolio of businesses as of December 31, 2000, our principal uses of derivative financial instruments will be to mitigate the risk associated with market movements in the price of natural gas associated with (i) the sale of in-kind fuel recoveries in excess of fuel used on Natural Gas Pipeline Company of America's pipeline system and (ii) the purchase of natural gas by Kinder Morgan Retail to serve its customers in the Choice Gas program. The "short" and "long" positions shown in the table that follows are principally associated with the activities described under (i) and (ii), respectively. Following is selected information concerning our risk management activities:
DECEMBER 31, 2000 ------------------------------------------------------- COMMODITY OVER-THE-COUNTER CONTRACTS SWAPS AND OPTIONS TOTAL ---------- ----------------- ----- (In contracts and thousands of dollars) Deferred Net (Loss) Gain $ 14,036 $ (28,466) $ (14,430) Contract Amounts - Gross $ 65,730 $ 163,991 $ 229,721 Contract Amounts - Net $ 540 $ (93,283) $ (92,743) Credit Exposure of Loss $ 2,514 $ 2,514 Notional Volumetric Positions: Long 419 1,296 Notional Volumetric Positions: Short (500) (2,913) Net Notional Totals To Occur in 2001 (81) (1,459) Net Notional Totals To Occur in 2002 - (158)
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (the "Statement"). The Statement establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. The Statement requires that changes in the derivatives fair value be recognized currently in earnings unless specific hedge accounting criteria are met. If the derivatives meet these criteria, the Statement allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company formally designate a derivative as a hedge and document and assess the effectiveness of derivatives associated with transactions that receive hedge accounting. The Statement, after amendment by SFAS 137 and SFAS 138, is effective for all quarters of all fiscal years beginning after June 15, 2000. The Statement cannot be applied retroactively. As discussed preceding, our principal use of derivative financial instruments is to mitigate the market price risk associated with anticipated transactions for the purchase and sale of natural gas. The Statement allows these transactions to continue to be treated as hedges for accounting purposes, although the changes in the market value of these instruments will affect comprehensive income in the period in which they occur and any ineffectiveness in the risk mitigation performance of the hedge will affect net income currently, although we do not expect the amount of such inefficiency to be material. The change in the market value of these instruments representing effective hedge operation will continue to affect net income in the period in which the associated physical transactions are consummated. Adoption of the Statement has resulted in the $14.4 million deferred net loss shown in the preceding table being reported as part of other comprehensive income, as well as subsequent changes in the market value of these derivatives prior to consummation of the transaction being hedged. 71 72 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) 15. 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." 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 $11.5 million and $5.1 million as of December 31, 2000 and 1999, respectively. Net periodic pension cost includes the following components:
YEAR ENDED DECEMBER 31, ---------------------------------------------------- 2000 1999 1998 ---- ---- ---- (In Thousands) Service Cost $ 7,306 $ 9,977 $ 4,859 Interest Cost 8,600 8,170 7,537 Expected Return on Assets (14,034) (13,381) (11,812) Net Amortization and Deferral (1,257) (210) (864) Recognition of Curtailment Gain - (9) - ---------- ---------- ---------- Net Periodic Pension (Benefit) Cost $ 615 $ 4,547 $ (280) ========== ========== ==========
The following table sets forth the reconciliation of the beginning and ending balances of the pension benefit obligation:
2000 1999 ---- ---- (In Thousands) Benefit Obligation at Beginning of Year $ (118,038) $ (121,076) Service Cost (7,306) (9,977) Interest Cost (8,600) (8,170) Actuarial Gain 3,922 14,602 Benefits Paid 6,915 6,421 Curtailment Gain - 162 ---------- ---------- Benefit Obligation at End of Year $ (123,107) $ (118,038) ========== ==========
72 73 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) 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 amounts recognized under the caption "Other Current Assets" in our Consolidated Balance Sheets:
DECEMBER 31, ------------------------------- 2000 1999 ---- ---- (In Thousands) Fair Value of Plan Assets at Beginning of Year $ 150,900 $ 143,983 Actual Return on Plan Assets During the Year 17,294 13,338 Benefits Paid During the Year (6,915) (6,421) ---------- ---------- Fair Value of Plan Assets at End of Year 161,279 150,900 Benefit Obligation at End of Year (123,107) (118,038) ---------- ---------- Plan Assets in Excess of Projected Benefit Obligation 38,172 32,862 Unrecognized Net Gain (33,134) (27,080) Prior Service Cost Not Yet Recognized in Net Periodic Pension Costs 88 105 Unrecognized Net Asset at Transition (696) (842) ---------- ---------- Prepaid Pension Cost $ 4,430 $ 5,045 ========== ==========
The rate of increase in future compensation was 3.5 percent for 2000, 1999 and 1998. The expected long-term rate of return on plan assets was 9.5 percent for 2000 and 1999, and 8.5 percent for 1998. The weighted-average discount rate used in determining the actuarial present value of the projected benefit obligation was 7.75 percent for 2000 and 1999, and 6.75 percent for 1998. 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 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. 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 or retirement. 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 2000 was $3.7 million. No contribution was made to the profit sharing plan for 1999 or 1998. In January 1998, we acquired the MidCon Retirement Plan as part of our acquisition of MidCon Corp. (See Note 2.) 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 and 1998, we contributed $0.7 million and $4.6 million, respectively, to the MidCon plan. 73 74 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) (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. (see Note 2). 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, ----------------------------------------------------- 2000 1999 1998 ---- ---- ---- (In Thousands) Service Cost $ 413 $ 450 $ 592 Interest Cost 7,159 6,655 6,425 Expected Return on Assets (4,790) (3,720) (2,854) Net Amortization and Deferral 992 908 919 Curtailment Gain - - (1,569) ---------- ---------- ---------- Net Periodic Postretirement Benefit Cost $ 3,774 $ 4,293 $ 3,513 ========== ========== ==========
The following table sets forth the reconciliation of the beginning and ending balances of the accumulated postretirement benefit obligation:
2000 1999 ---- ---- (In Thousands) Benefit Obligation at Beginning of Year $ (93,080) $ (101,988) Service Cost (413) (450) Interest Cost (7,159) (6,655) Actuarial Gain (Loss) (8,191) 3,278 Benefits Paid 15,918 15,330 Retiree Contributions (2,253) (2,595) ---------- ---------- Benefit Obligation at End of Year $ (95,178) $ (93,080) ========== ==========
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, 2000 1999 ---- ---- (In Thousands) Fair Value of Plan Assets at Beginning of Year $ 52,572 $ 45,364 Actual Return on Plan Assets (2,175) 4,320 Contributions by Employer 1,500 2,771 Retiree Contributions 1,726 2,246 Benefits Paid (2,467) (2,129) ----------- ----------- Fair Value of Plan Assets at End of Year 51,156 52,572 Benefit Obligation at End of Year (95,178) (93,080) ----------- ----------- Excess of Projected Benefit Obligation Over Plan Assets (44,022) (40,508) Unrecognized Net (Gain) Loss 12,779 (2,313) Unrecognized Net Obligations at Transition 11,149 12,078 ----------- ----------- Accrued Expense $ (20,094) $ (30,743) =========== ===========
74 75 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) The weighted-average discount rate used in determining the actuarial present value of the accumulated postretirement benefit obligation was 7.75 percent for 2000 and 1999, and 6.75 percent for 1998. The expected long-term rate of return on plan assets was 9.5 percent for 2000 and 1999, and 8.5 percent for 1998. The assumed health care cost trend rate was 7 percent per year for 1999 and beyond (3 percent per year for 1999 and beyond 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 2000 net periodic postretirement benefit cost by approximately $23,332 ($22,163) and would have increased (decreased) the accumulated postretirement benefit obligation as of December 31, 2000 by approximately $205,055 ($214,589). 16. 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 Option Plan, the 1992 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 and the Kinder Morgan, Inc. Amended and Restated 1999 Stock Option Plan. We also have an employee stock purchase plan. All per share amounts and shares outstanding or exercisable presented in this note have been restated to reflect the impact of the December 31, 1998, three-for-two common stock split as discussed in Note 12(D). On October 8, 1999, our Board of Directors approved the creation of the 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. The aggregate number of shares of stock that may be issued under the plan is 5.5 million. 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 approved an additional 0.5 million shares for future grants to participants in the 1992 Directors' Plan, which will be available subject to shareholder approval. 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. Certain restricted stock awards include provisions accelerating the lapsing of restrictions in the event certain operating goals are met. Compensation expense was recorded totaling $0, $8.6 million, and $3.1 million for 2000, 1999, and 1998, respectively, relating to restricted stock grants awarded under the plans.
OPTION SHARES SHARES SUBJECT GRANTED THROUGH VESTING EXPIRATION PLAN NAME TO THE PLAN 12/31/00 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 525,000 386,875 0 - 6 Months 10 Years Long-term Incentive Plan 5,700,000 2,754,839 0 - 5 Years 5 - 10 Years AOG Plan 775,500 775,500 3 Years 10 Years 1999 Plan 5,500,000 4,974,475 4 Years 10 Years
75 76 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) A summary of the status of our stock option plans at December 31, 2000, 1999 and 1998, and changes during the years then ended is presented in the table and narrative below:
2000 1999 1998 ------------------------ ------------------------ ------------------------ WTD. AVG. WTD. AVG. WTD. AVG. EXERCISE EXERCISE EXERCISE SHARES PRICE SHARES PRICE SHARES PRICE ------ ----- ------ ----- ------ ----- OUTSTANDING AT BEGINNING OF YEAR 7,542,898 $ 24.92 4,218,191 $ 24.38 3,220,065 $ 19.19 Granted 1,364,500 $ 30.42 4,837,656 $ 23.81 1,781,761 $ 31.40 Exercised (537,400) $ 19.26 (602,928) $ 8.00 (662,274) $ 16.46 Forfeited (2,276,179) $ 25.69 (910,021) $ 27.79 (121,361) $ 27.35 ---------- ---------- ---------- OUTSTANDING AT END OF YEAR 6,093,819 $ 26.05 7,542,898 $ 24.92 4,218,191 $ 24.38 ========== ======= ========== ======= ========== ======= EXERCISABLE AT END OF YEAR 2,056,771 $ 27.03 1,918,868 $ 26.54 1,794,112 $ 25.11 ========== ======= ========== ======= ========== ======= WEIGHTED-AVERAGE FAIR VALUE OF OPTIONS GRANTED $ 10.51 $ 5.83 $ 12.08 ======= ======= =======
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, ------------------------------------------- 2000 1999 1998 ---- ---- ---- RISK-FREE INTEREST RATE (%) 4.97 5.5 5.5 EXPECTED WEIGHTED-AVERAGE LIFE 4.5 years 4.0 years 4.0 years VOLATILITY 0.34 0.31 0.25 EXPECTED DIVIDEND YIELD (%) 0.38 3.2 3.5
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 $0.5 million, $0.6 million and $0.6 million related to the purchase discount offered under the ESP Plan for 2000, 1999 and 1998, respectively.
YEAR ENDED DECEMBER 31, ------------------------------------------------- 2000 1999 1998 ---- ---- ---- (In Thousands Except Per Share Amounts) NET INCOME (LOSS): As Reported $ 151,981 $ (239,661) $ 62,211 =========== ========== =========== Pro Forma $ 144,526 $ (244,513) $ 58,109 =========== ========== =========== EARNINGS (LOSS) PER DILUTED SHARE: As Reported $ 1.32 $ (2.99) $ 0.96 =========== ========== =========== Pro Forma $ 1.26 $ (3.05) $ 0.90 =========== ========== ===========
76 77 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) The following table sets forth our December 31, 2000, 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. NUMBER EXERCISE WTD. AVG. REMAINING NUMBER EXERCISE PRICE RANGE OUTSTANDING PRICE CONTRACTUAL LIFE EXERCISABLE PRICE ----------- ----------- ----- ---------------- ----------- ----- $00.00 - $23.72 166,228 $ 20.50 5.90 years 162,986 $ 20.44 $23.81 - $23.81 3,920,421 $ 23.81 8.77 years 1,018,417 $ 23.81 $24.04 - $39.38 2,007,170 $ 30.87 8.55 years 875,368 $ 32.00 ------------ ------------ 6,093,819 $ 26.05 8.61 years 2,056,771 $ 27.03 ============ ============
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 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 86,630 shares, 187,567 shares and 163,799 shares for plan years 2000, 1999 and 1998, 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 2000, 1999 and 1998 was $6.60, $6.41 and $5.94, respectively. 17. COMMITMENTS AND CONTINGENT LIABILITIES (A) Leases Expenses incurred under operating leases were $47.1 million in 2000, $57.8 million in 1999, and $56.9 million in 1998. Future minimum commitments under major operating leases as of December 31, 2000 are as follows:
YEAR AMOUNT - ---- ------ (In Thousands) 2001 $ 11,886 2002 8,376 2003 7,813 2004 7,563 2005 7,716 Thereafter 21,605 ---------- Total $ 64,959 ==========
(B) Guarantees of Unconsolidated Subsidiaries' Debt We have executed a guarantee of the revolving credit agreement of an unconsolidated subsidiary, TransColorado, in the amount of $100 million. As of December 31, 2000, $100 million had been borrowed with a maturity date of October 13, 2001. (C) Capital Expenditures Budget Approximately $5.5 million of our consolidated capital expenditure budget for 2001 had been committed for the purchase of plant and equipment at December 31, 2000. 77 78 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) (D) Commitment to Sell or Purchase Assets We announced on November 30, 1999, that we entered into agreements with HS Resources, Inc. for the sale of certain assets in the Wattenberg field area of the Denver-Julesberg Basin. Under the terms of the agreements, HS Resources, Inc. commenced operating these assets. We are receiving cash payments from HS Resources, Inc. during 2000 and 2001, with the legal transfer of ownership expected to occur on or before December 15, 2001. 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 5 and 9. 18. FAIR VALUE The following fair values of Investments, 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, -------------------------------------------------------------- 2000 1999 --------------------------- --------------------------- CARRYING CARRYING VALUE FAIR VALUE VALUE FAIR VALUE ----- ---------- ----- ---------- (In Millions) FINANCIAL ASSETS: Tom Brown, Inc. Common Stock (1) $ - $ - $ 12.3 $ 12.3 FINANCIAL LIABILITIES: Long-term Debt $ 3,291.6 $ 3,253.4 $ 3,305.6 $ 3,146.1 Capital Securities $ 275.0 $ 278.7 $ 275.0 $ 265.4 Energy Financial Instruments, Net $ 14.4 $ 14.4 $ 16.1 $ 16.1
(1) See Note 5 regarding the sale of this stock. 19. BUSINESS SEGMENT INFORMATION In accordance with the manner in which we manage our businesses, including the allocation of capital and evaluation of business unit performance, we report our operations in the following segments: (1) Natural Gas Pipeline Company of America and certain associated entities, 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 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 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 sale of Kinder Morgan Texas Pipeline, L.P. to Kinder Morgan Energy Partners and (ii) the December 31, 1999 sale 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 5. The accounting policies applied in the generation of business unit information are generally the same as those described in Note 1 to the accompanying Consolidated Financial Statements, except that items below the "Operating Income" line are either not allocated to business units or are not considered by Management in its evaluation of business unit performance. An exception to this is that Power, which routinely conducts its business activities in the form of joint operations with other parties that are accounted for under the equity 78 79 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) 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 income statement. In addition, certain items included in consolidated operating income (such as merger-related and severance costs and general and administrative expenses) are not allocated to individual business units. With adjustment for these items, we currently evaluate business unit performance primarily based on operating income in relation to the level of assets employed. Sales between business units are accounted for at market prices. For comparative purposes, prior period results and balances have been reclassified as necessary 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 2000, approximately 50% 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 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 2000, approximately 50% of its operating revenues were attributable to its nine 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 2000 and 1999, we had revenues from a single customer of $740.5 million and $ 389.4 million, respectively, amounts in excess of 10 percent of consolidated operating revenues for each year. Both Natural Gas Pipeline Company of America and Kinder Morgan Texas Pipeline made sales to this customer. With the transfer of Kinder Morgan Texas Pipeline to Kinder Morgan Energy Partners as of December 31, 2000, sales to this customer are not expected to exceed 10% of consolidated operating revenues in the future, although certain of Natural Gas Pipeline Company of America's customers may meet this threshold. 79 80 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) BUSINESS SEGMENT INFORMATION
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 $ 342,887 $ 656,035 $ (18) $ 84,975 $ 38,555 $ 5,478,183 Kinder Morgan Retail 49,732 229,510 (1) 11,776 10,730 350,042 Kinder Morgan Texas Pipeline 29,318 1,747,499 - 2,211 16,734 - Power and Other(3) 34,962 80,693 4 9,203 71,458 2,589,880(1) Discontinued Operations - - - - 3,185 - ---------- ---------- ---------- ---------- ---------- ----------- Consolidated 456,899 $2,713,737 $ (15) $ 108,165 $ 140,662 $ 8,418,105 ========== ========== ========== ========== =========== General and Administrative Expenses (58,087) Other Income and (Expenses) (92,370) ---------- Income from Continuing Operations Before Income Taxes $ 306,442 ==========
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 $ 306,507 $ 625,705 $ 1,183 $ 109,346 $ 41,716 $ 5,469,050 Kinder Morgan Interstate 53,924 96,531 16,676 16,985 20,743 - Kinder Morgan Retail 20,104 182,861 51 11,382 11,749 332,618 Kinder Morgan Texas Pipeline 16,554 872,161 - 2,466 4,567 255,200 Power and Other(3) 32,158 59,110 195 7,754 18,869 2,650,579(1) Discontinued Operations - - - - 28,363 718,227 ---------- ---------- ---------- ---------- ---------- ----------- Consolidated 429,247 $1,836,368 $ 18,105 $ 147,933 $ 126,007 $ 9,425,674 ========== ========== ========== ========== =========== General and Administrative Expenses (85,591) Merger-related and Severance Costs (37,443) Other Income and (Expenses) (59,822) ---------- Income from Continuing Operations Before Income Taxes $ 246,391 ==========
DECEMBER 31, YEAR ENDED DECEMBER 31, 1998 1998 ------------------------------------------------------------------------- ------------ 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 $ 336,825 $ 556,662 $ 299 $ 121,008 $ 40,855 $ 5,421,029 Kinder Morgan Interstate 58,006 88,244 17,333 19,474 49,044 581,089 Kinder Morgan Retail 56,214 234,307 (1) 11,014 17,405 362,289 Kinder Morgan Texas Pipeline 2,129 739,201 - 1,615 8,037 198,347 Power and Other(3) 25,458 41,845 5,535 2,252 5,540 1,519,510(2) Discontinued Operations - - - - 135,633 1,541,515 ---------- ---------- ---------- ---------- ---------- ----------- Consolidated 478,632 $1,660,259 $23,166 $ 155,363 $ 256,514 $ 9,623,779 ========== ========== ========== ========== =========== General and Administrative Expenses (68,502) Merger-related and Severance Costs (5,763) Other Income and (Expenses) (181,462) ---------- Income from Continuing Operations Before Income Taxes $ 222,905 ==========
(1) Principally the investment in Kinder Morgan Energy Partners and corporate cash and receivables (2) Principally government securities held as collateral for the Substitute Note (3) Restated, see Note 2. 80 81 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) GEOGRAPHIC INFORMATION All but an insignificant amount of our assets and operations are located in the continental United States. 81 82 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) QUARTERLY FINANCIAL INFORMATION (UNAUDITED) KINDER MORGAN, INC. AND SUBSIDIARIES QUARTERLY OPERATING RESULTS FOR 2000 AND 1999
2000 - THREE MONTHS ENDED ----------------------------------------------------------------- MARCH 31(1) JUNE 30(1) SEPTEMBER 30(1) DECEMBER 31 ----------- ---------- --------------- ----------- (In Thousands Except Per Share Amounts) Operating Revenues $ 480,481 $ 551,088 $ 750,465 $ 931,703 Gas Purchases and Other Costs of Sales 277,911 381,607 577,478 723,087 ---------- ---------- ---------- ---------- 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) 27,981(2) ---------- ---------- ---------- ---------- Income From Continuing Operations Before Income Taxes 77,212 41,081 44,846 143,303 Income Taxes 30,887 16,968 18,138 56,734 ---------- ---------- ---------- ---------- Income From Continuing Operations 46,325 24,113 26,708 86,569 Loss on Disposal of Discontinued Operations, Net of Tax - - - (31,734)(3) ---------- ---------- ---------- ---------- Net Income $ 46,325 $ 24,113 $ 26,708 $ 54,835 ========== ========== ========== ========== Number of Shares Used in Computing Basic Earnings Per Share 113,058 114,196 114,461 114,535 Number of Shares Used in Computing Diluted Earnings Per Share 113,456 114,981 116,177 118,594 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 ========== ========== ========== ========== DILUTED EARNINGS PER COMMON SHARE: Continuing Operations $ 0.41 $ 0.21 $ 0.23 $ 0.73 Loss on Disposal of Discontinued Operations - - - (0.27) ---------- ---------- ---------- ---------- Total Diluted Earnings Per Common Share $ 0.41 $ 0.21 $ 0.23 $ 0.46 ========== ========== ========== ==========
(1) Restated for a change to the equity method of accounting for an investment and reflects the reclassification of International's operating results to continuing operations. See Notes 2 and 6 of the accompanying Notes to Consolidated Financial Statements and the table presented below. (2) Includes the $62 million pre-tax gain from the sale of certain assets to Kinder Morgan Energy Partners; see Note 5 of the accompanying Notes to Consolidated Financial Statements. (3) See Note 6 of the accompanying Notes to Consolidated Financial Statements.
2000 - THREE MONTHS ENDED ---------------------------------------------- MARCH 31 JUNE 30 SEPTEMBER 30 -------- ------- ------------ (In Thousands) Income From Continuing Operations as Previously Reported $ 46,084 $ 24,827 $ 26,628 Power Restatement: Operating Revenues (1,072) (598) (97) Other Income and (Expenses) 1,892 1,618 1,092 Income Taxes (328) (408) (398) Reclassification of International Operations (251) (1,326) (517) --------- --------- --------- Income From Continuing Operations as Restated $ 46,325 $ 24,113 $ 26,708 ========= ========= =========
82 83 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
1999 - THREE MONTHS ENDED(1) --------------------------------------------------------------- MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 -------- ------- ------------ ----------- (In Thousands Except Per Share Amounts) Operating Revenues $ 425,696 $ 429,331 $ 495,906 $ 485,435 Gas Purchases and Other Costs of Sales 206,158 248,449 318,386 277,257 --------- --------- --------- --------- Gross Margin 219,538 180,882 177,520 208,178 Other Operating Expenses 118,593 119,292 107,361 107,727 Merger-Related and Severance Costs 2,916 (2,916) 10,962 26,481 --------- --------- --------- --------- Operating Income 98,029 64,506 59,197 73,970 Other Income and (Expenses) (58,162) (44,145) (48,729) 101,725(2) --------- --------- --------- --------- Income From Continuing Operations Before Income Taxes 39,867 20,361 10,468 175,695 Income Taxes 15,582 8,056 4,465 62,630 --------- --------- --------- --------- Income From Continuing Operations 24,285 12,305 6,003 113,065 --------- --------- --------- --------- Discontinued Operations, Net of Tax(3): Loss From Discontinued Operations (16,720) (14,500) (7,989) (11,732) Loss on Disposal of Discontinued Operations - - (11,479) (332,899) --------- --------- --------- --------- Total Loss From Discontinued Operations (16,720) (14,500) (19,468) (344,631) --------- --------- --------- --------- Net Income (Loss) 7,565 (2,195) (13,465) (231,566) Less-Preferred Dividends 88 41 - - Less-Premium Paid on Preferred Stock Redemption - 350 - - --------- --------- --------- --------- Earnings (Loss) Available for Common Stock $ 7,477 $ (2,586) $ (13,465) $(231,566) ========= ========= ========= ========= Number of Shares Used in Computing Basic Earnings Per Share 69,486 70,689 70,914 110,047 Number of Shares Used in Computing Diluted Earnings Per Share 69,578 70,761 70,986 110,105 BASIC EARNINGS (LOSS) PER COMMON SHARE: Continuing Operations $ 0.35 $ 0.17 $ 0.08 $ 1.03 Discontinued Operations (0.24) (0.21) (0.11) (0.11) Loss on Disposal of Discontinued Operations - - (0.16) (3.02) --------- --------- --------- --------- Total Basic Earnings (Loss) Per Common Share $ 0.11 $ (0.04) $ (0.19) $ (2.10) ========= ========= ========= ========= DILUTED EARNINGS (LOSS) PER COMMON SHARE: Continuing Operations $ 0.35 $ 0.17 $ 0.08 $ 1.03 Discontinued Operations (0.24) (0.21) (0.11) (0.11) Loss on Disposal of Discontinued Operations - - (0.16) (3.02) --------- --------- --------- --------- Total Diluted Earnings (Loss) Per Common Share $ 0.11 $ (0.04) $ (0.19) $ (2.10) ========= ========= ========= =========
(1) Restated for a change to the equity method of accounting for an investment and reflects the reclassification of International's operating results to continuing operations. See Notes 2 and 6 of the accompanying Notes to Consolidated Financial Statements and the table presented following. (2) Includes the $158 million pre-tax gain from the sale of certain assets to Kinder Morgan Energy Partners; see Note 5 of the accompanying Notes to Consolidated Financial Statements. (3) See Note 6 of the accompanying Notes to Consolidated Financial Statements. 83 84 ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
1999 - THREE MONTHS ENDED --------------------------------------------------------------- MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 -------- ------- ------------ ----------- (In Thousands) Income From Continuing Operations as Previously Reported $ 23,908 $ 12,380 $ 5,886 $ 112,478 Power Restatement: Operating Revenues (2,058) (2,580) (1,201) (1,595) Other Income and (Expenses) 2,797 2,934 2,955 1,720 Income Taxes (296) (141) (702) (50) Reclassification of International Operations (66) (288) (935) 512 --------- --------- --------- --------- Income From Continuing Operations as Restated $ 24,285 $ 12,305 $ 6,003 $ 113,065 ========= ========= ========= =========
ITEM 9: CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None 84 85 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 2001 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 2001 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 2001 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 2001 Annual Meeting of Stockholders, to be filed pursuant to Section 14 of the Securities Exchange Act of 1934 and is incorporated herein by reference. 85 86 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. (a) 2. Financial Statement Schedules KINDER MORGAN, INC. AND SUBSIDIARIES SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
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
Note: Activity and balances prior to 1999 were not material. The financial statements of Kinder Morgan Energy Partners, an equity method investee of the Registrant, are incorporated herein by reference from F-1 to F-40 of Kinder Morgan Energy Partners' Annual Report on Form 10-K for the year ended December 31, 2000 dated March 12, 2001. 86 87 ITEM 14: EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (continued) (a) 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 NO. 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) 87 88 ITEM 14: EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (continued) 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(f) $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(g) 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(h) 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(i) Purchase Contract Agreement dated as of November 25, 1998, between K N Energy, Inc. and U.S. Bank Trust National Association, as Purchase Contract Agent for the PEPS Units (Exhibit 4.4 to the Current Report on Form 8-K dated November 24, 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) 88 89 ITEM 14: EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (continued) 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(g) Form of Restricted Stock Agreement* 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) Stock Purchase Agreement dated December 18, 1997, between K N Energy, Inc. and Occidental Petroleum Corporation (Exhibit 2.1, File No. 333-44421) Exhibit 10(j) Amendment No.1 to Stock Purchase Agreement dated January 30, 1998, between K N Energy, Inc. and Occidental Petroleum Corporation (Exhibit 2(b) to the Annual Report on Form 10-K for the year ended December 31, 1997) Exhibit 10(k) Governance Agreement dated October 7, 1999, between Kinder Morgan, Inc. and Richard D. Kinder (Exhibit 99.C of the Schedule 13D filed by Mr. Kinder on October 8, 1999) Exhibit 10(l) Governance Agreement dated October 7, 1999, between Kinder Morgan, Inc. and Morgan Associates, Inc. (Exhibit 99.C of the Schedule 13D filed by Morgan Associates, Inc. and William V. Morgan on October 8, 1999) Exhibit 10(m) 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) 89 90 Exhibit 10(n) 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) Exhibit 10(o) 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 13 2000 Annual Report to Shareholders (Exhibit 13 to the Annual Report on Form 10-K for the year ended December 31, 2000) Exhibit 21 Subsidiaries of the Registrant (Exhibit 21 to the Annual Report on Form 10-K for the year ended December 31, 2000) Exhibit 23.1 Consent of Independent Accountants Exhibit 23.1 to the Annual Report on Form 10-K for the year ended December 31, 2000) Exhibit 23.2 Consent of Independent Public Accountants (Exhibit 23.2 to the Annual Report on Form 10-K for the year ended December 31, 2000) Exhibit 24.1 Power of Attorney* * Filed herewith. (b) Reports on Form 8-K (1) Current Report on Form 8-K dated March 5, 2001 was filed pursuant to Item 5 and Item 7 of that form. Pursuant to Item 5 of that form, we disclosed that on February 20, 2001, the Company issued a press release announcing that we and a unit of Williams (NYSE:WMB) had reached an agreement under which Williams will supply fuel to and market 3,300 megawatts of capacity for 16 years for six natural gas-fired, intermediate-peaking power generation facilities to be developed by Kinder Morgan Power Company over the next four years. Pursuant to Item 7 of that form, we filed the press release of the Company issued February 20, 2001 as an exhibit. (2) Current Report on Form 8-K dated February 16, 2001 was filed pursuant to Item 5 and Item 7 of that form. 90 91 ITEM 14: EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (continued) Pursuant to Item 5 of that form, we filed the following financial information of Kinder Morgan, Inc.: (1) Financial statements as of December 31, 2000 and 1999, and for the years ended December 31, 2000, 1999 and 1998; (2) Quarterly financial information (unaudited) for 2000 and 1999; (3) Selected financial data for each of the five years in the period ended December 31, 2000; (4) Management's discussion and analysis of financial condition and results of operation; (5) Quantitative and qualitative disclosures about market risk; and (6) Schedule II - Valuation and Qualifying Accounts. Pursuant to Item 7 of that form, we filed the following exhibits: 23.1 Consent of PricewaterhouseCoopers LLP 23.2 Consent of Arthur Andersen LLP 99.1 Form 8-K of Kinder Morgan Energy Partners, L.P. dated February 16, 2001, including the consolidated financial statements of Kinder Morgan Energy Partners, L.P. (3) Current Report on Form 8-K dated February 14, 2001 was filed pursuant to Item 9 of that form. Pursuant to Item 9 of that form, we filed notice that representatives of Kinder Morgan Energy Partners and the Company intended to discuss various strategic and financial issues relating to the business plans and objectives of the Company and Kinder Morgan Energy Partners at the UBS Warburg Energy Conference on February 15, 2001. We also gave notice that the materials presented at the meeting would be available for viewing prior to the meeting at the Company's web site at www.kindermorgan.com/presentations/KMI/ubswarburg02152001/index.html. (4) Current Report on Form 8-K dated February 1, 2001 was filed pursuant to Item 5 and Item 7 of that form. Pursuant to Item 5 of that form, we made three disclosures. First, we disclosed that during the fourth quarter of 2000, we changed to the equity method of accounting for our investment in the partnership that owns and operates the Ft. Lupton power generation facility. Second, we disclosed that during the fourth quarter of 2000, we decided to retain our previously discontinued international operations segment. Third, we disclosed that on January 17, 2001, we issued a press release containing earnings information and supplemental information with respect to the years ended December 31, 2000 and 1999 for our Company. Pursuant to Item 7 of that form, (1) we filed proforma financial statements of the Company, giving effect to the events we disclosed in Item 5 and (2) we filed the press release of the Company issued January 17, 2001 as an exhibit. (5) Current Report on Form 8-K dated January 30, 2001 was filed pursuant to Item 9 of that form. 91 92 Pursuant to Item 9 of that form, we filed notice that representatives of Kinder Morgan Energy Partners and the Company intended to discuss various strategic and financial issues relating to the business plans and objectives of the Company and Kinder Morgan Energy Partners at an analyst meeting on January 30, 2001. We also gave notice that the materials presented at the meeting would be available for viewing prior to the meeting at the Company's web site at www.kindermorgan.com/presentations/KMI/lehmans01302001. (6) Current Report on Form 8-K dated January 9, 2001 was filed pursuant to Item 9 of that form. Pursuant to Item 9 of that form, we filed notice that representatives of Kinder Morgan Energy Partners and the Company intended to discuss various strategic and financial issues relating to the business plans and objectives of the Company and Kinder Morgan Energy Partners at an analyst meeting on January 10, 2001. We also gave notice that the materials presented at the meeting would be available for viewing prior to the meeting at the Company's web site at www.kindermorgan.com/presentations/KMI/GoldmanSachs01202001/. (7) Current Report on Form 8-K dated November 6, 2000 was filed pursuant to Items 7 and 9 of that form. Pursuant to Item 9 of that form, in Item 7 we filed an exhibit containing presentation materials for use at a meeting with analysts and others on November 6, 2000. 92 93 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) Date: April 4, 2001 By /s/ C. Park Shaper --------------------------------------------- C. Park Shaper Vice President and Chief Financial Officer 93 94 EXHIBIT INDEX EXHIBIT NO. 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) 95 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(f) $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(g) 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(h) 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(i) Purchase Contract Agreement dated as of November 25, 1998, between K N Energy, Inc. and U.S. Bank Trust National Association, as Purchase Contract Agent for the PEPS Units (Exhibit 4.4 to the Current Report on Form 8-K dated November 24, 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) 96 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(g) Form of Restricted Stock Agreement* 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) Stock Purchase Agreement dated December 18, 1997, between K N Energy, Inc. and Occidental Petroleum Corporation (Exhibit 2.1, File No. 333-44421) Exhibit 10(j) Amendment No.1 to Stock Purchase Agreement dated January 30, 1998, between K N Energy, Inc. and Occidental Petroleum Corporation (Exhibit 2(b) to the Annual Report on Form 10-K for the year ended December 31, 1997) Exhibit 10(k) Governance Agreement dated October 7, 1999, between Kinder Morgan, Inc. and Richard D. Kinder (Exhibit 99.C of the Schedule 13D filed by Mr. Kinder on October 8, 1999) Exhibit 10(l) Governance Agreement dated October 7, 1999, between Kinder Morgan, Inc. and Morgan Associates, Inc. (Exhibit 99.C of the Schedule 13D filed by Morgan Associates, Inc. and William V. Morgan on October 8, 1999) Exhibit 10(m) 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) 97 Exhibit 10(n) 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) Exhibit 10(o) 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 13 2000 Annual Report to Shareholders (Exhibit 13 to the Annual Report on Form 10-K for the year ended December 31, 2000)** Exhibit 21 Subsidiaries of the Registrant (Exhibit 21 to the Annual Report on Form 10-K for the year ended December 31, 2000)** Exhibit 23.1 Consent of Independent Accountants Exhibit 23.1 to the Annual Report on Form 10-K for the year ended December 31, 2000)** Exhibit 23.2 Consent of Independent Public Accountants (Exhibit 23.2 to the Annual Report on Form 10-K for the year ended December 31, 2000)** Exhibit 24.1 Power of Attorney* * Filed with the Form 10-K. ** Filed with the Form 10-K/A. EX-99.2 3 h85888a1ex99-2.txt FORM 10-K/A OF KINDER MORGAN ENERGY PARTNERS, LP 1 SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ---------- FORM 10-K/A AMENDMENT NO. 1 ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 ---------- For the fiscal year ended DECEMBER 31, 2000 Commission file number: 1-11234 KINDER MORGAN ENERGY PARTNERS, L.P. (Exact name of registrant as specified in its charter) DELAWARE 76-0380342 (State or other jurisdiction (I.R.S. Employer of incorporation or organization) Identification No.) 500 DALLAS STREET, 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: Title of each class Name of each exchange on which registered - ------------------- ----------------------------------------- Common Units of Kinder Morgan New York Stock Exchange Energy Partners, L.P. SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None 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] Aggregate market value of the Common Units held by non-affiliates of the registrant, based on closing prices in the daily composite list for transactions on the New York Stock Exchange on February 28, 2001 was approximately $3,100,957,450. This figure assumes that only the general partner of the registrant, Kinder Morgan, Inc. and officers and directors of the general partner of the registrant and of Kinder Morgan, Inc. were affiliates. As of February 28, 2001, the registrant had 64,861,509 Common Units outstanding. 2 KINDER MORGAN ENERGY PARTNERS, L.P. TABLE OF CONTENTS
PAGE NO. PART I Items 1 and 2. Business and Properties 3 Item 3. Legal Proceedings 47 Item 4. Submission of Matters to a Vote of Security Holders 47 PART II Item 5. Market for the Registrant's Units and Related Security Holder Matters 48 Item 6. Selected Financial Data 49 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operation 50 Item 7a. Quantitative and Qualitative Disclosures About Market Risk 63 Item 8. Financial Statements and Supplementary Data 64 Item 9. Changes in and Disagreements on Accounting and Financial Disclosure 64 PART III Item 10. Directors and Executive Officers of the Registrant 65 Item 11. Executive Compensation 68 Item 12. Security Ownership of Certain Beneficial Owners and Management 72 Item 13. Certain Relationships and Related Transactions 73 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K 75 Financial Statements F-1 Signatures S-1
2 3 PART I ITEMS 1. AND 2. BUSINESS AND PROPERTIES GENERAL Kinder Morgan Energy Partners, L.P., a Delaware limited partnership, is a publicly traded master limited partnership formed in August 1992. We are the largest pipeline master limited partnership in terms of market capitalization and the second largest products pipeline system in the United States in terms of volumes delivered. Unless the context requires otherwise, references to "we", "us", "our", "KMP" or the "Partnership" are intended to mean Kinder Morgan Energy Partners, L.P., our operating limited partnerships and their subsidiaries. We manage a diversified portfolio of midstream energy assets that provide fee-based services to customers. Our assets primarily include: o more than 10,000 miles of product pipelines and over 20 associated terminals serving customers across the United States; o 10,000 miles of natural gas transportation pipelines, plus natural gas gathering and storage facilities; o Kinder Morgan CO2 Company, L.P., the largest transporter and marketer of carbon dioxide in the country; and o over 25 bulk terminal facilities which transload coal, liquid and other bulk products. 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 generating 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 is name to Kinder Morgan, Inc. In connection with the acquisition, Richard Kinder, Chairman and Chief Executive Officer of our general partner, became the Chairman and Chief Executive Officer of KMI. KMI trades on the New York Stock Exchange under the symbol "KMI" and is one of the largest midstream energy companies in America, operating more than 30,000 miles of natural gas and product pipelines. KMI also has significant natural gas retail distribution and electric generation. In addition, KMI, through its general partner interest, operates our portfolio of businesses and holds a significant limited partner interest in us. The address of our principal executive offices is 500 Dallas Street, Suite 1000, Houston, Texas 77002 and our telephone number at this address is (713) 369-9000. We trade under the New York Stock Exchange symbol "KMP". Our operations are grouped into four reportable business segments. These segments and their major assets are as follows: o Product Pipelines, consisting of refined petroleum product pipelines and joint venture projects including: o our Pacific operations, which are comprised of approximately 3,300 miles of pipeline that transport refined petroleum products to some of the faster growing population centers in the United States, including Los Angeles, San Diego, and Orange County, California; the San Francisco Bay Area; Las Vegas, Nevada and Tucson and Phoenix, Arizona, and 13 truck-loading terminals with an aggregate usable tankage capacity of approximately 8.2 million barrels; o our North System, a 1,600 mile pipeline that transports natural gas liquids and refined petroleum products between south central Kansas and the Chicago area and various intermediate points, including eight terminals; o our 51% interest in Plantation Pipe Line Company, which owns and operates a 3,100 mile refined petroleum products pipeline system throughout the southeastern United States, serving major metropolitan areas including Birmingham, Alabama; Atlanta, Georgia; Charlotte, North Carolina; and the Washington, D.C. area; o our 32.5% interest in the Cochin Pipeline System, a 1,900 mile multiproduct pipeline transversing Canada and the United States from Fort Saskatchewan, Alberta to Sarnia, Ontario; o our Cypress Pipeline, which transports natural gas liquids from Mont Belvieu, Texas to a major petrochemical producer in Lake Charles, Louisiana; 3 4 o our transmix operations, which include the processing and marketing of petroleum pipeline transmix via transmix processing plants in Colton, California; Richmond, Virginia; Dorsey Junction, Maryland; Indianola, Pennsylvania; and Wood River, Illinois; o our 50% interest in the Heartland Pipeline Company, which ships refined petroleum products in the Midwest; and o our Painter Gas Processing Plant, a natural gas processing plant, fractionator and natural gas liquids terminal with truck and rail loading facilities, which is leased to BP Amoco under a long-term arrangement. o Natural Gas Pipelines, consisting of assets acquired in late 1999 and 2000 including: o Kinder Morgan Interstate Gas Transmission LLC, which owns a 6,700 mile natural gas pipeline, including the Pony Express pipeline facilities, that extends from northwestern Wyoming east into Nebraska and Missouri and south through Colorado and Kansas; o Kinder Morgan Texas Pipeline L.P, which owns a 2,700 mile intrastate pipeline along the Texas Gulf Coast; o our 66 2/3% interest in the Trailblazer Pipeline Company, which transmits natural gas from Colorado through southeastern Wyoming to Beatrice, Nebraska; o our Casper and Douglas Gathering Systems, which is comprised of approximately 1,560 miles of natural gas gathering pipelines and two facilities in Wyoming capable of processing 210 million cubic feet of natural gas per day; o our 49% interest in the Red Cedar Gathering Company, which gathers natural gas in La Plata County, Colorado and owns and operates a carbon dioxide processing plant; o our 50% interest in Coyote Gas Treating, LLC, which owns a 250 million cubic feet per day natural gas treating facility in La Plata County, Colorado; and o our 25% interest in Thunder Creek Gas Services, LLC, which gathers, transports and processes coal bed methane gas in the Powder River Basin of Wyoming. o CO2 Pipelines, consisting of Kinder Morgan CO2 Company, L.P., which transports, markets and produces carbon dioxide for use in enhanced oil recovery operations in the continental United States, through the following: o Central Basin Pipeline, a 300 mile carbon dioxide pipeline located in the Permian Basin between Denver City, Texas and McCamey, Texas; o interests in carbon dioxide pipelines, including an approximate 81% interest in the Canyon Reef Carriers Pipeline, a 50% interest in the Cortez Pipeline and a 13% interest in the Bravo Dome Pipeline; o interests in carbon dioxide reserves, including an approximate 45% interest in the McElmo Dome and an approximate 11% interest in the Bravo Dome; and o interests in oil-producing fields, including an approximate 71% interest in the SACROC Unit and minority interests in the Sharon Ridge Unit, the Reinecke Unit and the Yates Field Unit, all of which are located in the Permian Basin of West Texas. o Bulk Terminals, consisting of over 25 owned or operated bulk terminal facilities including: o coal terminals located in Cora, Illinois; Paducah, Kentucky; Newport News, Virginia; Mount Vernon, Indiana; and Los Angeles, California; o petroleum coke terminals located on the lower Mississippi River and along the west coast of the United States; o liquids chemical terminals located in New Orleans, Louisiana and Cincinnati, Ohio; and o other bulk terminals handling alumina, cement, salt, soda ash, fertilizer and other dry bulk materials. BUSINESS STRATEGY Our management's objective is to grow our portfolio of businesses by: o focusing on stable, fee-based assets which are core to the energy infrastructure of growing markets; o increasing utilization of assets while containing costs; 4 5 o leveraging economies of scale from incremental acquisitions; and o maximizing the benefits of our financial structure. Since February 1997, we have announced 20 acquisitions valued at over $4.7 billion. These acquisitions and associated cost reductions have assisted us in growing from $17.7 million of net income in 1997 to $278.3 million of net income in 2000. We regularly consider and enter into discussions regarding potential acquisitions, including those from KMI or its affiliates, and are currently contemplating potential acquisitions. While there are currently no unannounced purchase agreements for the acquisition of any material business or assets, such transactions can be effected quickly, may occur at any time and may be significant in size relative to our existing assets or operations. We primarily transport and/or handle products for a fee and generally are not engaged in the purchase and sale of commodity products. As a result, we do not face significant risks relating directly to shifts in commodity prices. Product Pipelines. We plan to continue to expand our presence in the rapidly growing refined petroleum products markets in the western and southeastern United States through incremental expansions of our Pacific and Plantation pipelines and through acquisitions that increase unitholder distributions. Because our North system serves a relatively mature market, we intend to focus on increasing throughput within the system by remaining a reliable, cost-effective provider of transportation services and by continuing to increase the range of products transported and services offered. We recently assumed operation of Plantation Pipe Line Company. Our acquisition of our transmix operations in September 1999, October 2000 and December 2000 strengthened our existing transmix processing business and added fee-based services related to our core refined products pipeline business. Natural Gas Pipelines. Kinder Morgan Interstate Gas Transmission also serves a stable, mature market, and thus we are focused on reducing costs and securing throughput for this pipeline. New measurement systems and other improvements will aid in managing expenses. We will explore expansion and storage opportunities to increase utilization levels. Kinder Morgan Texas Pipeline L.P. intends to grow its transportation and storage businesses by identifying and serving significant new customers with demand for capacity on its intrastate pipeline system. Trailblazer is currently pursuing an expansion of its system supported by commitments secured in August 2000. Red Cedar Gathering Company, a partnership with the Southern Ute Indian Tribe, is pursuing additional gathering and processing opportunities on tribal lands. CO2 Pipelines. KMCO2's Permian Basin strategy is to offer customers "one-stop shopping" for carbon dioxide supply, transportation and technical support service. Outside the Permian Basin, we intend to compete aggressively for new supply and transportation projects. Our management believes these projects will arise as other United States oil producing basins mature and make the transition from primary production to enhanced recovery methods. Bulk Terminals. We are dedicated to growing our bulk terminals business through selective acquisitions, expansions, and development of new terminals. The bulk terminals industry in the United States is highly fragmented, leading to opportunities for us to make selective, accretive acquisitions. We will make investments to expand and improve existing facilities, particularly those facilities that handle low-sulfur western coal. Additionally, we plan to design, construct and operate new facilities for current and prospective customers. Our management believes we can use newly acquired or developed facilities to leverage our operational expertise and customer relationships. RECENT DEVELOPMENTS During 2000, our assets increased 43% and our net income increased 53% from 1999 levels. In addition, distributions per unit increased 31% from $0.725 for the fourth quarter of 1999 to $0.95 for the fourth quarter of 2000. The following is a brief listing of activity since the end of the third quarter of 2000. Additional information regarding these items is contained in the rest of this report. o On October 25, 2000, we acquired Kinder Morgan Transmix Company, LLC, formerly known as Buckeye Refining Company, LLC, for approximately $37 million plus net working capital. The acquisition included two transmix processing plants located in Indianola, Pennsylvania and Wood River, Illinois and other transmix assets. The two facilities are projected to process over 4.3 million barrels of transmix in 2001. 5 6 o On October 25, 2000, we entered into a new $600 million 364-day bank revolving facility that replaced and expanded our then existing $300 million facility and contains substantially the same covenants. In August 2000, we refinanced a fully drawn $175 million revolving credit facility at our subsidiary, SFPP, L.P., with an intercompany obligation to us. o On November 8, 2000, we closed on a private placement of $250 million of 10-year notes bearing a coupon of 7.5%. On February 27, 2001, we announced an offer to exchange these notes for substantially identical notes that are registered under the Securities Act of 1933. The exchange offer expires on March 27, 2001, unless extended by us at our sole discretion. o On November 30, 2000, we announced that we had signed a definitive agreement with GATX Corporation to purchase its United States pipeline and terminal businesses for approximately $1.15 billion, consisting of cash, assumed debt and other obligations. Primary assets included in the transaction are the CALNEV Pipe Line Company and the Central Florida Pipeline Company, along with 12 terminals that store refined petroleum products and chemicals. CALNEV is a 550 mile refined petroleum products pipeline system originating in Colton, California and extending to the Las Vegas, Nevada market. The Central Florida pipeline is a 195 mile refined petroleum products pipeline system consisting of a 16-inch gasoline pipeline and a 10-inch jet fuel and diesel pipeline, transporting product from Tampa to the Orlando, Florida market. The 12 terminals we are acquiring from GATX have a storage capacity of 35.6 million barrels, and the largest of these terminals are located in Houston, New York, Los Angeles and Chicago, with a total capacity of approximately 31.2 million barrels. The other terminals are located in Philadelphia, Portland, Oregon, San Francisco and Seattle. In addition, we are acquiring six other terminals from GATX with a capacity of 3.6 million barrels that are part of the CALNEV and Central Florida pipeline systems. On March 1, 2001, we announced that all of the assets in the transaction have closed, except for CALNEV, which closed on March 30, 2001. o On December 1, 2000, we purchased Delta Terminal Services, Inc. for approximately $114 million in cash. The acquisition included two liquid bulk storage terminals in New Orleans, Louisiana and Cincinnati, Ohio. The facilities provide services to producers of petroleum, chemicals and other products. The New Orleans terminal has a storage capacity of 2.8 million barrels. It is located at the 98.5 mile point on the Mississippi River close to the Harvey Canal and the Greater New Orleans Bridge. The terminal serves the New Orleans/Baton Rouge corridor and is situated on approximately 100 acres of land. The Cincinnati terminal has a storage capacity of 500,000 barrels. It is located at the 465.7 mile point on the Ohio River and is situated on approximately 60 acres of land. o On December 21, 2000, we reached agreement with the other owner of Plantation Pipe Line Company to become the operator of Plantation, a 3,100-mile refined petroleum products pipeline system throughout the southeastern United States. o On December 21, 2000, we completed a transaction whereby KMI contributed approximately $300 million of its assets to us. As consideration for these assets, we paid KMI approximately 50% of the fair value of the assets in cash and the remaining 50% of the fair value of the assets in units. The largest asset contributed was Kinder Morgan Texas Pipeline L.P., a 2,700 mile natural gas pipeline system that extends from south Texas to Houston along the Texas gulf coast. Other assets contributed included the Casper and Douglas Natural Gas Gathering and Processing Systems, KMI's 50% interest in Coyote Gas Treating, LLC and KMI's 25% interest in Thunder Creek Gas Services, LLC. o On December 28, 2000, we completed the purchase of a 32.5% interest in the Cochin Pipeline System from NOVA Chemicals Corporation. The effective date of the acquisition was November 3, 2000. The Cochin pipeline consists of approximately 1,900 miles of 12-inch pipeline transversing Canada and the United States from Fort Saskatchewan, Alberta to Sarnia, Ontario. It transports high vapor pressure ethane, ethylene, propane, butane and natural gas liquids to the midwestern United States and eastern Canadian petrochemical and fuel markets, and is a joint venture of our subsidiary and subsidiaries of BP Amoco, Conoco, Shell and NOVA Chemicals. o On December 28, 2000, we 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 was formed on January 1, 2001 and is owned 85% by Marathon Oil Company and 15% by KMCO2. The joint venture consists of a nearly 13% interest in the SACROC Unit and a 49.9% interest in the Yates oil field, the largest single interest in that Unit. In connection with the formation of the joint venture, we entered into a 10 year contract to supply Marathon with an aggregate of 30 billion cubic feet of carbon dioxide expected to be used to enhance oil recovery in the area. 6 7 o On December 31, 2000, we increased our ownership in the Colton, California transmix processing facility by purchasing Duke Energy Merchants' 50% interest in the facility. SFPP, L.P., our subsidiary that owns our Pacific operations, owns the remaining 50% ownership interest. The facility's transmix processing agreements with third parties were transferred to Duke, and in turn, we entered into a ten year fee-based processing agreement to process transmix for Duke at the facility. Duke will market all of the transmix we process for it at the Colton facility. Kinder Morgan Management, LLC, a wholly-owned subsidiary of our general partner, has filed a registration statement to issue and sell shares. Upon completion of that proposed offering, Kinder Morgan Management, LLC would become a partner in us and manage and control our business and affairs. The net proceeds from that offering would be used to buy i-units from us. The i-units would be a new class of our limited partner interests and would be issued only to Kinder Morgan Management, LLC. We would use the cash received from the sale of i-units to reduce short-term debt incurred to finance the GATX acquisition. No assurance can be given that the proposed issuance of shares and related financing will occur, or that they will not be modified from the foregoing description if ultimately completed. PRODUCT PIPELINES PACIFIC OPERATIONS Our Pacific operations include interstate common carrier pipelines regulated by the Federal Energy Regulatory Commission, intrastate pipelines in California regulated by the California Public Utilities Commission and non rate-regulated terminal operations. Our Pacific operations are split into a South Region and a North Region. Combined, the two regions consist of five pipeline segments that serve six western states with approximately 3,300 miles of refined petroleum products pipeline and related terminal facilities. Refined petroleum products and related uses are:
Product Use - ------- --- Gasoline Transportation Diesel fuel Transportation (auto, rail, marine), farm, industrial and commercial Jet fuel Commercial and military air transportation
Our Pacific operations transport over one million barrels per day of refined petroleum products, providing pipeline service to approximately 44 customer-owned terminals, three commercial airports and 12 military bases. For 2000, the three main product types transported were gasoline (61%), diesel fuel (21%) and jet fuel (18%). Our Pacific operations also include 13 truck-loading terminals. Our Pacific operations provide refined petroleum products to some of the fastest growing populations in the United States, including southern California; Las Vegas, Nevada; and the Tucson-Phoenix, Arizona region. Pipeline transportation of gasoline and jet fuel has a direct correlation with demographic patterns. We believe that the positive demographics associated with the markets served by our Pacific operations will continue in the foreseeable future. South Region. Our Pacific operations' South Region consists of three pipeline segments: the West Line, East Line and San Diego Line. The West Line consists of approximately 570 miles of primary pipeline and currently transports products for approximately 50 shippers from seven refineries and three pipeline terminals in the Los Angeles Basin to Phoenix and Tucson, Arizona and various intermediate commercial and military delivery points. Also, a significant portion of West Line volumes are transported to Colton, California for local distribution and for delivery to the CALNEV pipeline, which carries refined petroleum products to Las Vegas, Nevada and intermediate points. The West Line serves our terminals located in Colton and Imperial, California as well as in Tucson and Phoenix. In the fall of 2000, we completed a $9 million expansion of the West Line from Colton to Phoenix. 7 8 The East Line is comprised of two parallel lines originating in El Paso, Texas and continuing approximately 300 miles west to our Tucson terminal and one line continuing northwest approximately 130 miles from Tucson to Phoenix. All products received by the East Line at El Paso come from a refinery in El Paso or are delivered through connections with non-affiliated pipelines from refineries in west Texas and Artesia, New Mexico. The East Line serves our terminals located in Tucson and Phoenix. The San Diego Line is a 135-mile pipeline serving major population areas in Orange County (immediately south of Los Angeles) and San Diego. The same refineries and terminals that supply the West Line also supply the San Diego Line. On June 1, 2000, we completed an expansion of the San Diego Line. The expansion involved construction of 23 miles of 16-inch diameter pipe, and other appurtenant facilities, across the Camp Pendleton Marine Base just north of Oceanside, California. The expansion project cost approximately $18 million and coupled with the completion of supplementary pumping stations in the summer of 2000, the capacity of the San Diego Line has increased from 116,000 barrels per day to 144,000 barrels per day, an increase of almost 25%. The new facilities will increase the Pacific operations' capability to transport gasoline, diesel and jet fuel to customers in the rapidly growing Orange County and San Diego, California markets. North Region. Our Pacific operations' North Region consists of two pipeline segments: the North Line and Oregon Line. The North Line consists of approximately 1,075 miles of pipeline in six segments originating in Richmond, Concord and Bakersfield, California. This line serves our terminals located in Brisbane, Bradshaw, Chico, Fresno and San Jose, California, and Sparks, Nevada. The products delivered through the North Line come from refineries in the San Francisco Bay and Bakersfield areas. The North Line also receives product transported from various pipeline and marine terminals that deliver products from foreign and domestic ports. A refinery located in Bakersfield supplies substantially all of the products shipped through the Bakersfield-Fresno segment of the North Line. The Oregon Line is a 114-mile pipeline serving approximately ten shippers. Our Oregon Line receives products from marine terminals in Portland, Oregon and from Olympic Pipeline. Olympic Pipeline is a non-affiliated carrier that transports products from the Puget Sound, Washington area to Portland. From its origination point in Portland, the Oregon Line extends south and serves our terminal located in Eugene, Oregon. Truck Loading Terminals. Our Pacific operations include 13 truck-loading terminals with an aggregate usable tankage capacity of approximately 8.2 million barrels. Terminals are located at destination points on each of our Pacific operations' pipelines as well as at certain intermediate points along each pipeline. The simultaneous truck loading capacity of each terminal ranges from 2 to 12 trucks. We provide the following services at these terminals: o short-term product storage; o truck loading; o vapor recovery; o deposit control additive injection; o dye injection; o oxygenate blending; and o quality control. The capacity of terminaling facilities varies throughout our Pacific operations and we do not own terminaling facilities at all pipeline delivery locations. At certain locations, we make product deliveries to facilities owned by shippers or independent terminal operators. At our terminals, we provide truck loading and other terminal services. We charge a separate fee (in addition to pipeline tariffs) for these additional non rate-regulated services. Markets. Currently our Pacific operations serve in excess of 100 shippers in the refined products market, with the largest customers consisting of: o major petroleum companies; o independent refineries; o the United States military; and 8 9 o independent marketers and distributors of products. A substantial portion of the product volume transported is gasoline. Demand for gasoline depends on such factors as prevailing economic conditions and demographic changes in the markets served. We expect the majority of our Pacific operations' markets to maintain growth rates that exceed the national average for the foreseeable future. Currently, the California gasoline market is 945,000 barrels per day. The Arizona gasoline market is served primarily by us at a market demand of 135,000 barrels per day. Nevada's gasoline market is approximately 55,000 barrels per day and Oregon's is approximately 95,000 barrels per day. The distillate (diesel and jet fuel) market is approximately 490,000 barrels per day in California, 75,000 barrels per day in Arizona, 50,000 barrels per day in Nevada and 62,000 barrels per day in Oregon. We transport over 1 million barrels of petroleum products per day in these states. The volume of products transported is directly affected by the level of end-user demand for such products in the geographic regions served. Certain product volumes can experience seasonal variations and, consequently, overall volumes may be lower during the first and fourth quarters of each year. Supply. The majority of refined products supplied to our Pacific operations come from the major refining centers around Los Angeles, San Francisco and Puget Sound, as well as waterborne terminals located near these refining centers. Transmix is primarily supplied by petroleum pipeline and terminal operations, including our own pipelines in California and other western states. Competition. The most significant competitors of our Pacific operations' pipeline system are proprietary pipelines owned and operated by major oil companies in the area where our pipeline system delivers products as well as refineries with related trucking arrangements within the our market areas. We believe that high capital costs, tariff regulation and environmental permitting considerations make it unlikely that a competing pipeline system comparable in size and scope will be built in the foreseeable future. However, the possibility of pipelines being constructed to serve specific markets is a continuing competitive factor. Trucks may competitively deliver products in certain markets, particularly to shorter-haul destinations in the Los Angeles and San Francisco Bay areas. Longhorn Partners Pipeline is a proposed joint venture project that would begin transporting refined products from refineries on the Gulf Coast to El Paso and other destinations in Texas. Increased product supply in the El Paso area could result in some shift of volumes transported into Arizona from our West Line to our East Line. While increased movements into the Arizona market from El Paso would displace higher tariff volumes supplied from Los Angeles on our West Line, such shift of supply sourcing has not had, and is not expected to have, a material effect on operating results. NORTH SYSTEM Our North System is an approximately 1,600-mile interstate common carrier pipeline for natural gas liquids and refined petroleum products. Natural gas liquids are typically extracted from natural gas in liquid form under low temperature and high pressure conditions. Natural gas liquid products and related uses are as follows:
Product Use - ------- --- Propane Residential heating, industrial and agricultural uses, petrochemical feedstock Isobutane Further processing Natural gasoline Further processing or blending into gasoline motor fuel Ethane Feedstock for petrochemical plants Normal butane Feedstock for petrochemical plants or blending into gasoline motor fuel
Our North System extends from south central Kansas to the Chicago area. South central Kansas is a major hub for producing, gathering, storing, fractionating and transporting natural gas liquids. Our North System's primary pipeline is comprised of approximately 1,400 miles of 8-inch and 10-inch pipelines and includes: 9 10 o two parallel pipelines (except for a 50-mile segment in Nebraska and Iowa), which originate at Bushton, Kansas and continue to a major storage and terminal area in Des Moines, Iowa; o a third pipeline, which extends from Bushton to the Kansas City, Missouri area; and o a fourth pipeline that transports product to the Chicago area from Des Moines. Through interconnections with other major liquids pipelines, our North System's pipeline system connects Mid-Continent producing areas to markets in the Midwest and eastern United States. We also have defined sole carrier rights to use capacity on an extensive pipeline system owned by The Williams Company that interconnects with our North System. This capacity lease agreement requires us to pay $2.0 million per year, is in place until February 2013 and contains a five-year renewal option. In addition to our capacity lease agreement with Williams, we also have a reversal agreement with Williams to help provide for the transport of summer-time surplus butanes from Chicago area refineries to storage facilities at Bushton. We have an annual minimum joint tariff commitment of $0.6 million to Williams for this agreement. In 1999, we entered into a long-term agreement with Aux Sable Liquid Products to transport a significant volume of natural gas liquids in and around the Chicago area for Aux Sable. We have made modifications to our pipeline system and our Morris and Lemont, Illinois facilities in order to accommodate the transportation of natural gas liquids for Aux Sable. The shipments are expected to begin in late first quarter or early second quarter of 2001. In 2000, we entered into a propane terminaling agreement with Aux Sable and began service in late fourth quarter. The following table sets forth volumes, in thousands of barrels, of natural gas liquids transported on our North System (excluding Heartland Pipeline Company) for delivery to the various markets for the periods indicated:
YEAR ENDED DECEMBER 31, 2000 1999 1998 1997 1996 ------ ------ ------ ------ ------ Petrochemicals 1,276 1,059 1,040 1,200 684 Refineries and line reversal 12,020 10,517 10,489 10,600 9,536 Fuels 7,221 6,172 6,150 7,976 10,500 Other(1) 8,154 8,379 5,532 7,399 8,126 ------ ------ ------ ------ ------ Total 28,671 26,127 23,211 27,175 28,846 ====== ====== ====== ====== ======
(1) Natural gas liquid gathering systems and Chicago originations other than long-haul volumes of refinery butanes. Our North System has approximately 8.3 million barrels of storage capacity, which includes caverns, steel tanks, pipeline line-fill and leased storage capacity. This storage capacity provides operating efficiencies and flexibility in meeting seasonal demand of shippers as well as propane storage for our truck loading terminals. Truck Loading Terminals. Our North System has seven propane truck loading terminals and one multi-product complex at Morris, Illinois, in the Chicago area. Propane, normal butane, isobutane and natural gasoline can be loaded at our Morris terminal. Markets. Our North System currently serves approximately 50 shippers in the upper Midwest market, including both users and wholesale marketers of natural gas liquids. These shippers include all four major refineries in the Chicago area. Wholesale marketers of natural gas liquids primarily make direct large volume sales to major end-users, such as propane marketers, refineries, petrochemical plants and industrial concerns. Market demand for natural gas liquids varies in respect to the different end uses to which natural gas liquid products may be applied. Demand for transportation services is influenced not only by demand for natural gas liquids but also by the available supply of natural gas liquids. Supply. Natural gas liquids extracted or fractionated at the Bushton gas processing plant have historically accounted for a significant portion (approximately 40-50%) of the natural gas liquids transported through our North System. Other sources of natural gas liquids transported in our North System include large oil companies, marketers, end-users and natural gas processors that use interconnecting pipelines to transport hydrocarbons. KMI has transferred to ONEOK, Inc. the Bushton plant along with other assets previously owned by KMI. ONEOK has assumed contracts with us to continue shipping natural gas liquids through our North System in volumes substantially equal to those shipped through our North System when KMI owned the Bushton plant. 10 11 Competition. Our North System competes with other liquids pipelines and to a lesser extent with rail carriers. In most cases, established pipelines are the lowest cost alternative for the transportation of natural gas liquids and refined petroleum products. Consequently, pipelines owned and operated by others represent our primary competition. In the Chicago area, our North System competes with other natural gas liquid pipelines that deliver into the area and with rail car deliveries primarily from Canada. Other Midwest pipelines and area refineries compete with our North System for propane terminal deliveries. Our North System also competes indirectly with pipelines that deliver product to markets that our North System does not serve, such as the Gulf Coast market area. PLANTATION PIPE LINE COMPANY We own 51% of Plantation Pipe Line Company, which owns a 3,100 mile pipeline system throughout the southeastern Unites States. On December 21, 2000, we took over the day-to-day operations of Plantation. Plantation serves as a common carrier of refined petroleum products to various metropolitan areas, including Birmingham, Alabama; Atlanta, Georgia; Charlotte, North Carolina; and the Washington, D.C. area. We believe favorable demographics in the southeastern United States will serve as a platform for increased utilization and expansion of Plantation's pipeline system. Markets. Plantation ships products for approximately 50 companies to terminals throughout the southeastern United States. Plantation's principal customers are Gulf Coast refining and marketing companies, fuel wholesalers and the United States Department of Defense. In addition, Plantation services the Atlanta, Georgia; Charlotte, North Carolina; and Washington, D.C. airports (Ronald Reagan/National and Dulles), at which it delivers jet fuel to major airlines. Supply. Products shipped on Plantation originate at various Gulf Coast refineries from which major integrated oil companies and independent refineries and wholesalers ship refined petroleum products. Plantation can transport over 600,000 barrels of refined petroleum products per day. In December 1999, Plantation announced an expansion of its mainline system. The $40 million development will increase the system's capacity by 70,000 barrels per day. The first phase of the expansion was completed in the fourth quarter of 2000 and the entire expansion project should be completed in the second quarter of 2001. Competition. Plantation competes primarily with the Colonial Pipeline, which also runs from Gulf Coast refineries throughout the southeastern United States, extending into the northeastern states. COCHIN PIPELINE SYSTEM We own 32.5% of the Cochin Pipeline System, a 1,938 mile 12-inch multiproduct pipeline operating between Fort Saskatchewan, Alberta and Sarnia, Ontario. The Cochin Pipeline System and related storage and processing facilities consist of two components: o in Canada, all facilities are conducted under the name of Cochin Pipe Lines, Ltd.; and o in the United States, all facilities are operated under the name of Dome Pipeline Corporation. Markets. Formed in the late 1970's as a joint venture and an integral part of the Alberta petrochemical project, the pipeline transverses three provinces in Canada and seven states in the United States transporting high vapor pressure ethane, ethylene, propane, butane and natural gas liquids to the Midwestern United States and eastern Canadian petrochemical and fuel markets. The system operates as a National Energy Board (Canada) and Federal Energy Regulatory Commission (United States) regulated common carrier; shipping products on behalf of its owners as well as other third parties. Supply. The pipeline operates on a batched basis and has an estimated system capacity of approximately 112,000 barrels per day. Its peak capacity is approximately 124,000 barrels per day. It includes 31 pump stations spaced at 60 mile intervals and five United States propane terminals. Associated underground storage is available at Fort Saskatchewan, Alberta and Windsor, Ontario. The system is connected to the Williams Pipeline System in Minnesota and in Iowa, and connects with our North System at 11 12 Clinton, Iowa. The Cochin Pipeline System has the ability to access the Canadian Eastern Delivery System via the Windsor Storage Facility Joint Venture at Windsor, Ontario. Injection into the system can occur from: o BP Amoco, Chevron or Dow fractionation facilities at Fort Saskatchewan, Alberta; o TransCanada Midstream storage at five points within the provinces of Canada; or o the Williams Mapco West Junction, in Minnesota. CYPRESS PIPELINE Our Cypress Pipeline is an interstate common carrier pipeline system originating at storage facilities in Mont Belvieu, Texas and extending 104 miles east to the Lake Charles, Louisiana area. Mont Belvieu, located approximately 20 miles east of Houston, is the largest hub for natural gas liquids gathering, transportation, fractionation and storage in the United States. Markets. The pipeline was built to service Westlake, a major petrochemical producer in the Lake Charles, Louisiana area under a 20-year ship-or-pay agreement that expires in 2011. The contract requires a minimum volume of 30,000 barrels per day and in 1997, the producer agreed to ship at least an additional 13,700 barrels per day for five years. Also in 1997, we expanded the Cypress Pipeline's capacity by 25,000 barrels per day to 57,000 barrels per day. Our management continues to pursue projects that could increase throughput on our Cypress Pipeline. Supply. Our Cypress Pipeline originates in Mont Belvieu where it is able to receive ethane and ethane/propane mix from local storage facilities. Mont Belvieu has facilities to fractionate natural gas liquids received from several pipelines into ethane and other components. Additionally, pipeline systems that transport specification natural gas liquids from major producing areas in Texas, New Mexico, Louisiana, Oklahoma and the Mid-Continent Region supply ethane and ethane/propane mix to Mont Belvieu. TRANSMIX OPERATIONS Our transmix operations consist of: o transmix processing facilities located in Richmond, Virginia and Dorsey Junction, Maryland acquired in September 1999 from Primary Corporation; o transmix processing facilities located in Indianola, Pennsylvania and Wood River, Illinois acquired in October 2000 as part of our acquisition of Kinder Morgan Transmix Company, LLC, formerly known as Buckeye Refining Company, LLC; and o the Colton Processing Facility located in Colton, California. Transmix occurs when dissimilar refined petroleum products are co-mingled in the pipeline transportation process. Different products are pushed through the pipelines abutting each other, and the area where different products mix is called transmix. Employing atmospheric distillation units, we process pipeline transmix generated in the eastern United States to produce pipeline quality gasoline and light distillate products. The processing is provided on a "for fee" basis or on a "purchase, process and sell" basis. The processed material is returned to the generator of the transmix or is sold into the local market depending on the type of agreement in place with the generator. Our Richmond operating facility resides on an 11-acre site located near Interstate 95 and adjacent to Virginia's James River. The facility is comprised of a dock/pipeline, a 170,000-barrel tank farm, a processing plant, lab and truck rack. The facility is composed of four distillation units that operate 24 hours a day, 7 days a week providing a production capacity of approximately 8,000 barrels per day. The facility is able to segregate feedstock for specialty fuel production. The processing facility employs state-of-the-art computer based process control equipment and is supported by comprehensive in-house quality control laboratory capabilities. The facility is served by both Colonial and Plantation pipelines, by deep-water barge (25 feet draft) and by transport truck and rail. We also own an additional 3.6-acre bulk products terminal with a capacity of 55,000 barrels located nearby in Richmond. Our Dorsey Junction operating facility is located within the Colonial Pipeline Dorsey Junction terminal facility. The 5,000-plus barrel per day processing unit began operations in February 1998. It operates 24 hours a day, 7 days a week providing dedicated transmix separation service for Colonial on a "for fee" basis. 12 13 Our Indianola operating facility is located on a 30-acre site near Pittsburgh and is accessible by truck, barge and pipeline, primarily processing transmix from Buckeye, Colonial, Sun and Teppco pipelines. It has capacity to process 12,000 barrels of transmix per day and operates 24 hours per day, 7 days a week. The facility is comprised of a 500,000-barrel tank farm, a quality control laboratory, a truck loading rack and a processing unit. The facility can ship via the Buckeye pipeline as well as by truck. Our Wood River operating facility was constructed in 1993 on property owned by Conoco and is accessible by truck, barge and pipeline, primarily processing transmix from Explorer and Conoco pipelines. It has capacity to process 5,000 barrels of transmix per day. Located on approximately three acres leased from Conoco, the facility consists of one processing unit. Supporting terminal capability is provided through leased tanks in adjacent terminals. Our Colton operating facility, completed in the spring of 1998, and located adjacent to our products terminal in Colton, California, processes proprietary transmix on a fee basis for a subsidiary of Duke Energy. The facility produces refined petroleum products, which are injected into our Pacific operations' pipelines for delivery to markets in Southern California and Arizona. The facility processed approximately 4,100 barrels per day during 2000, which is near the capacity of the facility. Markets. The Gulf and East Coast petroleum distribution system, particularly the Mid-Atlantic region, provides the target market for our East Coast transmix processing operations. The Mid-Continent area and the New York Harbor are the target markets for our Pennsylvania and Illinois assets. Our West Coast transmix processing operations support the markets serviced by our Pacific operations. We are working to expand our Mid-Continent and West Coast markets. Supply. Transmix generated by Colonial, Plantation, Sun, Teppco, Explorer, and our Pacific operations provide the vast majority of our supply. These suppliers are committed by long-term contracts. Individual shippers and terminal operators provide additional supply. Competition. Our transmix operations compete mainly with Placid Refining in the Gulf coast area. Tosco Refining is a major competitor in the New York harbor area. There are various processors in the Mid-Continent area, mainly Phillips and Williams Brothers, who will compete with our expansion efforts into that market. A number of smaller organizations operate in the West and Southwest. These operations compete for supply, which we envision as the basis for growth in the West and Southwest. Our Colton Processing Facility competes with major oil company refineries and other transmix processing facilities in California and Arizona. HEARTLAND PIPELINE COMPANY The Heartland pipeline was completed in the fall of 1990 and is owned by Heartland Pipeline Company. We and Conoco each own 50% of Heartland. We operate the pipeline and Conoco operates Heartland's Des Moines terminal and serves as the managing partner of Heartland. In 2000, Heartland leased Conoco 100% of the Heartland terminal capacity at Des Moines, Iowa for $1.0 million. Markets. Heartland provides transportation of refined petroleum products from refineries in the Kansas and Oklahoma area to a BP Amoco terminal in Council Bluffs, Iowa, a Conoco terminal in Lincoln, Nebraska and Heartland's Des Moines terminal. The demand for, and supply of, refined petroleum products in the geographic regions served directly affect the volume of refined petroleum products transported by Heartland. Supply. Refined petroleum products transported by Heartland on our North System are supplied primarily from the National Cooperative Refinery Association crude oil refinery in McPherson, Kansas and the Conoco crude oil refinery in Ponca City, Oklahoma. Competition. Heartland competes with other refined product carriers in the geographic market served. Heartland's principal competitor is Williams Pipeline Company. 13 14 PAINTER GAS PROCESSING PLANT Our Painter Plant is located near Evanston, Wyoming and consists of: o a natural gas processing plant; o a nitrogen rejection unit; o a fractionator; o a natural gas liquids terminal; and o interconnecting pipelines with truck and rail loading facilities. The fractionation facility has a capacity of approximately 6,000 barrels per day, depending on the feedstock composition. We lease the Painter Plant to Amoco Oil Company, a unit of BP Amoco, which operates the fractionator and the associated Millis terminal and storage facilities for its own account. BP Amoco also owns and operates the nearby BP Amoco Painter Complex gas plant. NATURAL GAS PIPELINES Our Natural Gas Pipelines consist of natural gas gathering, transportation and storage for both interstate and intrastate pipelines. Within this segment, we operate over 10,000 miles of natural gas pipelines and associated storage and supply lines that are strategically located at the center of the North American pipeline grid. Our transportation network provides access to the major gas supply areas in the western United States and the Midwest, as well as major consumer markets. KINDER MORGAN INTERSTATE GAS TRANSMISSION LLC. Through Kinder Morgan Interstate Gas Transmission LLC, we own approximately 6,500 miles of transmission lines in Wyoming, Colorado, Kansas, Missouri and Nebraska. KMIGT provides transportation and storage services to KMI affiliates, third-party natural gas distribution utilities and other shippers. Pursuant to transportation agreements and FERC tariff provisions, KMIGT offers its customers firm and interruptible transportation and storage, including no-notice services. Under KMIGT's tariffs, firm transportation and storage customers pay reservation charges each month plus a commodity charge based on actual volumes transported or stored. Interruptible transportation and storage customers pay a commodity charge based upon actual volumes transported or stored. Reservation and commodity charges are both based upon geographical location (KMIGT does not have seasonal rates) and distance of the transportation service provided. Under no-notice service, customers pay a fee for the right to use a combination of firm storage and firm transportation to make deliveries of natural gas up to a specified volume. No-notice customers are able to meet their peak day requirements without making specific nominations. The system includes 41 transmission, field and storage compressor stations having an aggregate of approximately 158,981 installed horsepower. The pipeline system provides storage services to its customers from its Huntsman Storage Field in Cheyenne County, Nebraska. The facility has 39.4 billion cubic feet of total storage capacity, 7.9 billion cubic feet of working gas capacity and up to 101 million cubic feet per day of peak withdrawal capacity. Markets. Markets served by KMIGT consist of a stable customer base with expansion opportunities due to the system's access to the growing Rocky Mountain supply sources. Markets served by KMIGT are comprised mainly of local distribution companies and interconnecting interstate pipelines in the mid-continent area. Markets for the local distribution companies can include residential, commercial, industrial and agricultural customers. KMIGT also delivers into interconnecting interstate pipelines in the mid-continent area, which can in turn deliver gas into multiple markets throughout the United States. Due to the demand for natural gas to run irrigation systems in the summer, summer loads often equal the levels for the winter heating season. Contracts. On a volumetric basis, approximately 23% of KMIGT's firm contracts expire within one year, 10% expire within one to five years and 67% expire in more than five years. Out of the 23% of the firm volumes that expire within one year, 89% of those volumes are with affiliated entities. Affiliated entities are responsible for approximately 24% of the total firm transportation and storage capacity under contract on KMIGT's system. Over 90% of the system's firm transport capacity is currently subscribed. In February 2000, KMIGT preserved its current 14 15 cost of service for 5 years as part of the settlement with its customers and the Federal Energy Regulatory Commission on its filed rate case. Competition. KMIGT competes with other interstate and intrastate gas pipelines transporting gas from the supply sources in the Rocky Mountain and Hugoton Basins to mid-continent pipelines and market centers. KINDER MORGAN TEXAS PIPELINE L.P. KMTP, acquired in conjunction with the December 31, 2000 transfer of assets from KMI, operates an intrastate natural gas pipeline system, which is leased from Occidental Petroleum Corporation under a 30 year lease that commenced on December 31, 1996. The pipeline system is principally located in the Texas Gulf Coast area. The system includes approximately 2,700 miles of pipelines, supply and gathering lines, sales laterals and related facilities. KMTP transports natural gas from producing fields in South Texas, the Gulf Coast and the Gulf of Mexico to markets in southeastern Texas. In addition, KMTP has interconnections with Natural Gas Pipeline Company of America, a subsidiary of KMI, and 22 other intrastate and interstate pipelines. Markets/Contracts. KMTP acts as a seller of natural gas as well as a transporter. Principal customers of KMTP include the electric and natural gas utilities that serve the Houston area, and industrial customers located along the Houston Ship Channel and in the Beaumont/Port Arthur, Texas area. This market is one of the largest and most competitive natural gas markets in the United States. Large industrial end users of natural gas have, on average, three pipelines connected to their plants. Large local distribution companies and electric utilities have multiple pipeline connections. Multiple pipeline connections provide the consumer of natural gas the opportunity to purchase natural gas directly from a number of pipelines and/or from third parties that may hold capacity on the various pipelines. For this market, the greatest demand for natural gas deliveries for heating load occurs in the winter months, while electric generation peak demand occurs in the summer months. In 2000, KMTP delivered an average of 1.8 billion cubic feet per day of natural gas to this area, of which 62% of the deliveries were for sales contracts and 38% were for transportation contracts. During 2000, approximately 58% of KMTP's gross margin was attributable to sales and transportation services provided to Reliant Energy and its affiliates. On March 17, 2000, KMTP renewed its natural gas sales and transportation contract with Reliant Energy HL&P through March 1, 2004. Additionally, KMTP has entered into a new transportation services agreement with Reliant Energy HL&P beginning in 2002 and extending through 2012. Reliant HL&P provides electric service to approximately 1.6 million customers in the Houston area. The contract terms for Reliant Energy utilities will expire between 2002 and 2004. Also, on October 21, 2000, KMTP entered into a 10-year firm natural gas transportation and storage agreement with Calpine beginning July 1, 2001. Other industrial end users' contracts vary in length from month-to-month to five or more years. KMTP has also developed a salt dome storage facility located near Markham, Texas with a subsidiary of NISource Industries, Inc. The facility has two salt dome caverns and approximately 8.3 billion cubic feet of total storage capacity, over 5.7 billion cubic feet of working gas capacity and up to 500 million cubic feet per day of peak deliverability. The storage facility is leased by a partnership in which KMTP and a subsidiary of NISource are partners. KMTP has executed a 20 year sublease with the partnership under which it has rights to 50% of the facility's working gas capacity, 85% of its withdrawal capacity and approximately 70% of its injection capacity. KMTP also leases a salt dome cavern from Dow Hydrocarbon & Resources, Inc. in Brazoria County, Texas, referred to as the Stratton Ridge Facility. The Stratton Ridge Facility has a total capacity of 6.5 billion cubic feet, working gas capacity of 3.6 billion cubic feet and a peak day deliverability of up to 150 million cubic feet per day. Competition. KMPT competes with marketing companies, interstate and intrastate pipelines for sales and transport customers in the Houston, Beaumont and Port Arthur areas, and for acquiring gas supply in South Texas, the Gulf Coast of Texas and the Gulf of Mexico. TRAILBLAZER PIPELINE COMPANY We own 66 2/3% of Trailblazer Pipeline Company, an Illinois general partnership. Enron Trailblazer Pipeline Company, a subsidiary of Enron Corporation, owns the remaining 33 1/3%. A committee consisting of management representatives for each of the partners manages Trailblazer. NGPL, a subsidiary of KMI, manages, maintains and 15 16 operates Trailblazer and provides the personnel to operate Trailblazer for which NGPL is reimbursed at cost. Trailblazer is a "natural gas company" within the meaning of the Natural Gas Act. Trailblazer's principal business is to transport and redeliver natural gas to others in interstate commerce, and it does business in the states of Wyoming, Colorado, Nebraska and Illinois. Trailblazer has been a fully "open access" pipeline under Order Nos. 436/500 since June 1, 1991. Trailblazer owns and operates a 436 mile 36-inch diameter pipeline system which originates at an interconnection with Wyoming Interstate Company Ltd.'s pipeline system near Rockport, Weld County, Colorado and runs through southeastern Wyoming to a terminus near Beatrice, Gage County, Nebraska where Trailblazer's pipeline system interconnects with NGPL's and Northern Natural Gas Company's pipeline systems. Trailblazer's pipeline is the fourth segment of a 791 mile pipeline system known as the Trailblazer Pipeline System, which originates in Uinta County, Wyoming with Canyon Creek Compression Company, a 22,000 brake horsepower compressor station located at the tailgate of BP Amoco Production Company's processing plant in the Whitney Canyon Area in Wyoming (Canyon Creek's facilities are the first segment). Canyon Creek receives gas from the BP Amoco processing plant and provides transportation and compression of gas for delivery to Overthrust Pipeline Company's 88 mile 36-inch diameter pipeline system at an interconnection in Uinta County, Wyoming (Overthrust's system is the second segment). Overthrust delivers gas to Wyoming Interstate's 269 mile 36-inch diameter pipeline system at an inter-connection (Kanda) in Sweetwater County, Wyoming (Wyoming Interstate's system is the third segment). Wyoming Interstate's pipeline delivers gas to Trailblazer's pipeline at an interconnection near Rockport in Weld County, Colorado. Markets. Significant growth in Rocky Mountain natural gas supplies has prompted a need for additional pipeline transportation service. In August 2000, Trailblazer announced an approximate $58.7 million expansion to its system, which will provide an additional capacity of 324,000 dekatherms per day. The expansion project would start in Rockport, Colorado, where Trailblazer's pipeline interconnects with pipelines owned by Colorado Interstate Gas Co., Wyoming Interstate Company, West Gas and KMIGT, and terminate in Gage County, Nebraska. With this project, Trailblazer will install two new compressor stations and add additional horsepower at an existing compressor station. Trailblazer filed its expansion plan with the FERC on January 10, 2001, and pending FERC approval, the project is scheduled for completion in the third quarter of 2002. Competition. While competing pipelines have been announced, which would move gas east out of the Rocky Mountains, the main competition that Trailblazer faces is that the gas supply in the Rocky Mountain area either stays in the area or is moved west and therefore not transported on Trailblazer's pipeline. CASPER AND DOUGLAS NATURAL GAS GATHERING AND PROCESSING SYSTEMS We own and operate our Casper and Douglas natural gas gathering and processing facilities. Douglas Gathering is comprised of approximately 1,500 miles of 4-inch to 16-inch diameter pipe that gathers approximately 58 million cubic feet per day of casinghead gas from 650 active receipt points. Douglas Gathering has an aggregate 24,495 horsepower of compression with central dehydration at each field booster compressor station. Gathered volumes are processed at our Douglas plant, located in Douglas, Wyoming. Residue gas is delivered into KMIGT and recovered liquids are injected in Phillips Petroleum's natural gas liquids pipeline for transport to Borger, Texas. Casper Gathering is comprised of approximately 60 miles of 4-inch to 8-inch diameter pipeline that transports approximately 20 million cubic feet per day of natural gas from eight active receipt points. Gathered volumes are delivered directly into KMIGT. Current gathering capacity is contingent upon available capacity on KMIGT and the Casper Plant's 50 to 80 million cubic feet per day processing capacity. Our Casper Plant, located in Casper, Wyoming, is a lean oil absorption facility with full fractionation and capacity to process 50 to 80 million cubic feet per day of natural gas depending on raw gas quality. As a result of utilizing a lean oil absorption process the facility does not recover ethane from the raw gas stream. The inlet composition of gas entering our Casper plant averages approximately 1.2 gallons per thousand cubic feet of propane and heavier natural gas liquids, reflecting the relatively lean gas gathered by Casper Gathering. Our Casper Plant recoveries averaged approximately 60% of propane, 89% of isobutene, 90% of normal butane, and 98% of natural gasoline and C6+. The facility is a straddle plant on KMIGT and utilizes 5,000 horsepower of compression. 16 17 Competition. There are a number of other natural gas gathering and processing alternatives for producers in the Powder River Basin. However, Casper and Douglas are the only two plants in the region that provide straddle processing of natural gas streams flowing into KMIGT. The other regional facilities include the Hilight (80 million cubic feet per day) and Kitty (17 million cubic feet per day) plants owned and operated by Western Gas Resources; the Sage Creek (50 million cubic feet per day) plant owned and operated by Devon; and Lost Creek Gathering which is a partnership between Burlington Resources and Northern Border Partners. RED CEDAR GATHERING COMPANY We own a 49% equity interest in the Red Cedar Gathering Company, a joint venture organized in August 1994. The Southern Ute Indian Tribe owns the remaining 51%. Red Cedar owns and operates natural gas gathering and treating facilities in La Plata County, Colorado, in the Ignacio Blanco Field of the San Juan Basin. The Ignacio Blanco Field is that portion of the San Juan Basin located in Colorado, most of which is located within the exterior boundaries of the Southern Ute Indian Reservation. Red Cedar gathers coal seam and conventional natural gas at wellheads and at several central delivery points, and treats gas for delivery to three major interstate gas pipeline systems and to an intrastate pipeline. Red Cedar's gas gathering system currently consists of over 450 miles of gathering pipeline connecting more than 600 producing wells, 17 field compressor stations and a carbon dioxide processing plant. A majority of the gas on the system moves through 8-inch to 20-inch diameter pipe. The capacity and throughput of the Red Cedar system as currently configured is approximately 600 million cubic feet per day of natural gas. COYOTE GAS TREATING, LLC We own a 50% equity interest in Coyote Gas Treating, LLC, a joint venture organized in December 1996. Coyote Gas Treating, LLC, known as Coyote Gulch, is a 250 million cubic feet per day natural gas treating facility located in La Plata County, Colorado. El Paso Field Services Company owns the remaining 50% interest. We took over the operations of Coyote Gulch on February 1, 1999. Prior to that time, El Paso was the operator of the plant. The inlet gas stream treated by Coyote Gulch contains an average carbon dioxide content of between 12% and 13%. The plant treats the gas down to a carbon dioxide concentration of 2% in order to meet interstate pipeline gas quality specifications. Coyote's residue gas is delivered into the TransColorado Pipeline for transport to the Blanco, New Mexico San Juan Basin Hub. THUNDER CREEK GAS SERVICES, LLC We own a 25% equity interest in Thunder Creek Gas Services, LLC, a joint venture organized in September 1998. Thunder Creek provides gathering, compression and treating services to a number of producers in the Powder River Basin. Throughput volumes include both coalseam and conventional plant residue gas. Devon Energy, an independent energy company, operates the facilities and owns the remaining 75% interest. Thunder Creek's operations include a 450 million cubic feet per day, 126-mile, 24-inch trunk-line, a 225 million cubic feet per day amine-type carbon dioxide treating plant, 340 miles of gathering lines and one major trunkline compressor station with a total 11,275 horsepower. Thunder Creek was established to construct, equip, operate and maintain natural gas gathering, compression, and treating facilities within a large area of mutual interest in the Powder River Basin of eastern Wyoming. The Powder River Basin encompasses approximately 26,000 square miles of eastern Wyoming and southeastern Montana and contains an estimated 1 trillion tons of coal. With gas content of the coal in the basin ranging from 30 to 75 standard cubic feet per ton, industry estimates place potential recoverable coalbed methane reserves within the Powder River Basin somewhere between 10 trillion cubic feet and 15 trillion cubic feet. 17 18 CO2 PIPELINES On March 5, 1998, we and affiliates of Shell Exploration & Production Company combined our carbon dioxide activities and assets into a partnership (Shell CO2 Company, Ltd.). Shell CO2 Company, Ltd. was established to transport, market and produce carbon dioxide for use in enhanced oil recovery operations in the continental United States. We acquired a 20% interest in Shell CO2 Company, Ltd. in exchange for contributing our Central Basin Pipeline and approximately $25 million in cash. Shell contributed the following assets in exchange for the remaining 80% ownership interest: o an approximate 45% interest in the McElmo Dome carbon dioxide reserves; o an 11% interest in the Bravo Dome carbon dioxide reserves; o an indirect 50% interest in the Cortez Pipeline; o a 13% interest in the Bravo Pipeline; and o certain other related assets. These assets facilitated our marketing of carbon dioxide by bringing a complete package of carbon dioxide supply, transportation and technical expertise to the customer. Carbon dioxide is used in enhanced oil recovery projects as a flooding medium for recovering crude oil from mature oil fields. On April 1, 2000, we acquired the remaining 80% interest in Shell CO2 Company, Ltd. from Shell for $212.1 million. After the closing, we renamed Shell CO2 Company, Ltd., Kinder Morgan CO2 Company, L.P. We own a 98.9899% limited partner interest in KMCO2 and our general partner owns a direct 1.0101% general partner interest. On June 1, 2000, we announced an agreement to acquire carbon dioxide asset interests from Devon Energy Production Company L.P. for approximately $55 million. All of the properties acquired were located in the Permian Basin of west Texas and the principal assets were an 81% interest in the Canyon Reef Carriers carbon dioxide pipeline and a working interest in the SACROC unit (oil field). Additionally, we acquired minority interests in the Sharon Ridge unit, operated by Exxon Mobil, the Reinecke unit, operated by Spirit 76, and gas processing plants used to recover injected carbon dioxide. On December 28, 2000, we announced that KMCO2 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. It is owned 85% by Marathon Oil Company and 15% by KMCO2. McElmo and Bravo Domes. We operate and own approximately 45% of McElmo Dome, which contains more than 11 trillion cubic feet of nearly pure carbon dioxide. Compression capacity exceeds one billion cubic feet per day. While current wellbore capacity is about 850 million cubic feet per day, additional wells are planned to increase deliverability by approximately 1 billion cubic feet per day. McElmo Dome produces from the Leadville formation at 8,000 feet with 44 wells that produce at individual rates of up to 100 million cubic feet per day. Bravo Dome, of which we own approximately 11%, holds reserves of approximately two trillion cubic feet of carbon dioxide. Bravo Dome produces approximately 333 million cubic feet per day, with production coming from more than 350 wells in the Tubb Sandstone at 2,300 feet. Pipelines. Placed in service in 1985, our Central Basin Pipeline consists of approximately 143 miles of 16-inch to 20-inch main pipeline and 157 miles of 4-inch to 12-inch lateral supply lines located in the Permian Basin between Denver City, Texas and McCamey, Texas with a throughput capacity of 600 million cubic feet per day. At its origination point in Denver City, our Central Basin Pipeline interconnects with all three major carbon dioxide supply pipelines from Colorado and New Mexico, namely the Cortez Pipeline (operated by KMCO2) and the Bravo and Sheep Mountain Pipelines (operated by BP Amoco). Central Basin Pipeline's mainline terminates near McCamey where it interconnects with the Canyon Reef Carriers Pipeline. We operate and own a 50% interest in the 502-mile, 30-inch Cortez Pipeline. Prior to January 1, 2001, Cortez Pipeline was operated by a Shell affiliate. This pipeline carries carbon dioxide from the McElmo Dome source reservoir to the Denver City, Texas hub. The Cortez Pipeline currently transports in excess of 700 million cubic feet 18 19 per day, including approximately 90% of the carbon dioxide transported on our Central Basin Pipeline. In addition, we own 13% of the 218 mile 20-inch Bravo Pipeline, which delivers to the Denver City hub and has a capacity of more than 350 million cubic feet per day. Major delivery points along the line include the Slaughter Field in Cochran and Hockley counties, Texas, and the Wasson field in Yoakum County, Texas. Tariffs on the Cortez and Bravo pipelines are not regulated. In addition, we own 81% of the Canyon Reef Carriers Pipeline. The Canyon Reef Carriers Pipeline, constructed in 1972, is the oldest carbon dioxide pipeline in West Texas. The Canyon Reef Carriers Pipeline extends 140 miles from McCamey, Texas, to our SACROC field. This pipeline is 16 inches in diameter and has a capacity of approximately 240 million cubic feet per day and makes deliveries to the SACROC, Sharon Ridge and Reinecke units. SACROC Unit. The SACROC unit, in which we have a 71% working interest, is comprised of approximately 50,000 acres located in the Permian Basin in Scurry County, Texas. SACROC was discovered in 1948 and has produced over 1.2 billion barrels of oil since inception. The current production rate is approximately 9,000 barrels of oil per day from 250 producing wells. Markets. Our principal market for carbon dioxide is for injection into mature oil fields in the Permian Basin, where industry demand is expected to be comparable to historical demand for the next several years. We have negotiated making deliveries to two new projects, the Cogdell field, operated by Occidental Petroleum and the HT Boyd field, operated by Anadarko Petroleum. Deliveries are expected to begin by mid 2001. We are exploring additional potential markets including southwest and central Kansas, California and the coal bed methane production in the San Juan Basin of New Mexico. Competition. Our primary competitors for the sale of carbon dioxide include suppliers that have an ownership interest in McElmo Dome, Bravo Dome and Sheep Mountain Dome carbon dioxide reserves. Our ownership interests in the Cortez and Bravo pipelines are in direct competition with Sheep Mountain pipeline and Petrosource Carbon Company's carbon dioxide pipeline. We also compete with other interests in McElmo Dome and Cortez Pipeline, for transportation of carbon dioxide to the Denver City, Texas market area. There is no assurance that new carbon dioxide source fields will not be discovered which could compete with us or that new methodologies for enhanced oil recovery could replace carbon dioxide flooding. BULK TERMINALS Our Bulk Terminals segment consists of over 25 bulk terminals, which handle approximately 40 million tons of dry and liquid bulk products annually. COAL TERMINALS Our Cora Terminal is a high-speed, rail-to-barge coal transfer and storage facility. Built in 1980, the terminal is located on approximately 480 acres of land along the upper Mississippi River near Cora, Illinois, about 80 miles south of St. Louis, Missouri. The terminal has a throughput capacity of about 15 million tons per year that can be expanded to 20 million tons with certain capital additions. The terminal currently is equipped to store up to one million tons of coal. This storage capacity provides customers the flexibility to coordinate their supplies of coal with the demand at power plants. Storage capacity at the Cora Terminal could be doubled with additional capital investment. Our Grand Rivers Terminal is operated on land under easements with an initial expiration of July 2014. Grand Rivers is a coal transloading and storage facility located along the Tennessee River just above the Kentucky Dam. The terminal has current annual throughput capacity of approximately 12-15 million tons with a storage capacity of approximately two million tons. With capital improvements, the terminal could handle 25 million tons annually. Our Pier IX Terminal is located in Newport News, Virginia. The terminal originally opened in 1983 and has the capacity to transload approximately 12 million tons of coal annually. It can store 1.3 million tons of coal on its 30-acre storage site. In addition, the Pier IX Terminal operates a cement facility, which has the capacity to transload over 400,000 tons of cement annually. 19 20 In addition, we operate the LAXT Coal Terminal in Los Angeles, California and a smaller coal terminal in Mt. Vernon, Indiana. We are also in the process of developing our Shipyard River Terminal in Charleston, South Carolina, to be able to unload, store, and reload coal imported from various foreign countries. The imported coal is expected to be low sulfur and would be used by local utilities to comply with the Clean Air Act. When modifications are complete, Shipyard River Terminal will have the capacity to handle 2.5 million tons per year. Markets. Coal continues to dominate as the fuel for electric generation, accounting for more than 55% of United States electric generation feedstock. Forecasts of overall coal usage and power plant usage for the next 20 years show an increase of about 1.5% per year. Current domestic supplies are predicted to last for several hundred years. Most coal transloaded through our coal terminals is destined for use in coal-fired electric generation. We believe that obligations to comply with the Clean Air Act Amendments of 1990 will cause shippers to increase the use of low-sulfur coal from the western United States. Approximately 80% of the coal loaded through our Cora Terminal and our Grand Rivers Terminal is low sulfur coal originating from mines located in the western United States, including the Hanna and Powder River basins in Wyoming, western Colorado and Utah. In 2000, four major customers accounted for approximately 90% of all the coal loaded through our Cora Terminal and our Grand Rivers Terminal. Both Pier IX and LAXT export coal to foreign markets. Substantial portions of the coal transloaded at these facilities are covered by long-term contracts. In addition, Pier IX serves power plants on the eastern seaboard of the United States and imports cement pursuant to a long-term contract. Supply. Historically, our Cora and Grand Rivers terminals have moved coal that originated in the mines of southern Illinois and western Kentucky. Many shippers, however, particularly in the East, are now using western coal loaded at the terminals or a mixture of western coal and other coals as a means of meeting environmental restrictions. We believe that Illinois and Kentucky coal producers and shippers will continue to be important customers, but anticipate that growth in volume through the terminals will be primarily due to western low sulfur coal originating in Wyoming, Colorado and Utah. Our Cora Terminal sits on the mainline of the Union Pacific Railroad and is strategically positioned to receive coal shipments from the West. Grand Rivers provides easy access to the Ohio-Mississippi River network and the Tennessee-Tombigbee System. The Paducah & Louisville Railroad, a short line railroad, serves Grand Rivers with connections to seven Class I rail lines including the Union Pacific, CSX, Illinois Central and Burlington Northern Santa Fe. The Pier IX Terminal is served by the CSX Railroad, which transports coal from central Appalachian and other eastern coal basins. Cement imported at the Pier IX Terminal primarily originates in Europe. The Union Pacific Railroad serves LAXT. Competition. Our Cora Terminal and our Grand Rivers Terminal compete with several coal terminals located in the general geographic area. No significant new coal terminals have been constructed near our Cora Terminal or our Grand Rivers Terminal in the last ten years. We believe our Cora Terminal and our Grand Rivers Terminal can compete successfully with other terminals because of their favorable location, independent ownership, available capacity, modern equipment and large storage areas. Our Pier IX Terminal competes primarily with two modern coal terminals located in the same Virginian port complex as our Pier IX Terminal. There are significant barriers to entry for the construction of new coal terminals, including the requirement for significant capital expenditures and restrictive environmental permitting requirements. PETROLEUM COKE AND OTHER BULK TERMINALS We own or operate 8 petroleum coke terminals in the United States. Petroleum coke is a by-product of the refining process and has characteristics similar to coal. Petroleum coke supply in the United States has increased in the last several years due to the increased use of coking units by domestic refineries. Petroleum coke is used in domestic utility and industrial steam generation facilities and is exported to foreign markets. Most of our customers are large integrated oil companies that choose to outsource the storage and loading of petroleum coke for a fee. We own or operate an additional 12 bulk terminals located primarily on the southern edge of the lower Mississippi River, the Gulf Coast and the West Coast. These other bulk terminals serve customers in the alumina, 20 21 cement, salt, soda ash, ilminite, fertilizer, ore and other industries seeking specialists who can build, own and operate bulk terminals. Competition. Our petroleum coke and other bulk terminals compete with numerous independent terminal operators, with other terminals owned by oil companies and other industrials opting not to outsource terminal services. Competition against the petroleum coke terminals that we operate but do not own has increased significantly primarily from companies that also market and sell the product. This increased competition will likely decrease profitability in this segment. Many of our other bulk terminals were constructed pursuant to long-term contracts for specific customers. As a result, we believe other terminal operators would face a significant disadvantage in competing for this business. LIQUID TERMINALS On December 1, 2000, we purchased the stock of Delta Terminal Services, Inc. for $114.1 million. Delta operates a large liquids terminal in New Orleans, with 2.8 million barrels of storage, four docks and seven drumming buildings, as well as a smaller liquids terminal in Cincinnati, Ohio. These terminals handle a variety of chemicals, vegetable oils and other liquid petroleum products and compete with several large independent terminal operators. MAJOR CUSTOMERS Our total operating revenues are derived from a wide customer base. During 2000 and 1999, no revenues from transactions with a single external customer amounted to 10% or more of our consolidated revenues. For the year ended December 31, 1998, the following customers accounted for more than 10% of our consolidated revenues: o Equilon Enterprises(1) 13.2% o Tosco Group 12.3% o Chevron 11.0% o ARCO 10.9% (1) Equilon is the name of the joint venture, formed in January 1998, that combined major elements of Texaco's and Shell's mid-western and western U.S. refining and marketing businesses and nationwide trading, transportation and lubricants businesses. EMPLOYEES We do not have any employees. Our general partner and/or our subsidiary entities employ all persons necessary for the operation of our business. We reimburse our general partner for the services of its employees. As of February 1, 2001, our general partner and/or our subsidiary entities had approximately 1,600 employees. Approximately 100 hourly personnel at certain terminals are represented by five labor unions. No other employees of our general partner or our subsidiaries are members of a union or have a collective bargaining agreement. Our general partner and our subsidiaries consider their relations with their employees to be good. REGULATION INTERSTATE COMMON CARRIER REGULATION Some of our pipelines are interstate common carrier pipelines, subject to regulation by the Federal Energy Regulatory Commission under the Interstate Commerce Act. The ICA requires that we maintain our tariffs on file with the FERC, which tariffs set forth the rates we charge for providing transportation services on our interstate common carrier pipelines as well as the rules and regulations governing these services. Petroleum pipelines may change their rates within prescribed ceiling levels that are tied to an inflation index. Shippers may protest rate increases made within the ceiling levels, but such protests must show that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline's increase in costs. A pipeline must, as a general rule, utilize the indexing methodology to change its rates. The FERC, however, uses cost-of-service ratemaking, market-based rates and settlement as alternatives to the indexing approach in certain specified 21 22 circumstances. In 2000, 1999 and 1998, application of the indexing methodology did not significantly affect our rates. The ICA requires, among other things, that such rates be "just and reasonable" and nondiscriminatory. The ICA permits interested persons to challenge newly proposed or changed rates and authorizes the FERC to suspend the effectiveness of such rates for a period of up to seven months and to investigate such rates. If, upon completion of an investigation, the FERC finds that the new or changed rate is unlawful, it is authorized to require the carrier to refund the revenues in excess of the prior tariff collected during the pendency of the investigation. The FERC may also investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained during the two years prior to the filing of a complaint. On October 24, 1992, Congress passed the Energy Policy Act of 1992. The Energy Policy Act deemed petroleum pipeline rates that were in effect for the 365-day period ending on the date of enactment or that were in effect on the 365th day preceding enactment and had not been subject to complaint, protest or investigation during the 365-day period to be just and reasonable under the ICA (i.e., "grandfathered"). The Energy Policy Act also limited the circumstances under which a complaint can be made against such grandfathered rates. The rates we charge for transportation service on our North System and Cypress Pipeline were not suspended or subject to protest or complaint during the relevant 365-day period established by the Energy Policy Act. For this reason, we believe these rates should be grandfathered under the Energy Policy Act. Certain rates on our Pacific operations' pipeline system were subject to protest during the 365-day period established by the Energy Policy Act. Accordingly, certain of the Pacific pipelines' rates have been, and continue to be, subject to complaints with the FERC, as is more fully described in Item 3. Legal Proceedings. Both the performance of interstate transportation and storage services by natural gas companies, including interstate pipeline companies, and the rates charged for such services, are regulated by the FERC under the Natural Gas Act and, to a lesser extent, the Natural Gas Policy Act. Legislative and regulatory changes began in 1978 with the passage of the Natural Gas Policy Act, pursuant to which the process of deregulation of natural gas sold at the wellhead was commenced. The restructuring of the natural gas industry continued with the adoption of: o Order 380 in 1984, which eliminated purchasers' minimum bill obligations to pipelines, thus making natural gas purchased from third parties, particularly on the spot market, more economically attractive relative to natural gas purchased from pipelines; and o Order 436 in 1985, which provided that interstate transportation of natural gas under blanket or self-implementing authority must be provided on an open-access, non-discriminatory basis. After Order 436 was partially overturned in federal court, the FERC issued Order 500 in August 1987 as an interim rule intended to readopt the basic thrust of the regulations promulgated by Order 436. Order 500 was amended by Orders 500 A through L. The FERC's stated purpose in issuing Orders 436 and 500, as amended, was to create a more competitive environment in the natural gas marketplace. This purpose continued with Order 497, issued in June 1988, which set forth new standards and guidelines imposing certain constraints on the interaction of interstate pipelines and their marketing affiliates and imposing certain disclosure requirements regarding that interaction. Order 636, issued in April 1992, as amended, was a continuation of the FERC's efforts to improve the competitive structure of the pipeline industry and maximize the consumer benefits of a competitive structure of the pipeline industry and a competitive wellhead gas market. In Order 636, the FERC required interstate pipelines that perform open access transportation under blanket certificates to "unbundle" or separate their traditional merchant sales services from their transportation and storage services and to provide comparable transportation and storage services with respect to all natural gas supplies whether purchased from the pipeline or from other merchants such as marketers or producers. Pipelines must now separately state the applicable rates for each unbundled service they provide (i.e., for the natural gas commodity, transportation and storage). Specifically, Order 636 contains the following procedures to increase competition in the industry: o requiring the unbundling of sales services from other services, meaning that only a separately identified merchant affiliate of the pipeline could sell natural gas at points of entry into the pipeline system; o permitting holders of firm capacity to release all or a part of their capacity for resale by the pipeline either to the highest bidder or, under short-term or maximum rate releases, to shippers in a prepackaged release, with revenues in both instances credited to the releasing shipper; 22 23 o allowing shippers to use as secondary points other receipt points and delivery points on the system, subject to the rights of other shippers to use those points as their primary receipt and delivery points; o the issuance of blanket sales certificates to interstate pipelines for unbundled services; o the continuation of pre-granted abandonment of previously committed pipeline sales and transportation services, subject to certain rights of first refusal, which should make unused pipeline capacity available to other shippers and clear the way for excess transportation services to be reallocated to the marketplace; o requiring that firm and interruptible transportation services be provided by pipelines to all parties on a comparable basis; and o generally requiring that pipelines derive transportation rates using a straight-fixed-variable rate method which places all fixed costs in a fixed reservation fee that is payable without regard to usage, as opposed to the previously used modified fixed-variable method that allocated a part of the pipelines' fixed costs to the usage fee. The FERC's stated position is that the straight-fixed-variable method promotes the goal of a competitive national gas market by increasing the cost of unnecessarily holding firm capacity rather than releasing it, and is consistent with its directive to unbundle pipelines' traditional merchant sales services. Order 636 has been affirmed in all material respects upon judicial review and our own FERC orders approving our unbundling plans are final and not subject to any pending judicial review. Our acquisition of the KMIGT interstate natural gas pipeline system has resulted in a significant increase in the percentage of our assets subject to regulation by the FERC. To the extent any of our interstate pipelines ever have marketing affiliates, we would become subject to the requirements of FERC Order Nos. 497, et. seq., and 566, et. seq., the Marketing Affiliate Rules, which prohibit preferential treatment by an interstate pipeline of its marketing affiliates and govern in particular the provision of information by an interstate pipeline to its marketing affiliates. The intrastate common carrier operations of our Pacific operations' pipelines in California are subject to regulation by the California Public Utilities Commission under a "depreciated book plant" methodology, which is based on an original cost measure of investment. Intrastate tariffs filed by us with the CPUC have been established on the basis of revenues, expenses and investments allocated as applicable to the intrastate portion of our business. Tariff rates with respect to intrastate pipeline service in California are subject to challenge by complaint by interested parties or by independent action of the CPUC. A variety of factors can affect the rates of return permitted by the CPUC and certain other issues similar to those which have arisen with respect to our FERC regulated rates could also arise with respect to our intrastate rates. Certain of our Pacific operations' pipeline rates have been, and continue to be, subject to complaints with the CPUC, as is more fully described in Item 3. Legal Proceedings. STATE AND LOCAL REGULATION Our activities are subject to various state and local laws and regulations, as well as orders of regulatory bodies, governing a wide variety of matters, including: o marketing; o production; o pricing; o pollution; o protection of the environment; and o safety. SAFETY REGULATION Our pipelines are subject to regulation by the United States Department of Transportation with respect to their design, installation, testing, construction, operation, replacement and management. In addition, we must permit access to and copying of records, and make certain reports and provide information as required by the Secretary of Transportation. Comparable regulation exists in some states in which we conduct pipeline operations. In addition, our truck and bulk terminal loading facilities are subject to U.S. DOT regulations dealing with the transportation of hazardous materials for motor vehicles and rail cars. We believe that we are in substantial compliance with U.S. DOT and comparable state regulations. 23 24 We are also subject to the requirements of the Federal Occupational Safety and Health Act and comparable state statutes. We believe that we are in substantial compliance with Federal OSHA requirements, including general industry standards, recordkeeping requirements and monitoring of occupational exposure to hazardous substances. In general, we expect to increase expenditures in the future to comply with higher industry and regulatory safety standards. Such expenditures cannot be accurately estimated at this time, although we do not expect that such expenditures will have a material adverse impact on us, except to the extent additional hydrostatic testing requirements are imposed. ENVIRONMENTAL MATTERS Our operations are subject to federal, state and local laws and regulations relating to protection of the environment. We believe that our operations and facilities are in substantial compliance with applicable environmental regulations. We have an ongoing environmental compliance program. However, risks of accidental leaks or spills are associated with the transportation of natural gas liquids, refined petroleum products, natural gas and carbon dioxide, the handling and storage of bulk materials and the other activities conducted by us. There can be no assurance that we will not incur significant costs and liabilities, including those relating to claims for damages to property and persons resulting from operation of our businesses. Moreover, it is possible that other developments, such as increasingly strict environmental laws and regulations and enforcement policies thereunder, could result in increased costs and liabilities to us. Environmental laws and regulations have changed substantially and rapidly over the last 25 years, and we anticipate that there will be continuing changes. The clear trend in environmental regulation is to increase reporting obligations and place more restrictions and limitations on activities, such as emissions of pollutants, generation and disposal of wastes and use, storage and handling of chemical substances, that may impact human health, the environment and/or endangered species. Increasingly strict environmental restrictions and limitations have resulted in increased operating costs for us and other similar businesses throughout the United States. It is possible that the costs of compliance with environmental laws and regulations will continue to increase. We will attempt to anticipate future regulatory requirements that might be imposed and to plan accordingly in order to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. SOLID WASTE We own several properties that have been used for many years for the transportation and storage of refined petroleum products and natural gas liquids and the handling and storage of coal and other bulk materials. Solid waste disposal practices within the petroleum industry have changed over the years with the passage and implementation of various environmental laws and regulations. Hydrocarbons and other solid wastes may have been disposed of in, on or under various properties owned by us during the operating history of the facilities located on such properties. In such cases, hydrocarbons and other solid wastes could migrate from their original disposal areas and have an adverse effect on soils and groundwater. We do not believe that there currently exists significant surface or subsurface contamination of our assets by hydrocarbons or other solid wastes not already identified and addressed. We have maintained a reserve to account for the costs of cleanup at these sites. We generate both hazardous and nonhazardous solid wastes that are subject to the requirements of the Federal Resource Conservation and Recovery Act and comparable state statutes. From time to time, state regulators and the United States Environmental Protection Agency consider the adoption of stricter disposal standards for nonhazardous waste. Furthermore, it is possible that some wastes that are currently classified as nonhazardous, which could include wastes currently generated during pipeline or bulk terminal operations, may in the future be designated as "hazardous wastes." Hazardous wastes are subject to more rigorous and costly disposal requirements. Such changes in the regulations may result in additional capital expenditures or operating expenses for us. SUPERFUND The Comprehensive Environmental Response, Compensation and Liability Act, also known as the "Superfund" law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of "potentially responsible persons" for releases of "hazardous substances" into the environment. These persons include the owner or operator of a site and companies that disposed of or arranged for the disposal of the hazardous substances found at the site. CERCLA authorizes the U.S. EPA and, in some cases, third parties to take actions in response to threats 24 25 to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. Although "petroleum" is excluded from CERCLA's definition of a "hazardous substance," in the course of our ordinary operations, we will generate wastes that may fall within the definition of "hazardous substance." By operation of law, if we are determined to be a potentially responsible person, we may be responsible under CERCLA for all or part of the costs required to clean up sites at which such wastes have been disposed. EPA GASOLINE VOLATILITY RESTRICTIONS In order to control air pollution in the United States, the U.S. EPA has adopted regulations that require the vapor pressure of motor gasoline sold in the United States to be reduced from May through mid-September of each year. These regulations mandated vapor pressure reductions beginning in 1989, with more stringent restrictions beginning in 1992. States may impose additional volatility restrictions. The regulations have had a substantial effect on the market price and demand for normal butane, and to some extent isobutane, in the United States. Gasoline manufacturers use butanes in the production of motor gasolines. Since normal butane is highly volatile, it is now less desirable for use in blended gasolines sold during the summer months. Although the U.S. EPA regulations have reduced demand and may have resulted in a significant decrease in prices for normal butane, low normal butane prices have not impacted our pipeline business in the same way they would impact a business with commodity price risk. The U.S. EPA regulations have presented the opportunity for additional transportation services on our North System. In the summer of 1991, our North System began long-haul transportation of refinery grade normal butane produced in the Chicago area to the Bushton, Kansas area for storage and subsequent transportation north from Bushton during the winter gasoline blending season. CLEAN AIR ACT Our operations are subject to the Clean Air Act and comparable state statutes. We believe that the operations of our pipelines, storage facilities and bulk terminals are in substantial compliance with such statutes. Numerous amendments to the Clean Air Act were adopted in 1990. These amendments contain lengthy, complex provisions that may result in the imposition over the next several years of certain pollution control requirements with respect to air emissions from the operations of the pipelines, storage facilities and bulk terminals. The U.S. EPA is developing, over a period of many years, regulations to implement those requirements. Depending on the nature of those regulations, and upon requirements that may be imposed by state and local regulatory authorities, we may be required to incur certain capital expenditures over the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals and addressing other air emission-related issues. Due to the broad scope and complexity of the issues involved and the resultant complexity and controversial nature of the regulations, full development and implementation of many of the regulations have been delayed. Until such time as the new Clean Air Act requirements are implemented, we are unable to estimate the effect on earnings or operations or the amount and timing of such required capital expenditures. At this time, however, we do not believe that we will be materially adversely affected by any such requirements. RISK FACTORS RISKS RELATED TO OUR BUSINESS PENDING FEDERAL ENERGY REGULATORY COMMISSION AND CALIFORNIA PUBLIC UTILITIES COMMISSION PROCEEDINGS SEEK SUBSTANTIAL REFUNDS AND REDUCTIONS IN TARIFF RATES ON SOME OF OUR PACIFIC OPERATIONS' PIPELINES. Some shippers on our Pacific operations' pipelines have filed complaints with the Federal Energy Regulatory Commission and California Public Utilities Commission that seek substantial refunds and reductions in the tariff rates on such pipelines. Adverse decisions regarding these complaints could negatively impact our cash flow. Additional challenges to tariff rates could be filed with the Federal Energy Regulatory Commission and California Public Utilities Commission in the future. In the first set of complaints filed between 1992 and 1995 before the Federal Energy Regulatory Commission, some shippers alleged that pipeline tariff rates: 25 26 o for the West Line, serving southern California and Arizona, were not entitled to "grandfathered" status under the Energy Policy Act because "substantially changed circumstances" had occurred pursuant to the Energy Policy Act; and o for the East Line, serving New Mexico and Arizona, were unjust and unreasonable. An initial decision by the FERC administrative law judge was issued on September 25, 1997. The initial decision determined that our Pacific operations' West Line rates were grandfathered under the Energy Policy Act. The initial decision also included rulings that were generally adverse to our Pacific operations' East Line regarding certain cost of service issues. On January 13, 1999, the FERC issued an opinion that affirmed, in major respects, the initial decision, but also modified parts of the decision that were adverse to us. In May 2000, the FERC issued a new opinion affirming in part and modifying and clarifying in part the January 13, 1999 opinion. Some of the complainants have appealed the FERC's decision to the United States Court of Appeals for the District of Columbia Circuit. During the pendency of the above-referenced complaint proceeding, some shippers filed complaints that predominantly attacked the pipeline tariff rates of our Pacific operations' pipelines, contending that the rates were not just and reasonable under the ICA and should not be entitled to "grandfathered" status under the Energy Policy Act. These complaints covered rates for service on the East Line, the West Line, the North Line serving the area between San Francisco, California and Reno, Nevada, and the Oregon Line serving the area from Portland, Oregon to Eugene, Oregon. The complaints seek substantial reparations for alleged overcharges during the years in question and request prospective rate reduction on each of the challenged facilities. These complaints are expected to proceed to hearing in August 2001, with an initial decision by the administrative law judge expected in the first half of 2002. In January 2000, several of the shippers amended and restated their complaints challenging the tariff rates of our Pacific operations' pipelines and filed additional complaints in July and August 2000. We are vigorously defending against all of these complaints. The complaints filed before the CPUC challenge the rates charged for intrastate transportation of refined petroleum products through our Pacific operations' pipeline system in California. On August 6, 1998, the CPUC issued its decision dismissing the complainants' challenge to SFPP, L.P.'s intrastate rates. On June 24, 1999, the CPUC granted limited rehearing of its August 1998 decision for the purpose of: o addressing the proper ratemaking treatment for partnership tax expenses; o the calculation of environmental costs; and o the public utility status of SFPP, L.P.'s Sepulveda Line and its Watson Station gathering enhancement facilities. In pursuing these rehearing issues, the complainants seek prospective rate reductions aggregating approximately $10 million per year. On April 10, 2000, the complainants filed a new complaint with the CPUC asserting SFPP, L.P.'s intrastate rates were not just and reasonable. See Note 16 of the Notes to our Consolidated Financial Statements for additional information. OUR ACQUISITION STRATEGY MAY REQUIRE ACCESS TO NEW CAPITAL, AND TIGHTENED CREDIT MARKETS OR MORE EXPENSIVE CAPITAL WILL IMPAIR OUR ABILITY TO EXECUTE OUR STRATEGY. Part of our business strategy includes acquiring additional businesses that will allow us to increase distributions to unitholders. During the period from December 31, 1996 to December 31, 2000, we made several acquisitions that increased our asset base over 14 times and increased our net income over 23 times. We regularly consider and enter into discussions regarding potential acquisitions and are currently contemplating potential acquisitions. While there are currently no unannounced purchase agreements pending for the acquisition of any business or assets, such transactions can be effected quickly, may occur at any time and may be significant in size relative to our existing assets. We may need new capital to finance these acquisitions. Limitations on our access to capital will impair our ability to execute our strategy. Expensive capital will limit our ability to make acquisitions accretive. Our ability to maintain our capital structure may impact the market value of our common units and our debt securities. 26 27 ENVIRONMENTAL REGULATION SIGNIFICANTLY AFFECTS OUR BUSINESS. Our business operations are subject to federal, state and local laws and regulations relating to environmental protection. If an accidental leak or spill of liquid petroleum products occurs from our pipelines or at our storage 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 cash flow. In addition, emission controls required under the Federal Clean Air Act and other similar federal and state laws could require significant capital expenditures at our facilities. Although we cannot predict the impact of EPA standards or future environmental measures, our costs could increase significantly if environmental laws and regulations become stricter. Since the costs of environmental regulation are already significant, additional regulation could negatively affect our business. COMPETITION COULD ULTIMATELY LEAD TO LOWER LEVELS OF PROFITS AND LOWER OUR CASH FLOW. Propane competes with electricity, fuel, oil and natural gas in the residential and commercial heating market. In the engine fuel market, propane competes with gasoline and diesel fuel. Butanes and natural gasoline used in motor gasoline blending and isobutane used in premium fuel production compete with alternative products. Natural gas liquids used as feed stocks for refineries and petrochemical plants compete with alternative feed stocks. The availability and prices of alternative energy sources and feed stocks significantly affect demand for natural gas liquids. Refined product pipelines are generally the lowest cost method for intermediate and long-haul overland refined product movement. Accordingly, the most significant competitors to our product pipelines are: o proprietary pipelines owned and operated by major oil companies in the areas where our pipelines deliver products; o refineries within the market areas served by our product pipelines; and o trucks. Additional product pipelines may be constructed in the future to serve specific markets now served by our pipelines. Trucks competitively deliver products in certain markets. Recently, major oil companies have increased the usage of trucks, resulting in minor but notable reductions in product volumes delivered to certain shorter-haul destinations, primarily Orange County and Colton, California served by the South and West lines of our Pacific operations. We cannot predict with certainty whether this trend towards increased short-haul trucking will continue in the future. Demand for terminaling services varies widely throughout the product pipeline system. Certain major petroleum companies and independent terminal operators directly compete with us at several terminal locations. At those locations, pricing, service capabilities and available tank capacity control market share. Our natural gas and carbon dioxide pipelines compete against other existing natural gas and carbon dioxide pipelines originating from the same sources or serving the same markets as our natural gas and carbon dioxide pipelines. In addition, we also may face competition from natural gas pipelines that may be built in the future. Our coal terminals compete with other coal terminals located in the same general geographic areas. Our petroleum coke and other bulk terminals compete with numerous independent terminal operators, with other terminals owned by oil companies and other industrials opting not to outsource terminal services. Competition against the petroleum coke terminals that we operate but do not own has increased significantly primarily from companies that also market and sell the product. Our ability to compete also depends upon general market conditions, which may change. We conduct our operations without the benefit of exclusive franchises from government entities. We provide common carrier transportation services through our pipelines at posted tariffs and, with respect to our Pacific operations, almost always without long-term contracts for transportation service with customers. Demand for transportation services on our pipelines is primarily a function of: o total and per capita consumption; o prevailing economic and demographic conditions; o alternate modes of transportation; o alternate sources; and 27 28 o price. WE GENERALLY DO NOT OWN THE LAND ON WHICH OUR PIPELINES ARE CONSTRUCTED AND WE ARE SUBJECT TO THE POSSIBILITY OF INCREASED COSTS FOR THE LOSS OF LAND USE. 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. If we were to lose these rights, our business could be affected negatively. Southern Pacific Transportation Company has allowed us to construct and operate a significant portion of our Pacific operations' pipeline under their railroad tracks. Southern Pacific Transportation Company and its predecessors were given the right to construct their railroad tracks under federal statutes enacted in 1871 and 1875. The 1871 statute was thought to be an outright grant of ownership that would continue until the land ceased to be used for railroad purposes. Two United States Circuit Courts, however, ruled in 1979 and 1980 that railroad rights-of-way granted under laws similar to the 1871 statute provide only the right to use the surface of the land for railroad purposes without any right to the underground portion. If a court were to rule that the 1871 statute does not permit the use of the underground portion for the operation of a pipeline, we may be required to obtain permission from the land owners in order to continue to maintain the pipelines. No assurance can be given that we could obtain that permission over time at a cost that would not negatively affect us. Whether we have the power of eminent domain for our pipelines varies from state to state depending upon the type of pipeline -- petroleum liquids, natural gas or carbon dioxide -- and the laws of the particular state. Our inability to exercise the power of eminent domain could negatively affect our business if we were to lose the right to use or occupy the property on which our pipelines are located. OUR RAPID GROWTH MAY CAUSE DIFFICULTIES INTEGRATING NEW OPERATIONS. Part of our business strategy includes acquiring additional businesses that will allow us to increase distributions to unitholders. During the period from December 31, 1996 to December 31, 2000, we made several acquisitions that increased our asset base over 14 times and increased our net income over 23 times. We believe that we can profitably combine the operations of acquired businesses with our existing operations. However, unexpected costs or challenges may arise whenever businesses with different operations and management are combined. Successful business combinations require management and other personnel to devote significant amounts of time to integrating the acquired business with existing operations. These efforts may temporarily distract their attention from day-to-day business, the development or acquisition of new properties and other business opportunities. In addition, the management of the acquired business often will not join our management team. The change in management may make it more difficult to integrate an acquired business with our existing operations. OUR DEBT INSTRUMENTS MAY LIMIT OUR FINANCIAL FLEXIBILITY. The instruments governing our debt contain restrictive covenants that may prevent us from engaging in certain transactions we deem beneficial. The agreements governing our debt generally require us to comply with various affirmative and negative covenants, including the maintenance of certain financial ratios and restrictions on: o incurring additional debt; o entering into mergers, consolidations and sales of assets; and o granting liens. The instruments governing any future debt may contain similar restrictions. RESTRICTIONS ON OUR ABILITY TO PREPAY THE DEBT OF SFPP, L.P. MAY LIMIT OUR FINANCIAL FLEXIBILITY. SFPP, L.P. is subject to restrictions with respect to its debt that may limit our flexibility in structuring or refinancing existing or future debt. These restrictions include the following: o before December 15, 2002, we may prepay SFPP, L.P.'s first mortgage notes with a make-whole prepayment premium; and o we agreed as part of the acquisition 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. 28 29 RISK RELATED TO OWNERSHIP OF OUR DEBT SECURITIES IF WE DEFAULT DEBT SECURITIES ARE STRUCTURALLY SUBORDINATED TO DEBT OF OUR OPERATING PARTNERSHIPS AND SUBSIDIARIES. Since we do not anticipate that any of our operating partnerships or subsidiaries will guarantee our debt securities, our existing and future debt securities will be effectively subordinated to all debt of our operating partnerships and subsidiaries. As of December 31, 2000, our operating partnerships and subsidiaries had $165.4 million of debt (excluding intercompany debt). If any of our operating partnerships or subsidiaries defaults on its debt, the holders of our debt securities would not receive any money from the defaulting operating partnership or subsidiary until it had repaid all of its debts in full. RISKS RELATED TO OWNERSHIP OF OUR UNITS IF WE DEFAULT UNITHOLDERS MAY HAVE NEGATIVE TAX CONSEQUENCES IF WE DEFAULT ON OUR DEBT OR SELL ASSETS. If we default on any of our debt, the lenders will have the right to sue us for non-payment. Such an action could cause an investment loss and cause negative tax consequences for unitholders through the realization of taxable income by unitholders without a corresponding cash distribution. Likewise, if we were to dispose of assets and realize a taxable gain while there is substantial debt outstanding and proceeds of the sale were applied to the debt, unitholders could have increased taxable income without a corresponding cash distribution. THERE IS THE POTENTIAL FOR A CHANGE OF CONTROL IF KINDER MORGAN, INC. DEFAULTS ON DEBT. Kinder Morgan, Inc. indirectly owns all of the outstanding capital stock of the general partner. KMI has significant operations which provide cash independent of dividends that KMI receives from the general partner. Nevertheless, if KMI defaults on its debt, its lenders could acquire control of our general partner. LIMITATIONS IN OUR PARTNERSHIP AGREEMENT AND STATE PARTNERSHIP LAW OUR UNITHOLDERS HAVE LIMITED VOTING RIGHTS AND CONTROL OF MANAGEMENT. Our unitholders have only limited voting rights on matters affecting the Partnership. Our general partner, through a wholly owned subsidiary, manages our activities. Our unitholders have no right to elect our general partner on an annual or other ongoing basis. If our general partner withdraws, however, the holders of a majority of the outstanding units, excluding units owned by our departing general partner and its affiliates, may elect its successor. Our limited partners may remove our general partner only if: o the holders of at least 66 2/3% of our outstanding units, excluding units owned by our departing general partner and its affiliates, vote to remove our general partner; o a successor general partner is approved by at least 66 2/3% of our outstanding units, excluding units owned by our departing general partner and its affiliates; and o we receive an opinion of counsel opining that the removal would not result in the loss of the limited liability to any of our limited partners or the limited partners of any of our operating partnerships or cause us or our operating partnerships to be taxed other than as a partnership for federal income tax purposes. A PERSON OR GROUP OWNING 20% OR MORE OF OUR UNITS CANNOT VOTE. Any units held by a person or group that owns 20% or more of the common units cannot be voted. This limitation does not apply to our general partner and its affiliates. This provision may: o discourage a person or group from attempting to remove our general partner or otherwise change management; and o reduce the price at which the common units will trade under certain circumstances. For example, a third party will probably not attempt to remove our general partner and take over our management by making a tender offer for our outstanding units at a price above their trading market price without removing our general partner and substituting an affiliate. OUR GENERAL PARTNER'S LIABILITY TO US AND OUR UNITHOLDERS MAY BE LIMITED. Our partnership agreement contains language limiting the liability of our general partner to us or our unitholders. For example, our partnership agreement provides that: 29 30 o our general partner does not breach any duty to us or our unitholders by borrowing funds or approving any borrowing. Our general partner is protected even if the purpose or effect of the borrowing is to increase incentive distributions to our general partner; o our general partner does not breach any duty to us or our unitholders by taking any actions consistent with the standards of reasonable discretion outlined in the definitions of "available cash" and "cash from operations" contained in our partnership agreement; and o our general partner does not breach any standard of care or duty by resolving conflicts of interest unless our general partner acts in bad faith. OUR PARTNERSHIP AGREEMENT MODIFIES THE FIDUCIARY DUTIES OF OUR GENERAL PARTNER UNDER DELAWARE LAW. Such modifications of state law standards of fiduciary duty may significantly limit the ability of unitholders to successfully challenge the actions of our general partner as being a breach of what would otherwise have been a fiduciary duty. These standards include the highest duties of good faith, fairness and loyalty to our limited partners. Such a duty of loyalty would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction for which it has a conflict of interest. Under our partnership agreement, our general partner may exercise its broad discretion and authority in the management of us and the conduct of our operations as long as our general partner's actions are in our best interest. UNITHOLDERS MAY HAVE LIABILITY TO REPAY DISTRIBUTIONS. Unitholders will not be liable for assessments in addition to their initial capital investment in our units. Under certain circumstances, however, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Delaware law, we may not make a distribution to you if the distribution causes our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and non-recourse liabilities are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that for a period of three years from the date of such a distribution, a limited partner who receives the distribution and knew at the time of the distribution that the distribution violated Delaware law will be liable to the limited partnership for the distribution amount. Under Delaware law, an assignee who becomes a substituted limited partner of a limited partnership is liable for the obligations of the assignor to make contributions to the partnership. However, such an assignee is not obligated for liabilities unknown to the assignee at the time the assignee became a limited partner if the liabilities could not be determined from the partnership agreement. UNITHOLDERS MAY BE LIABLE IF WE HAVE NOT COMPLIED WITH STATE PARTNERSHIP LAW. We conduct our business in a number of states. In some of those states the limitations on the liability of limited partners for the obligations of a limited partnership have not been clearly established. Our unitholders might be held liable for our obligations as if they were a general partner if: o a court or government agency determined that we were conducting business in the state but had not complied with the state's partnership statute; or o our unitholders' rights to act together to remove or replace the general partner or take other actions under our partnership agreement constitute "control" of our business. OUR GENERAL PARTNER MAY BUY OUT MINORITY UNITHOLDERS IF IT OWNS 80% OF THE UNITS. If at any time our general partner and its affiliates own 80% or more of our issued and outstanding units, our general partner will have the right to purchase all of the remaining units. Because of this right, a unitholder may have to sell his units against his will or for a less than desirable price. Our general partner may only purchase all of the units. The purchase price for such a purchase will be the greater of: o the most recent 20-day average trading price ending on the date five days prior to the date the notice of purchase is mailed; or o the highest purchase price paid by our general partner or its affiliates to acquire units during the prior 90 days. Our general partner can assign this right to its affiliates or to us. WE MAY SELL ADDITIONAL LIMITED PARTNER INTERESTS, DILUTING EXISTING INTERESTS OF UNITHOLDERS. Our partnership agreement allows our general partner to cause us to issue additional common units and other equity securities. 30 31 When we issue additional equity securities, your proportionate partnership interest will decrease. Such an issuance could negatively affect the amount of cash distributed to unitholders and the market price of our units. Issuance of additional units will also diminish the relative voting strength of the previously outstanding units. There is no limit on the total number of units we may issue. OUR GENERAL PARTNER CAN PROTECT ITSELF AGAINST DILUTION. Whenever we issue equity securities to any person other than our general partner and its affiliates, our general partner has the right to purchase additional limited partnership interests on the same terms. This allows our general partner to maintain its partnership interest in the Partnership. No other unitholder has a similar right. Therefore, only our general partner may protect itself against dilution caused by issuance of additional equity securities. THERE ARE POTENTIAL CONFLICTS OF INTEREST RELATED TO THE OPERATION OF THE PARTNERSHIP. Certain conflicts of interest could arise among our general partner, its ultimate corporate parent, Kinder Morgan, Inc., and us. Such conflicts may include, among others, the following situations: Some of our general partner's officers and directors may have conflicting fiduciary duties to KMI. Some of KMI's directors and officers are also directors and officers of our general partner. Conflicts of interest may result due to the fiduciary duties such directors and officers may have to manage KMI's business in a manner beneficial to KMI and its shareholders. The resolution of these conflicts may not always be resolved in the best interests of our unitholders. Our general partner may not be fully reimbursed for KMI's use of its officers and employees and/or it may over-compensate KMI for our use of KMI's officers and employees. KMI shares administrative personnel with our general partner to operate both KMI's business and our business. As a result, our general partner's officers, who in some cases may also be KMI officers, must allocate, in their reasonable and sole discretion, the time our general partner's employees and KMI's employees spend on behalf of us and on behalf of KMI. These allocations are not the result of arms-length negotiations between our general partner and KMI. Although our general partner intends for the net payments to reflect the relative value received by us and KMI for the use of each others employees, due to the nature of the allocations, this reimbursement may not exactly match the actual time and overhead spent. Since we reimburse our general partner for its general and administrative expenses, the under allocation of the time and overhead spent by our general partners' employees on KMI's activities or the over allocation of the time and overhead spent by KMI's employees on our behalf could negatively affect the amount of cash available for distribution to our unitholders. See Item 13. "Certain Relationships and Related Transactions -- General and Administrative Expenses" in this Report. Our general partner's decisions may affect cash distributions to unitholders. Our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings and reserves. All of these decisions can impact the amount of cash distributed by us to our unitholders, which, in turn, affects the amount of the cash incentive distribution to our general partner. Our general partner generally tries to avoid being personally liable for our obligations. Our general partner is permitted to protect its assets in this manner pursuant to our partnership agreement. Under our partnership agreement, our general partner does not breach its fiduciary duty even if we could have obtained more favorable terms without limitations on our general partner's liability. Our general partner's decision to exercise or assign its call right to purchase all of the limited partnership interests may conflict with our unitholder's interests. If our general partner exercises this right, a unitholder may have to sell its interest against its will or for a less than desirable price. TAX TREATMENT OF PUBLICLY TRADED PARTNERSHIPS UNDER THE INTERNAL REVENUE CODE The Internal Revenue Code of 1986, as amended, imposes certain limitations on the current deductibility of losses attributable to investments in publicly traded partnerships and treats certain publicly traded partnerships as corporations for federal income tax purposes. The following discussion briefly describes certain aspects of the Code that apply to individuals who are citizens or residents of the United States without commenting on all of the federal income tax matters affecting us or our unitholders, and is qualified in its entirety by reference to the Code. OUR 31 32 UNITHOLDERS ARE URGED TO CONSULT THEIR OWN TAX ADVISOR ABOUT THE FEDERAL, STATE, LOCAL AND FOREIGN TAX CONSEQUENCES TO THEM OF AN INVESTMENT IN US. TAX CHARACTERIZATION OF THE PARTNERSHIP The availability of the federal income tax benefits of a unitholder's investment in us depends, in large part, on our classification as a partnership for federal income tax purposes. The Code generally treats a publicly traded partnership formed after 1987 as a corporation unless, for each taxable year of its existence, 90% or more of its gross income consists of qualifying income. If we were to fail to meet the 90% qualified income test for any year, we would be treated as a corporation unless we met the inadvertent failure exception. Qualifying income includes interest, dividends, real property rents, gains from the sale or disposition of real property, income and gains derived from the exploration, development, mining or production, processing, refining, transportation (including pipelines transporting gas, oil or products thereof), or the marketing of any mineral or natural resource (including fertilizer, geothermal energy and timber), and gain from the sale or disposition of capital assets that produced such income. Our general partner believes that more than 90% of our gross income is, and has been, qualifying income, because we are engaged primarily in the transportation of natural gas liquids, refined petroleum products, natural gas and carbon dioxide through pipelines and the handling and storage of coal. If we were classified as an association taxable as a corporation for federal income tax purposes, we would be required to pay tax on our income at corporate rates, distributions to our unitholders would generally be taxed as corporate distributions, and no income, gain, loss, deduction or credit would flow through to our unitholders. Because tax would be imposed upon us as an entity, the cash available for distribution to our unitholders would be substantially reduced. Our being treated as an association taxable as a corporation or otherwise as a taxable entity would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders. There can be no assurance that the law will not be changed so as to cause us to be treated as an association taxable as a corporation for federal income tax purposes or otherwise to be subject to entity-level taxation. Our partnership agreement provides that, if a law is enacted that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal income tax purposes, certain provisions of our partnership agreement relating to our general partner's incentive distributions will be subject to change, including a decrease in the amount of the target distribution levels to reflect the impact of entity level taxation on us. See "Description of the Partnership Agreement -- Cash Distribution Policy -- Adjustment of Target Distribution Levels" in this Report. PASSIVE ACTIVITY LOSS LIMITATIONS Under the passive loss limitations, losses generated by us, if any, will only be available to offset future income generated by us and cannot be used to offset income which an individual, estate, trust or personal service corporation realizes from other activities, including passive activities or investments. Income which may not be offset by passive activity losses, includes not only salary and active business income, but also portfolio income such as interest, dividends or royalties or gain from the sale of property that produces portfolio income. Credits from passive activities are also limited to the tax attributable to any income from passive activities. The passive activity loss rules are applied after other applicable limitations on deductions, such as the at-risk rules and the basis limitation. Certain closely held corporations are subject to slightly different rules, which can also limit their ability to offset passive losses against certain types of income. A unitholder's proportionate share of unused losses may be deducted when the unitholder disposes of all of such holder's units in a fully taxable transaction with an unrelated party. Net passive income from us may be offset by a unitholder's unused losses from us carried over from prior years, but not by losses from other passive activities, including losses from other publicly traded partnerships. In addition, a unitholder's proportionate share of our portfolio income, including portfolio income arising from the investment of our working capital, is not treated as income from a passive activity and may not be offset by such unitholder's share of net losses from us. SECTION 754 ELECTION We and our operating partnerships have made, will make for each taxable year, as necessary, and will maintain the election provided for by Section 754 of the Code, which will generally permit a unitholder to calculate cost 32 33 recovery and depreciation deductions by reference to the portion of the unitholder's purchase price attributable to each of our assets. For tax purposes, transfers of more than 50% of unitholders' interests in capital and profits during any 12-month period will result in a constructive termination of us. A constructive termination of the partnership could result in penalties and a loss of basis adjustments under Section 754, if we were unable to determine that a termination had occurred during any year and, therefore, did not make a Section 754 election for the new partnership's initial tax year. NO AMORTIZATION OF BOOK-UP ATTRIBUTABLE TO INTANGIBLES Our acquisition of our Pacific operations resulted in a restatement of the capital accounts of both the former Santa Fe common unitholders and our pre-acquisition unitholders to fair market value. An allocation of such increased capital account value among our assets was based on values indicated by an independent appraisal obtained by our general partner. The independent appraisal indicated that all of such value was attributable to tangible assets. However, if such allocations are challenged by the Internal Revenue Service and such challenge is successful, a portion of such allocations could be re-allocated to intangible assets that would not be amortizable either for tax or capital account purposes, and therefore, would not support a curative allocation of income. This could result in a disproportionate allocation of taxable income to either a pre-acquisition unitholder or a former Santa Fe common unitholder. DEDUCTIBILITY OF INTEREST EXPENSE The Code generally provides that investment interest expense is deductible only to the extent of a non-corporate taxpayer's net investment income. In general, net investment income for purposes of this limitation includes gross income from property held for investment (except for net capital gains taxed at the long-term capital gains rate) and portfolio income (determined pursuant to the passive loss rules) reduced by certain expenses (other than interest) which are directly connected with the production of such income. Property subject to the passive loss rules is not treated as property held for investment. However, the IRS has issued a notice which provides that net income from a publicly traded partnership (not otherwise treated as a corporation) may be included in net investment income for the purposes of the limitation on the deductibility of investment interest. A unitholder's investment income attributable to its interest in us will include both its allocable share of our portfolio income and trade or business income. A unitholder's investment interest expense will include its allocable share of our interest expense attributable to portfolio investments. TAX LIABILITY EXCEEDING CASH DISTRIBUTIONS OR PROCEEDS FROM DISPOSITIONS OF UNITS A unitholder will be required to pay federal income tax and, in certain cases, state and local income taxes on such unitholder's allocable share of our income, whether or not such unitholder receives cash distributions from us. No assurance is given that unitholders will receive cash distributions equal to their allocable share of taxable income from the Partnership. Further, a unitholder may incur tax liability in excess of the amount of cash received. TAX SHELTER REGISTRATION; POTENTIAL IRS AUDIT We are registered with the IRS as a tax shelter. No assurance can be given that the IRS will not audit us or that tax adjustments will not be made. The rights of a unitholder owning less than a 1% profits interest in us to participate in the income tax audit process have been substantially reduced by our partnership agreement. Further, any adjustments in our returns will lead to adjustments in a unitholder's returns and may lead to audits of such unitholder's returns and adjustments of items unrelated to us. Each unitholder would bear the cost of any expenses incurred in connection with an examination of the personal tax return of such unitholder. UNRELATED BUSINESS TAXABLE INCOME Certain entities otherwise exempt from federal income taxes (such as individual retirement accounts, pension plans and charitable organizations) are nevertheless subject to federal income tax on net unrelated business taxable income and each such entity must file a tax return for each year in which it has more than $1,000 of gross income from unrelated business activities. Our general partner believes that substantially all of our gross income will be treated as derived from an unrelated trade or business and taxable to such entities. The tax-exempt entity's share of our deductions directly connected with carrying on such unrelated trade or business is allowed in computing the 33 34 entity's taxable unrelated business income. ACCORDINGLY, INVESTMENT IN US BY TAX-EXEMPT ENTITIES SUCH AS INDIVIDUAL RETIREMENT ACCOUNTS, PENSION PLANS AND CHARITABLE TRUSTS MAY NOT BE ADVISABLE. STATE AND LOCAL TAX TREATMENT Each unitholder may be subject to income, estate or inheritance taxes in states and localities in which we own property or do business, as well as in such unitholder's own state or locality. For purposes of state and local tax reporting, as of December 31, 2000, partners may have to report income in 25 states: Arizona, California, Colorado, Illinois, Indiana, Iowa, Kansas, Kentucky, Louisiana, Maryland, Michigan, Minnesota, Missouri, Nebraska, Nevada, New Mexico, North Carolina, Ohio, Oklahoma, Oregon, Pennsylvania, South Carolina, Texas, Virginia and Wyoming. A unitholder will likely be required to file state income tax returns and to pay applicable state income taxes in many of these states and may be subject to penalties for failure to comply with such requirements. Some of the states have proposed that we withhold a percentage of income attributable to our operations within the state for unitholders who are non-residents of the state. In the event that such states require that we withhold amounts (which may be greater or less than a particular unitholder's income tax liability to the state), such withholding would generally not relieve the non-resident unitholder from the obligation to file a state income tax return. DESCRIPTION OF THE PARTNERSHIP AGREEMENT The following paragraphs summarize provisions of our partnership agreement. A copy of our partnership agreement is filed as an exhibit to this report. Unless otherwise specifically described, references herein to our partnership agreement constitute references herein to our partnership agreement and those of our operating partnerships, collectively. The following discussion is qualified in its entirety by reference to our partnership agreement. With regard to allocations of taxable income and taxable loss, See "Tax Treatment of Publicly Traded Partnerships Under the Internal Revenue Code." ORGANIZATION AND DURATION Except for Kinder Morgan CO2 Company, L.P., which is a Texas limited partnership, we and each of our operating partnerships are Delaware limited partnerships. Unless liquidated or dissolved at an earlier time, under the terms of our partnership agreement, we and each of our operating partnerships will dissolve on December 31, 2082. PURPOSE Our purpose under our partnership agreement is to serve as the limited partner in our operating partnerships and to conduct any other business that may be lawfully conducted by a Delaware limited partnership. LIMITED PARTNER UNITS We currently have two classes of limited partner interests: common units and Class B units. Our common units are publicly traded on the New York Stock Exchange. Our Class B units are similar to our common units except that our Class B units are not eligible for trading on the New York Stock Exchange. The holders of our Class B units have the same rights as our common unitholders with respect to, without limitation, distributions from us, voting rights and allocations of income, gain, loss or deductions. All of the outstanding Class B units were issued to KMI in connection with KMI's transfer to us of certain Natural Gas Pipeline assets effective December 31, 2000. The Class B units are convertible into common units after such time as the New York Stock Exchange has advised us that the common units issuable upon such conversion are eligible for listing on the NYSE. At any time after December 21, 2001, the holders of a majority of our Class B units may notify us of their desire to convert their Class B units into our common units. If at such time the common units issuable upon conversion of the Class B units would not be eligible for listing on the NYSE, we must use our reasonable efforts to meet any unfulfilled requirements for such listing within 120 days after receipt of such notice. If we are unable to satisfy all of the requirements of the NYSE for listing of such common units within the 120 days, then our Class B unitholders may at any time thereafter require that we redeem their Class B units for cash by delivering a notice of redemption to us. KMI has represented that it will not demand cash redemption for the Class B units. 34 35 POWER OF ATTORNEY Each limited partner, and each person who acquires a unit from a prior unitholder and executes and delivers a transfer application with respect to such unit, grants to our general partner and, if a liquidator has been appointed, the liquidator, a power of attorney to, among other things: o execute and file certain documents required in connection with our qualification, continuance or dissolution or the amendment of our partnership agreement in accordance with its terms; and o make consents and waivers contained in our partnership agreement. RESTRICTIONS ON AUTHORITY OF OUR GENERAL PARTNER Our general partner's authority is limited in certain respects under our partnership agreement. Our general partner is prohibited, without the prior approval of holders of record of a majority of the outstanding units from, among other things, selling or exchanging all or substantially all of our assets in a single transaction or a series of related transactions (including by way of merger, consolidation or other combination) or approving on our behalf the sale, exchange or other disposition of all or substantially all of our assets. However, our general partner may mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without such approval. Our general partner may also sell all or substantially all of our assets pursuant to a foreclosure or other realization upon the foregoing encumbrances without such approval. Except as provided in our partnership agreement and generally described under "--Amendment of Partnership Agreement and Other Agreements," any amendment to a provision of our partnership agreement generally will require the approval of the holders of at least 66 2/3% of our outstanding units. Our general partner's ability to sell or otherwise dispose of a significant portion of our assets is restricted by the terms of our credit facilities. In general, our general partner may not take any action, or refuse to take any reasonable action, the effect of which would be to cause us to be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes, unless it has obtained the consent of holders of record of a majority of our outstanding units (other than units owned by our general partner and its affiliates). WITHDRAWAL OR REMOVAL OF OUR GENERAL PARTNER Our general partner has agreed not to voluntarily withdraw as our general partner prior to January 1, 2003 (with limited exceptions described below) without obtaining the approval of at least a majority of our outstanding units (excluding for purposes of such determination units held by the general partner and its affiliates) and furnishing an opinion of counsel that such withdrawal will not cause us to be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes or result in the loss of the limited liability of any limited partner. On or after January 1, 2003, our general partner may withdraw as our general partner by giving 90 days' written notice (without first obtaining approval from the unitholders), and such withdrawal will not constitute a breach of our partnership agreement. If an opinion of counsel cannot be obtained to the effect that (following the selection of a successor) our general partner's withdrawal would not result in the loss of limited liability of the holders of units or cause us to be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes, we will be dissolved after such withdrawal. Notwithstanding the foregoing, our general partner may withdraw prior to January 1, 2003 without approval of the unitholders upon 90 days' notice to our limited partners if more than 50% of our outstanding units (other than those held by the withdrawing general partner and its affiliates) are held or controlled by one person and its affiliates. In addition, our partnership agreement does not restrict KMI's ability to sell directly or indirectly, all or any portion of the capital stock of our general partner to a third party without the approval of the holders of units. Our general partner may not be removed unless such removal is approved by the vote of the holders of not less than 66 2/3% of our outstanding units (excluding units held by our general partner and its affiliates) provided that certain other conditions are satisfied. Any such removal is subject to the approval of our successor general partner by the same vote and receipt of an opinion of counsel that such removal and the approval of a successor will not result in the loss of limited liability of any limited partner or cause us to be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes. 35 36 In the event our general partner withdraws and such withdrawal violates our partnership agreement or our limited partners remove the general partner for cause, a successor general partner will have the option to acquire the general partner interest of the departing general partner for a cash payment equal to the fair market value of such interest. Under all other circumstances where our general partner withdraws or is removed by our limited partners, the departing general partner will have the option to require the successor general partner to acquire such departing general partner's interest for such amount. In each case such fair market value will be determined by agreement between the departing general partner and the successor general partner, or if no agreement is reached, by an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner (or if no expert can be agreed upon, by the expert chosen by agreement of the expert selected by each of them). In addition, we would also be required to reimburse the departing general partner for all amounts due to the departing general partner, including without limitation all employee related liabilities, including severance liabilities, incurred in connection with the termination of the employees employed by the departing general partner for our benefit. If the above-described option is not exercised by either the departing general partner or the successor general partner, as applicable, the departing general partner's interest in us will be converted into common units equal to the fair market value of such departing general partner's interest as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph. Our general partner may transfer all, but not less than all, of its general partner interest in us, without the approval of our limited partners, to one of its affiliates, or upon its merger or consolidation into another entity or the transfer of all or substantially all of its assets to another entity, provided in either case that such entity assumes the rights and duties of our general partner, agrees to be bound by the provisions of our partnership agreement and furnishes an opinion of counsel that such transfer would not result in the loss of the limited liability of any limited partner or cause us to be treated as an association taxable as a corporation or otherwise cause us to be subject to entity level taxation for federal income tax purposes. In the case of any other transfer of our general partner's interest in us, in addition to the foregoing requirements, the approval of at least a majority of the units is required, excluding for such purposes those units held by our general partner and its affiliates. Upon the withdrawal or removal of our general partner, we will be dissolved, wound up and liquidated, unless such withdrawal or removal takes place following the approval of a successor general partner or unless within 180 days after such withdrawal or removal a majority of the holders of units agrees in writing to continue our business and appoint a successor general partner. See "-Termination and Dissolution." ANTI-TAKEOVER AND RESTRICTED VOTING RIGHT PROVISIONS Our partnership agreement contains certain provisions that are intended to discourage a person or group from attempting to remove our general partner or otherwise change our management. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of the units, such person or group loses any and all voting rights with respect to all of the units beneficially owned or held by such person. TRANSFER OF UNITS; STATUS AS LIMITED PARTNER OR ASSIGNEE Until a unit has been transferred on our books, we and our transfer agent, notwithstanding any notice to the contrary, may treat the record holder thereof as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulation. Any transfers of a unit will not be recorded by our transfer agent or recognized by us unless the transferee executes and delivers a transfer application (set forth on the reverse side of the certificate representing units). By executing and delivering the transfer application, the transferee of units: o becomes the record holder of such units and shall constitute an assignee until admitted to us as a substituted limited partner; o automatically requests admission as a substituted limited partner; o agrees to be bound by the terms and conditions of and is deemed to have executed our partnership agreement; o represents that such transferee has the capacity, power and authority to enter into our partnership agreement; 36 37 o grants powers of attorney to our general partner and any liquidator of ours as specified in our partnership agreement; and o makes the consents and waivers contained in our partnership agreement. An assignee, pending its admission as a substituted limited partner, is entitled to an interest in us equivalent to that of a limited partner with respect to the right to share in allocations and distributions from us, including liquidating distributions. Our general partner will vote, and exercise other powers attributable to, units owned by an assignee that has not become a substituted limited partner at the written direction of such assignee. See "-Meetings; Voting." An assignee will become a substituted limited partner in respect of the transferred units upon our general partner's consent and the recordation of the name of the assignee in our books and records. Our general partner's consent may be withheld in its sole discretion. Units are securities and are transferable according to the laws governing transfers of securities. In addition to other rights acquired upon transfer, a transferor gives a transferee the right to request admission as a substituted limited partner in respect of the transferred units. A purchaser or transferee of a unit who does not execute and deliver a transfer application obtains only: o the right to transfer the units to a purchaser or other transferee; and o the right to transfer the right to seek admission as a substituted limited partner with respect to the transferred units. Thus, a purchaser or transferee of units who does not execute and deliver a transfer application will not receive cash distributions unless the units are held in a nominee or street name account and the nominee or broker has executed and delivered a transfer application with respect to such units and may not receive certain federal income tax information or reports furnished to record holders of units. The transferor of units will have a duty to provide such transferee with all information that may be necessary to obtain registration of the transfer of the units, but the transferee agrees, by acceptance of the certificate representing units, that the transferor will not have a duty to see to the execution of the transfer application by the transferee and will have no liability or responsibility if such transferee neglects or chooses not to execute and forward the transfer application. Unitholders may hold their units in nominee accounts, provided that the broker (or other nominee) executes and delivers a transfer application. We will be entitled to treat the nominee holder of a unit as the absolute owner thereof, and the beneficial owner's rights will be limited solely to those that it has against the nominee holder as a result of or by reason of any understanding or agreement between such beneficial owner and nominee holder. NON-CITIZEN ASSIGNEES; REDEMPTION If we are or become subject to federal, state or local laws or regulations that, in the reasonable determination of our general partner, provide for the cancellation or forfeiture of any property in which we have an interest because of the nationality, citizenship or other related status of any limited partner or assignee, we may redeem the units held by such limited partner or assignee at their average fair market price. In order to avoid any such cancellation or forfeiture, our general partner may require each record holder or assignee to furnish information about such unitholder's nationality, citizenship, residency or related status. If the record holder fails to furnish such information within 30 days after a request for such information, or if our general partner determines on the basis of the information furnished by such holder in response to the request that the cancellation or forfeiture of any property in which we have an interest may occur, our general partner may be substituted as the limited partner for such record holder, who will then be treated as a non-citizen assignee, and our general partner will have the right to redeem the units held by such record holder as described above. Our partnership agreement sets forth the rights of such record holder or assignee upon redemption. Pending such redemption or in lieu thereof, our general partner may change the status of any such limited partner or assignee to that of a non-citizen assignee. Further, a non-citizen assignee (unlike an assignee who is not a substituted limited partner) does not have the right to direct the vote regarding such non-citizen assignee's units and may not receive distributions in kind upon our liquidation. See "-Transfer of Units; Status as Limited Partner or Assignee." 37 38 As used in this Report: o "average fair market price" means, with respect to a limited partner interest as of any date, the average of the daily end of day price (as hereinafter defined) for the 20 consecutive unit transaction days (as hereinafter defined) immediately prior to such date; o "end of day price" means for any day the last sale price on such day, regular way, or in case no such sale takes place on such day, the average of the closing bid and asked prices on such day, regular way, in either case as reported in the principal consolidated transaction reporting system with respect to securities listed or admitted to trading on the principal national securities exchange on which our limited partner interests of such class are listed or admitted to trading or, if our limited partner interests of such class are not listed or admitted to trading on any national securities exchange, the last quoted sale price on such day, or, if not so quoted, the average of the high bid and low asked prices on such day in the over-the-counter market, as reported by the NASDAQ or such other system then in use, or if on any such day our limited partner interests of such class are not quoted by any such organization, the average of the closing bid and asked prices on such day as furnished by a professional market maker making a market in our limited partner interests of such class selected by the board of directors of our general partner, or if on any such day no market maker is making a market in such limited partner interests, the fair value of such limited partner interests on such day as determined reasonably and in good faith by the board of directors of our general partner; and o "unit transaction day" means a day on which the principal national securities exchange on which such limited partner interests are listed or admitted to trading is open for the transaction of business or, if our limited partner interests of such class are not listed or admitted to trading on any national securities exchange, a day on which banking institutions in New York City generally are open. ISSUANCE OF ADDITIONAL SECURITIES The Partnership's Issuance of Securities. Our partnership agreement does not restrict the ability of our general partner to issue additional limited or general partner interests and authorizes our general partner to cause us to issue additional securities for such consideration and on such terms and conditions as shall be established by our general partner in its sole discretion without the approval of any limited partners. In accordance with Delaware law and the provisions of our partnership agreement, our general partner may issue additional partnership interests, which, in its sole discretion, may have special voting rights to which the units are not entitled. Limited Pre-emptive Right of Our General Partner. Our general partner has the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase from us units or other of our equity securities whenever, and on the same terms that, we issue such securities to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of our general partner and its affiliates in the Partnership to that which existed immediately prior to each such issuance. LIMITED CALL RIGHT If at any time our general partner and its affiliates hold 80% or more of any class of our units, our general partner will have the right, which it may assign and transfer to any of its affiliates or to us, to purchase all of our remaining units of that class as of a record date to be selected by the general partner, on at least 10 but not more than 60 days' notice. The purchase price in the event of such purchase shall be the greater of: o the average fair market price of limited partner interests of such class as of the date five days prior to the mailing of written notice of our general partner's election to purchase limited partner interests of such class; and o the highest cash price paid by our general partner or any of its affiliates for any units of that class purchased within the 90 days preceding the date our general partner mails notice of its election to purchase such units. AMENDMENT OF OUR PARTNERSHIP AGREEMENT AND OTHER AGREEMENTS Amendments to our partnership agreement may be proposed only by or with the consent of our general partner. In order to adopt a proposed amendment, our general partner is required to seek written approval of the holders of the number of units required to approve such amendment or call a meeting of our limited partners to consider and 38 39 vote upon the proposed amendment, except as described below. Proposed amendments (other than those described below) must be approved by holders of at least 66 2/3% of the outstanding units, except that no amendment may be made which would: o enlarge the obligations of any limited partner, without its consent; o enlarge the obligations of our general partner, without its consent, which may be given or withheld in its sole discretion; o restrict in any way any action by or rights of our general partner as set forth in our partnership agreement; o modify the amounts distributable, reimbursable or otherwise payable by us to our general partner; o change the term of the Partnership; or o give any person the right to dissolve us other than our general partner's right to dissolve us with the approval of a majority of the outstanding units or change such right of our general partner in any way. Our general partner may make amendments to our partnership agreement without the approval of any limited partner or assignee to reflect: o a change in our name, the location of our principal place of business, our registered agent or our registered office; o admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement; o a change that, in our general partner's sole discretion, is reasonable and necessary or appropriate to qualify or continue our qualification as a partnership in which our limited partners have limited liability or that is necessary or advisable in our general partner's opinion to ensure that we will not be treated as an association taxable as a corporation or otherwise subject to taxation as an entity for federal income tax purposes; o an amendment that is necessary, in the opinion of counsel, to prevent us or our general partner or our or their respective directors or officers from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or "plan asset" regulations adopted under the Employee Retirement Income Security Act of 1974, whether or not substantially similar to plan asset regulations currently applied or proposed by the United States Department of Labor; o an amendment that in our general partner's sole discretion is necessary or desirable in connection with the authorization of additional limited or general partner interests; o any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone; o an amendment effected, necessitated or contemplated by a merger agreement that has been approved pursuant to the terms of our partnership agreement; and o any other amendments substantially similar to the foregoing. In addition, our general partner may make amendments to our partnership agreement without such consent if the amendments: o do not adversely affect our limited partners in any material respect; o are necessary or desirable to satisfy any requirements, conditions or guidelines contained in any opinion, directive, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute; o are necessary or desirable to facilitate the trading of our units or to comply with any rule, regulation, guideline or requirement of any securities exchange on which our units are or will be listed for trading, compliance with any of which our general partner deems to be in our best interests and the holders of our units; or o are required to effect the intent of, or as contemplated by, our partnership agreement. Our general partner will not be required to obtain an opinion of counsel as to the tax consequences or the possible effect on limited liability of amendments described in the two immediately preceding paragraphs. No other amendments to our partnership agreement will become effective without the approval of at least 95% of the units unless we obtain an opinion of counsel to the effect that such amendment: 39 40 o will not cause us to be treated as an association taxable as a corporation or otherwise cause us to be subject to entity level taxation for federal income tax purposes; and o will not affect the limited liability of any of our limited partners or the limited partner of our operating partnerships. Any amendment that materially and adversely affects the rights or preferences of any type or class of limited partner interests in relation to other types or classes of limited partner interests or our general partner's interests will require the approval of at least 66 2/3% of the type or class of limited partner interests so affected. MANAGEMENT Our general partner will manage and operate our activities, and our general partner's activities will be limited to such management and operation. Holders of units will not direct or participate in our or any of our operating partnerships, management or operations. See "--Limited Liability." Our general partner owes a fiduciary duty to our unitholders. Notwithstanding any limitation on obligations or duties, our general partner will be liable, as our general partner, for all of our debts (to the extent we do not pay them), except to the extent that indebtedness we incur is made specifically non-recourse to our general partner. We do not currently have any directors, officers or employees. As is commonly the case with publicly traded limited partnerships, we do not currently contemplate that we will directly employ any of the persons responsible for managing or operating our business or for providing it with services, but will instead reimburse our general partner or its affiliates for the services of such persons. See "-Reimbursement of Expenses." Reimbursement of Expenses. Our general partner will receive no management fee or similar compensation in conjunction with its management of us (other than cash distributions). See "--Cash Distribution Policy." However, our general partner is entitled pursuant to our partnership agreement to reimbursement on a monthly basis, or such other basis as our general partner may determine in its sole discretion, for all direct and indirect expenses it incurs or payments it makes on our behalf and all other necessary or appropriate expenses allocable to us or otherwise reasonably incurred by our general partner in connection with operating our business. Our partnership agreement provides that our general partner shall determine the fees and expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion. The reimbursement for such costs and expenses will be in addition to any reimbursement to our general partner and its affiliates as a result of the indemnification provisions of our partnership agreement. See "-Indemnification." Indemnification. Our partnership agreement provides that we will indemnify our general partner, any departing general partner and any person who is or was an officer or director of our general partner or any departing general partner, to the fullest extent permitted by law, and may indemnify, to the extent deemed advisable by our general partner, to the fullest extent permitted by law, any person who is or was an affiliate of our general partner or any departing general partner, any person who is or was an officer, director, employee, partner, agent or trustee of our general partner, any departing general partner or any such affiliate, or any person who is or was serving at the request of our general partner or any affiliate of our general partner or any departing general partner as an officer, director, employee, partner, agent, or trustee of another person from and against any and all losses, claims, damages, liabilities (joint or several), expenses (including, without limitation, legal fees and expenses), judgments, fines, penalties, interest, settlement and other amounts arising from any and all claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, in which any indemnified person may be involved, or is threatened to be involved, as a party or otherwise, by reason of its status as: o our general partner, a departing general partner or affiliate of either; o an officer, director, employee, partner, agent or trustee of the general partner, any departing general partner or affiliate of either; or o a person serving at our request in another entity in a similar capacity. In each case the indemnified persons must have acted in good faith and in a manner which such indemnified persons believed to be in or not opposed to our best interests and, with respect to any criminal proceeding, had no reasonable cause to believe its conduct was unlawful. Any indemnification under our partnership agreement will only be paid out of our assets, and our general partner will not be personally liable for, or have any obligation to contribute or loan funds or assets to us to enable us to effectuate, such indemnification. We are authorized to 40 41 purchase (or to reimburse our general partner or its affiliates for the cost of) insurance, purchased on behalf of our general partner and such other persons as our general partner determines, against liabilities asserted against and expenses incurred by such persons in connection with our activities, whether or not we would have the power to indemnify such person against such liabilities under the provisions described above. Conflicts and Audit Committee. One or more of our general partner's directors who are neither officers nor employees of our general partner or any of its affiliates will serve as a committee of our general partner's board of directors and will, at the request of our general partner, review specific matters as to which our general partner believes there may be a conflict of interest in order to determine if the resolution of such conflict proposed by our general partner is fair and reasonable to us. This conflicts and audit committee will only review matters at the request of our general partner, which has sole discretion to determine which matters to submit to such committee. Any matters approved by this conflicts and audit committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our general partner of our partnership agreement or any duties it may owe to us. Additionally, it is possible that such procedure in itself may constitute a conflict of interest. MEETINGS; VOTING Holders of units or assignees who are record holders of units on the record date set pursuant to our partnership agreement will be entitled to notice of, and to vote at, meetings of our limited partners and to act with respect to matters as to which approvals may be solicited. With respect to voting rights attributable to units that are owned by assignees who have not yet been admitted as limited partners, our general partner will be deemed to be the limited partner with respect thereto and will, in exercising the voting rights in respect of such units on any matter, vote such units at the written direction of the record holders thereof. If a proxy is not returned on behalf of the unit record holder, such record holder's units will not be voted (except that, in the case of units held by our general partner on behalf of non-citizen assignees, our general partner will vote the votes in respect of such units in the same ratios as the votes of limited partners in respect of other units are cast). When a proxy is returned properly executed, the units represented thereby will be voted in accordance with the indicated instructions. If no instructions have been specified on the properly executed and returned proxy, the units represented thereby will be voted "FOR" the approval of the matters to be presented. Units held by our general partner on behalf of non-citizen assignees shall be voted by our general partner in the same ratios as the votes of our limited partners with respect to the matter presented to the holders of units. Any action that our limited partners are required or permitted to be taken may be taken either at a meeting of our limited partners or without a meeting if consents in writing setting forth the action so taken are signed by holders of such number of limited partner interests as would be necessary to authorize or take such action at a meeting of our limited partners. Meetings of our limited partners may be called by our general partner or by limited partners owning at least 20% of the outstanding units of the class for which a meeting is proposed. Our limited partners may vote either in person or by proxy at meetings. Two-thirds (or a majority, if that is the vote required to take action at the meeting in question) of the outstanding limited partner interests of the class for which a meeting is to be held (excluding, if such are excluded from such vote, limited partner interests held by the general partner and its affiliates) represented in person or by proxy will constitute a quorum at a meeting of our limited partners. Except for any proposal for removal of our general partner or certain amendments to our partnership agreement described above, substantially all matters submitted for a vote are determined by the affirmative vote, in person or by proxy, of holders of a majority of our outstanding limited partner interests. Each record holder of a unit has a vote according to such record holder's percentage interest in us, although our general partner could issue additional limited partner interests having special voting rights. See "--Issuance of Additional Securities." However, units owned beneficially by any person or group (other than our general partner and its affiliates) that own beneficially 20% or more of all units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of limited partners, calculating required votes, determining the presence of a quorum or for other similar partnership purposes. Our partnership agreement provides that the broker (or other nominee) will vote units held in nominee or street name accounts pursuant to the instruction of the beneficial owner thereof, unless the arrangement between the beneficial owner and such holder's nominee provides otherwise. 41 42 Any notice, demand, request, report or proxy materials required or permitted to be given or made to record holders of units (whether or not such record holder has been admitted as a limited partner) under the terms of our partnership agreement will be delivered to the record holder by us or, at our request, by the transfer agent. LIMITED LIABILITY Except as described below, units are fully paid, and holders of units will not be required to make additional contributions to us. Assuming that a limited partner does not participate in the control of our business, within the meaning of the Delaware limited partnership act, and that such partner otherwise acts in conformity with the provisions of our partnership agreement, such partner's liability under Delaware law will be limited, subject to certain possible exceptions, generally to the amount of capital such partner is obligated to contribute to us in respect of such holder's units plus such holder's share of any of our undistributed profits and assets. However, if it were determined that the right or exercise of the right by our limited partners as a group to remove or replace our general partner, to approve certain amendments to our partnership agreement or to take other action pursuant to our partnership agreement constituted "participation in the control" of our business for the purposes of the Delaware limited partnership act, then our limited partners could be held personally liable for our obligations under the laws of the State of Delaware to the same extent as our general partner. Under Delaware law, a limited partnership may not make a distribution to a partner to the extent that at the time of the distribution, after giving effect to the distribution, all liabilities of the partnership, other than liabilities to partners on account of their partnership interests and nonrecourse liabilities, exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, Delaware law provides that the fair value of property subject to nonrecourse liability shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds that nonrecourse liability. Delaware law provides that a limited partner who receives such a distribution and knew at the time of the distribution that the distribution was in violation of Delaware law shall be liable to the limited partnership for the amount of the distribution for three years from the date of the distribution. Under Delaware law, an assignee who becomes a substituted limited partner of a limited partnership is liable for the obligations of the assignor to make contributions to us, except the assignee is not obligated for liabilities unknown to such assignee at the time the assignee became a limited partner and which could not be ascertained from our partnership agreement. We are organized under the laws of Delaware and currently conduct business in a number of states. Maintaining limited liability will require that we comply with legal requirements in all of the jurisdictions in which we conduct business, including qualifying the operating partnerships to do business therein. Limitations on the liability of limited partners for the obligations of a limited partnership have not been clearly established in many jurisdictions. If it were determined that we were, by virtue of our limited partner interest in our operating partnerships or otherwise, conducting business in any state without complying with the applicable limited partnership statute, or that the right or exercise of the right by our limited partners as a group to remove or replace our general partner, to approve certain amendments to our partnership agreement, or to take other action pursuant to our partnership agreement constituted "participation in the control" of our business for the purposes of the statues of any relevant jurisdiction, then our limited partners could be held personally liable for our obligations under the law of such jurisdiction to the same extent as our general partner. We will operate in such manner as our general partner deems reasonable and necessary or appropriate to preserve the limited liability of holders of units. BOOKS AND REPORTS Our general partner is required to keep appropriate books of the business at our principal offices. Our books will be maintained for both tax and financial reporting purposes on an accrual basis. Our fiscal is the calendar year. As soon as practicable, but in no event later than 120 days after the close of each fiscal year, our general partner will furnish each record holder of a unit (as of a record date selected by our general partner) with an annual report containing audited financial statements for the past fiscal year, prepared in accordance with generally accepted accounting principles. As soon as practicable, but in no event later than 90 days after the close of each calendar 42 43 quarter (except the fourth quarter), our general partner will furnish each record holder of a unit upon request a report containing our unaudited financial statements and such other information as may be required by law. Our general partner will use all reasonable efforts to furnish each record holder of a unit information reasonably required for tax reporting purposes within 90 days after the close of each taxable year. Such information is expected to be furnished in a summary form so that certain complex calculations normally required of partners can be avoided. Our general partner's ability to furnish such summary information to holders of units will depend on the cooperation of such holders of units in supplying certain information to our general partner. Every holder of a unit (without regard to whether such holder supplies such information to our general partner) will receive information to assist in determining such holder's federal and state tax liability and filing such holder's federal and state income tax returns. RIGHT TO INSPECT PARTNERSHIP BOOKS AND RECORDS Our partnership agreement provides that a limited partner can, for a purpose reasonably related to such limited partner's interest as a limited partner, upon reasonable demand and at such partner's own expense, have furnished to him: o a current list of the name and last known address of each partner; o a copy of our tax returns; o information as to the amount of cash, and a description and statement of the agreed value of any other property or services contributed or to be contributed by each partner and the date on which each became a partner; o copies of our partnership agreement, our certificate of limited partnership, amendments thereto and powers of attorney pursuant to which the same have been executed; o information regarding the status of our business and financial condition; and o such other information regarding our affairs as is just and reasonable. Our general partner may, and intends to, keep confidential from our limited partners trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests or which we are required by law or by agreements with third parties to keep confidential. TERMINATION AND DISSOLUTION We will continue until December 31, 2082, unless sooner terminated pursuant to our partnership agreement. We will be dissolved upon: 1. our general partner's election to dissolve us, if approved by a majority of the units; 2. our sale of all or substantially all of our assets and properties and our operating partnerships; 3. the bankruptcy or dissolution of our general partner; or 4. the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner (other than by reason of a transfer in accordance with the partnership agreement or withdrawal or removal following approval of a successor). However, we will not be dissolved upon an event described in clause 4 if within 90 days after such event our partners agree in writing to continue our business and to the appointment, effective as of the date of such event, of a successor general partner. Upon a dissolution pursuant to clause 3 or 4, at least a majority of the units may also elect, within certain time limitations, to reconstitute us and continue our business on the same terms and conditions set forth in our partnership agreement by forming a new limited partnership on terms identical to those set forth in our partnership agreement and having as a general partner an entity approved by at least a majority of the units, subject to our receipt of an opinion of counsel that the exercise of such right will not result in our unitholders' loss of limited liability or cause us or the reconstituted limited partnership to be treated as an association taxable as a corporation or otherwise subject to taxation as an entity for federal income tax purposes. 43 44 REGISTRATION RIGHTS Pursuant to the terms of our partnership agreement and subject to certain limitations described therein, we have agreed to register for resale under the Securities Act of 1933 and applicable state securities laws any units (or other securities of the Partnership) proposed to be sold by our general partner (or its affiliates) if an exemption from such registration requirements is not otherwise available for such proposed transaction. We are obligated to pay all expenses incidental to such registration, excluding underwriting discounts and commissions. CASH DISTRIBUTION POLICY One of our principal objectives is to generate cash from our operations and to distribute available cash to our partners in the manner described herein. "Available cash" generally means, with respect to any calendar quarter, all cash received by us from all sources, less all of our cash disbursements and net additions to reserves. For purposes of cash distributions to our unitholders, the term available cash excludes the amount paid in respect of the 0.5% special limited partner interest in SFPP, L.P. owned by the former general partner of SFPP, which amount will equal 0.5% of the total cash distributions made each quarter by SFPP to its partners. Our general partner's decisions regarding amounts to be placed in or released from reserves may have a direct impact on the amount of available cash. This is because increases and decreases in reserves are taken into account in computing available cash. Our general partner may, in its reasonable discretion (subject to certain limits), determine the amounts to be placed in or released from reserves each quarter. Cash distributions will be characterized as either distributions of cash from operations or cash from interim capital transactions. This distinction affects the amounts distributed to unitholders relative to our general partner. See "--Quarterly Distributions of Available Cash-Distributions of Cash from Operations" and "-Quarterly Distributions of Available Cash-Distributions of Cash from Interim Capital Transactions." "Cash from operations" generally refers to our cash balance on the date we commenced operations, plus all cash generated by the operations of our business, after deducting related cash expenditures, reserves, debt service and certain other items. "Cash from interim capital transactions" will generally be generated only by borrowings, sales of debt and equity securities and sales or other dispositions of assets for cash (other than inventory, accounts receivable and other current assets and assets disposed of in the ordinary course of business). To avoid the difficulty of trying to determine whether available cash distributed by us is cash from operations or cash from interim capital transactions, all available cash distributed by us from any source will be treated as cash from operations until the sum of all available cash distributed as cash from operations equals the cumulative amount of cash from operations actually generated from the date we commenced operations through the end of the calendar quarter prior to such distribution. Any excess available cash (irrespective of its source) will be deemed to be cash from interim capital transactions and distributed accordingly. If cash from interim capital transactions is distributed in respect of each unit in an aggregate amount per unit equal to $11.00 per unit (the initial public offering price of the units adjusted to give effect to the 2-for-1 split of units effective October 1, 1997) the distinction between cash from operations and cash from interim capital transactions will cease, and both types of available cash will be treated as cash from operations. Our general partner does not anticipate that we will distribute significant amounts of cash from interim capital transactions. The discussion below indicates the percentages of cash distributions required to be made to our general partner and our unitholders. In the following general discussion of how available cash is distributed, references to available cash, unless otherwise stated, mean available cash that constitutes cash from operations. Quarterly Distributions of Available Cash. We will make distributions to our partners with respect to each calendar quarter prior to liquidation in an amount equal to 100% of our available cash for such quarter. Distributions of Cash from Operations. Our distributions of available cash constituting cash from operations with respect to any quarter will be made in the following manner: 44 45 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 $0.3025 per unit in cash for that 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 $0.3575 per unit in cash for that quarter (the "Second Target Distribution"); 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 $0.4675 per unit in cash for that quarter; and fourth, 50% of any available cash then remaining to the owners of all classes of units pro rata, paid in cash to owners of common units and Class B units, and 50% in cash to our general partner. In addition, if the first, second and third target distribution levels are reduced to zero, as described below under "--Quarterly Distributions of Available Cash-Adjustment of Target Distribution Levels," all remaining available cash will be distributed as cash from operations, 50% our unitholders pro rata and 50% to our general partner. These provisions are inapplicable upon our dissolution and liquidation. Distributions of Cash from Interim Capital Transactions. Distributions on any date by us of available cash that constitutes cash from interim capital transactions will be distributed 98% to our unitholders pro rata and 2% to our general partner until we shall have distributed in respect of each unit available cash constituting cash from interim capital transactions in an aggregate amount per unit equal to the adjusted initial unit price of $11.00. As cash from interim capital transaction is distributed, it is treated as if it were a repayment of the initial public offering price. To reflect such repayment, the first, second and third target distribution levels will be adjusted downward by multiplying each amount by a fraction, the numerator of which is the unrecovered initial unit price immediately after giving effect to such repayment and the denominator of which is the unrecovered initial unit price, immediately prior to giving effect to such repayment. "Unrecovered initial unit price" includes the amount by which the initial unit price exceeds the aggregate distribution of cash from interim capital transactions per unit. When "payback of initial unit price" is achieved, i.e., when the unrecovered initial unit price is zero, then in effect the first, second and third target distribution levels each will have been reduced to zero. Thereafter all distributions of available cash from all sources will be treated as if they were cash from operations and available cash will be distributed 50% to our unitholders pro rata and 50% to our general partner. Adjustment of Target Distribution Levels. The first, second and third target distribution levels will be proportionately adjusted upward or downward, as appropriate, in the event of any combination or subdivision of units (whether effected by a distribution payable in units or otherwise) but not by reason of the issuance of additional units for cash or property. For example, in connection with our two-for-one split of the units on October 1, 1997, the first, second and third target distribution levels were each reduced to 50% of their initial levels. See "--Quarterly Distributions of Available Cash-Distributions of Cash from Operations." In addition, if a distribution is made of available cash constituting cash from interim capital transactions, the first, second and third target distribution levels will be adjusted downward proportionately, by multiplying each such amount, as the same may have been previously adjusted, by a fraction, the numerator of which is the unrecovered initial unit price immediately after giving effect to such distribution and the denominator of which is the unrecovered initial unit price immediately prior to such distribution. For example, assuming the unrecovered initial unit price is $11.00 per unit and if cash from interim capital transactions of $5.50 per unit is distributed to our unitholders (assuming no prior adjustments), then the amount of the first, second and third target distribution levels would each be reduced to 50% of their initial levels. If and when the unrecovered initial unit price is zero, the first, second and third target distribution levels each will have been reduced to zero, and our general partner's share of distributions of available cash will increase, in general, to 50% of all distributions of available cash. The first, second and third target distribution levels may also be adjusted if legislation is enacted which causes us to become taxable as a corporation or otherwise subjects us to taxation as an entity for federal income tax 45 46 purposes. In such event, the first, second, and third target distribution levels for each quarter thereafter would be reduced to an amount equal to the product of: o each of the first, second and third target distribution levels multiplied by; o one minus the sum of: o the maximum marginal federal income tax rate to which we are subject as an entity; plus o any increase that results from such legislation in the effective overall state and local income tax rate to which we are subject as an entity for the taxable year in which such quarter occurs (after taking into account the benefit of any deduction allowable for federal income tax purposes with respect to the payment of state and local income taxes). For example, assuming we are not previously subject to state and local income tax, if we were to become taxable as an entity for federal income tax purposes and we became subject to a maximum marginal federal, and effective state and local, income tax rate of 38%, then each of the target distribution levels, would be reduced to 62% of the amount thereof immediately prior to such adjustment. LIQUIDATION AND DISTRIBUTION OF PROCEEDS Upon our dissolution, unless we are reconstituted and continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that such liquidator deems necessary or desirable in its good faith judgment in connection therewith, liquidate our assets and apply the proceeds of the liquidation as follows: o first towards the payment of all our creditors and the creation of a reserve for contingent liabilities; and o then to all partners in accordance with the positive balances in their respective capital accounts. Under certain circumstances and subject to certain limitations, the liquidator may defer liquidation or distribution of our assets for a reasonable period of time and/or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners. Generally, any gain will be allocated between our unitholders and our general partner in a manner that approximates their sharing ratios in the various target distribution levels. Our unitholders and our general partner will share in the remainder of our assets in proportion to their respective partnership capital account balances. Any loss or unrealized loss will be allocated to our general partner and our unitholders: first, in proportion to the positive balances in such partners' capital accounts until all such balances are reduced to zero; and thereafter, to our general partner. TRANSFER AGENT AND REGISTRAR DUTIES First Chicago Trust Company of New York is the registrar and transfer agent for our units and receives a fee from us for serving in such capacities. We will pay fees charged by our transfer agent for transfers of units except: o fees similar to those customarily paid by holders of securities for surety bond premiums to replace lost or stolen certificates; o taxes or other governmental charges; o special charges for services requested by a holder of a unit; and o other similar fees or charges. We will not charge unitholders for disbursements of cash distributions. We will indemnify our transfer agent, its agents and each of their respective shareholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted in respect of its activities as such, except for any liability due to any negligence, gross negligence, bad faith or intentional misconduct of the indemnified person or entity. 46 47 RESIGNATION OR REMOVAL Our transfer agent may at any time resign, by notice to us, or be removed by us, such resignation or removal to become effective upon our general partner's appointment of a successor transfer agent and registrar and such successor's acceptance of such appointment. If no successor has been appointed and accepted such appointment within 30 days after notice of such resignation or removal, our general partner is authorized to act as the transfer agent and registrar until a successor is appointed. ITEM 3. LEGAL PROCEEDINGS See Note 16 of the Notes to the Consolidated Financial Statements included elsewhere in this report. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS There were no matters submitted to a vote of our unitholders during the fourth quarter of 2000. 47 48 PART II ITEM 5. MARKET FOR THE REGISTRANT'S UNITS AND RELATED SECURITY HOLDER MATTERS The following table sets forth, for the periods indicated, the high and low sale prices per common unit, as reported on the New York Stock Exchange, the principal market in which our common units are traded, and the amount of cash distributions declared per common unit.
PRICE RANGE ----------------------- CASH HIGH LOW DISTRIBUTIONS ---------- ---------- ------------- 2000 ---- First Quarter $ 44.5625 $ 38.5000 $ 0.7750 Second Quarter 39.9375 37.1250 0.8500 Third Quarter 47.3750 39.6250 0.8500 Fourth Quarter 56.3125 46.0000 0.9500 1999 ---- First Quarter $ 37.9375 $ 33.1250 $ 0.7000 Second Quarter 39.0000 33.9375 0.7000 Third Quarter 45.3750 37.5000 0.7250 Fourth Quarter 43.9375 39.6250 0.7250
The quarterly distribution for the fourth quarter of 2000 was $.95 per unit. We currently expect that we will continue to pay comparable cash distributions in the future assuming no adverse change in our operations, economic conditions and other factors. However, we can give no assurance that future distributions will continue at such levels. As of February 14, 2001, there were approximately 36,000 beneficial owners of our common units and one holder of our Class B units. Recent Sales of Unregistered Securities. During the quarter ended December 31, 2000, we issued the following equity securities, which were not registered under the Securities Act of 1933, as amended. Effective December 31, 2000, we acquired over $300 million of assets from KMI. As consideration for these assets, we paid to KMI $192.7 million, 640,000 common units and 2,656,700 Class B units. The units were issued to KMI pursuant to Section 4(2) of the Securities Act of 1933. 48 49 ITEM 6. SELECTED FINANCIAL DATA (UNAUDITED) The following table sets forth, for the periods and at the dates indicated, selected historical financial and operating data for us.
YEAR ENDED DECEMBER 31, 2000(7) 1999(8) 1998(9) 1997 1996 ----------- ----------- ----------- ----------- ----------- (In thousands, except per unit and operating data) INCOME AND CASH FLOW DATA: Revenues $ 816,442 $ 428,749 $ 322,617 $ 73,932 $ 71,250 Cost of product sold 124,641 16,241 5,860 7,154 7,874 Operating expense 190,329 111,275 77,162 17,982 22,347 Fuel and power 43,216 31,745 22,385 5,636 4,916 Depreciation and amortization 82,630 46,469 36,557 10,067 9,908 General and administrative 60,065 35,612 39,984 8,862 9,132 ----------- ----------- ----------- ----------- ----------- Operating income 315,561 187,407 140,669 24,231 17,073 Earnings from equity investments 71,603 42,918 25,732 5,724 5,675 Amortization of excess cost of equity investments (8,195) (4,254) (764) -- -- Interest (expense) (97,102) (54,336) (40,856) (12,605) (12,634) Interest income and other, net 10,415 22,988 (5,992) (353) 3,129 Income tax (provision) benefit (13,934) (9,826) (1,572) 740 (1,343) ----------- ----------- ----------- ----------- ----------- Income before extraordinary charge 278,348 184,897 117,217 17,737 11,900 Extraordinary charge -- (2,595) (13,611) -- -- ----------- ----------- ----------- ----------- ----------- Net income $ 278,348 $ 182,302 $ 103,606 $ 17,737 $ 11,900 =========== =========== =========== =========== =========== General partners' interest in net income $ 109,470 $ 56,273 $ 33,447 $ 4,074 $ 218 =========== =========== =========== =========== =========== Limited partners' interest in net income $ 168,878 $ 126,029 $ 70,159 $ 13,663 $ 11,682 =========== =========== =========== =========== =========== Basic Limited Partners' income per unit before extraordinary charge(1) $ 2.68 $ 2.63 $ 2.09 $ 1.02 $ 0.90 =========== =========== =========== =========== =========== Basic Limited Partners' net income per unit $ 2.68 $ 2.57 $ 1.75 $ 1.02 $ 0.90 =========== =========== =========== =========== =========== Diluted Limited Partners' net income per unit(2) $ 2.67 $ 2.57 $ 1.75 $ 1.02 $ 0.90 =========== =========== =========== =========== =========== Per unit cash distribution paid $ 3.20 $ 2.78 $ 2.39 $ 1.63 $ 1.26 =========== =========== =========== =========== =========== Additions to property, plant and equipment $ 125,523 $ 82,725 $ 38,407 $ 6,884 $ 8,575 BALANCE SHEET DATA (AT END OF PERIOD): Net property, plant and equipment $ 3,306,305 $ 2,578,313 $ 1,763,386 $ 244,967 $ 235,994 Total assets $ 4,625,210 $ 3,228,738 $ 2,152,272 $ 312,906 $ 303,603 Long-term debt $ 1,255,453 $ 989,101 $ 611,571 $ 146,824 $ 160,211 Partners' capital $ 2,117,067 $ 1,774,798 $ 1,360,663 $ 150,224 $ 118,344 OPERATING DATA: Product Pipelines - Pacific - Mainline delivery volumes (MBbls)(3) 386,611 375,663 307,997 -- -- Pacific - Other delivery volumes (MBbls)(3) 14,243 10,025 17,957 -- -- Plantation - Delivery volumes (MBbls) 226,795 214,900 -- -- -- North System/Cypress - Delivery volumes (MBbls) 51,111 50,124 44,783 46,309 46,601 Natural Gas Pipelines - Transport volumes (Bcf)(4) 449.2 424.3 -- -- -- Carbon Dioxide Pipelines - Delivery volumes (Bcf)(5) 386.5 379.3 -- -- -- Bulk Terminals - Transload tonnage (Mtons)(6) 41,529 39,190 24,016 9,087 6,090
(1) Represents income before extraordinary charge per unit adjusted for the two-for-one split of units on October 1, 1997. Basic Limited Partners' income per unit before extraordinary charge was computed by dividing the interest of our unitholders in income before extraordinary charge by the weighted average number of units outstanding during the period. (2) 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. (3) We acquired our Pacific operations on March 6, 1998. (4) KMIGT and Trailblazer assets were acquired on December 31, 1999. 1999 volumes are shown for comparative purposes only. (5) Acquired remaining 80% interest in Kinder Morgan CO2 Company, L.P., effective April 1, 2000. 2000 and 1999 volume information is adjusted to include properties acquired from Devon Energy effective June 1, 2000, and to correct volumes previously reported. 2000 and 1999 volume information is shown for comparative purposes only. (6) Represents the volumes of the Cora Terminal, excluding ship or pay volumes of 252 Mtons for 1996, the Grand Rivers Terminal from September 1997, Kinder Morgan Bulk Terminals from July 1, 1998 and the Pier IX and Shipyard Terminals from December 18, 1998. (7) Includes results of operations for KMIGT, 66 2/3% interest in Trailblazer Pipeline Company, 49% interest in Red Cedar, Milwaukee Bulk Terminals, Dakota Bulk Terminal, remaining 80% interest in KMCO2, Devon Energy carbon dioxide properties, Kinder Morgan Transmix Company, LLC, 32.5% interest in Cochin Pipeline System and Delta Terminal Services since dates of acquisition. KMIGT, Trailblazer assets, and our 49% interest in Red Cedar were acquired on December 31, 1999. Milwaukee Bulk Terminals, Inc. and Dakota Bulk Terminal, Inc. were acquired on January 1, 2000. Our remaining 80% interest in KMCO2 was acquired on April 1, 2000. The Devon Energy carbon dioxide properties were acquired on June 1, 2000. Buckeye Refining Company, LLC was acquired on October 25, 2000. Our 32.5% interest in Cochin was acquired on November 3, 2000, and Delta Terminal Services, Inc. was acquired on December 1, 2000. (8) Includes results of operations for 51% interest in Plantation Pipe Line Company, Product Pipelines' transmix operations and 33 1/3% interest in Trailblazer Pipeline Company since dates of acquisition. Our second investment in Plantation, representing a 27% interest was made on June 16, 1999. The Product Pipelines' transmix operations were acquired on September 10, 1999, and our initial 33 1/3% investment in Trailblazer was made on November 30, 1999. (9) Includes results of operations for Pacific operations, Kinder Morgan Bulk Terminals, Inc. and the 24% interest in Plantation Pipe Line Company since the respective dates of acquisition. The Pacific operations were acquired March 6, 1998, Kinder Morgan Bulk Terminals were acquired on July 1, 1998 and our 24% interest in Plantation Pipeline Company was acquired on September 15, 1998. 49 50 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS You should read the following discussion and analysis in conjunction with our Consolidated Financial Statements included elsewhere in this report. RESULTS OF OPERATIONS Our financial results over the past three years reflect significant growth in revenues, operating income and net income. During this timeframe, we made numerous strategic business acquisitions and experienced strong growth in our pipeline and terminal operations. The combination of targeted business acquisitions, higher capital spending, favorable economic conditions and management's continuing focus on controlling general and operating expenses across our entire business portfolio led the way to strong growth in all four of our business segments. In 2000, we reported record levels of revenue, operating income, net income and earnings per unit. Our net income was $278.3 million ($2.67 per diluted unit) on revenues of $816.4 million in 2000, compared to net income of $182.3 million ($2.57 per diluted unit) on revenues of $428.7 million in 1999, and net income of $103.6 million ($1.75 per diluted unit) on revenues of $322.6 million in 1998. Included in our net income for 1999 and 1998 were extraordinary charges associated with debt refinancing transactions in the amount of $2.6 million in 1999 and $13.6 million in 1998. In addition, our 1999 net income included a benefit of $10.1 million related to the sale of our 25% interest in the Mont Belvieu Fractionator, which separates natural gas liquids from natural gas, partially offset by special non-recurring charges. Our total consolidated operating income was $315.6 million in 2000, $187.4 million in 1999 and $140.7 million in 1998. Our total consolidated net income before extraordinary charges was $278.3 million in 2000, $184.9 million in 1999 and $117.2 million in 1998. Our increase in overall net income and revenues in 2000 compared to 1999 primarily resulted from the inclusion of our Natural Gas Pipelines segment, acquired from Kinder Morgan, Inc. on December 31, 1999, and our acquisition of the remaining 80% ownership interest in Kinder Morgan CO2 Company, L.P. (formerly Shell CO2 Company, Ltd.) effective April 1, 2000. Prior to that date, we owned a 20% equity interest in Kinder Morgan CO2 Company, L.P. and reported its results under the equity method of accounting. The results of Kinder Morgan CO2 Company, L.P. are included in our CO2 Pipelines segment. Our acquisition of substantially all of our Product Pipelines' transmix operations in September 1999, and Milwaukee Bulk Terminals, Inc. and Dakota Bulk Terminal, Inc. in January 2000, also contributed to our overall increase in period-to-period revenues and net income. The inclusion of a full year of activity for our Pacific operations and Bulk Terminals segment was the largest contributing factor for the increase in total revenues and earnings in 1999 compared with 1998. We acquired our Pacific operations in March 1998, Kinder Morgan Bulk Terminals, Inc. in July 1998 and the Pier IX and Shipyard River terminals in December 1998. PRODUCT PIPELINES Our Product Pipelines' segment revenues increased 34%, from $314.1 million in 1999 to $421.4 million in 2000, and net income increased 6%, from $209.0 million in 1999 to $221.2 million in 2000. The $107.3 million increase in year-to-year segment revenues includes a $90.7 million increase in revenues earned from transmix operations. The increase in transmix revenues resulted primarily from the inclusion of a full year of operations from our initial acquisition of transmix assets, acquired September 1999, and the inclusion of two months of operations from additional transmix assets acquired in late October 2000. The segment also reported revenues of $3.8 million from the inclusion of two months of operations from our investment in the Cochin pipeline system, which was acquired in November 2000. Furthermore, higher throughput volumes on both our Pacific operations and North System pipelines contributed to a $12.7 million increase in segment revenues. On our Pacific operations, average tariff rates remained relatively flat between 2000 and 1999, with an almost 3% increase in mainline delivery volumes resulting in a 3% increase in revenues. On our North System, revenues grew 14% in 2000 compared to 1999. The increase was due to an almost 10% increase in throughput revenue volumes, primarily due to strong demand from refineries in the Midwest, as well as a 5% increase in average tariff rates. In 1998, the Product Pipelines segment earned $156.9 million on revenues of $258.7 million. The $55.4 million increase in revenues in 1999 over 1998 relates to the inclusion in 1999 of a full year of results from our Pacific operations, acquired in March 1998, and the inclusion of almost four months of transmix operations, which were 50 51 acquired in early September 1999. The acquired transmix assets produced revenues of $18.3 million in 1999. Our Pacific operations reported a revenue increase of $35.3 million in 1999 versus 1998. With a full twelve months of activity reported in 1999, total mainline throughput volumes on our Pacific operations pipelines increased 22% in 1999 compared to 1998. The higher 1999 segment revenues were partly offset by an almost 4% decrease in average tariff rates on our Pacific pipelines. The decrease in average tariff rates was mainly due to the reduction in transportation rates, effective April 1, 1999, on our Pacific operation's East Line. Combined operating expenses for the Product Pipelines segment, which include the segment's cost of sales, fuel, power and operating and maintenance expenses, were $172.5 million in 2000, $76.5 million in 1999 and $56.3 million in 1998. The increase in expenses in each year resulted mainly from the inclusion of our transmix operations and the higher delivery volumes on our Pacific operations pipelines. Depreciation and amortization expense was $41.7 million in 2000, $38.9 million in 1999 and $32.7 million in 1998, reflecting our acquisitions, continued investments in capital additions and pipeline expansions. Segment operating income was $193.5 million in 2000, $186.1 million in 1999 and $159.2 million in 1998. Earnings from our equity investments, net of amortization of excess costs, were $29.1 million in 2000, $21.4 million in 1999 and $5.9 million in 1998. The increases in our equity earnings each year were chiefly due to our investments in Plantation Pipe Line Company. We acquired a 24% ownership interest in Plantation Pipe Line Company in September 1998 and an additional 27% ownership interest in June 1999. Additionally, the Product Pipeline segment benefited from favorable changes in non-operating income/expense in 1999 compared to 1998, primarily the result of lower 1999 expense accruals made for our Federal Energy Regulatory Commission rate case reserve (as a result of the Federal Energy Regulatory Commission's opinion relating to an outstanding rate case dispute), 1999 insurance recoveries and favorable adjustments to employee post-retirement benefit liabilities. We are parties to proceedings at the Federal Energy Regulatory Commission and the California Public Utilities Commission that challenge our tariffs on our Pacific operations. The FERC complaint seeks approximately $105 million in tariff refunds and approximately $35 million in prospective annual tariff reductions. The CPUC complaint seeks approximately $17 million in tariff refunds and approximately $10 million in prospective annual tariff reductions. Decisions regarding these complaints could negatively impact our cash flow. Additional challenges to tariff rates could be filed with the Federal Energy Regulatory Commission and California Public Utilities Commission in the future. We believe we have meritorious defenses in the proceedings challenging our pipeline tariffs, and we are defending these proceedings vigorously. We believe the ultimate resolutions of these proceedings will be materially more favorable than the outcomes sought by the protesting shippers. NATURAL GAS PIPELINES Our Natural Gas Pipelines segment reported earnings of $112.9 million on revenues of $173.0 million in 2000. These results were produced from assets that we acquired from Kinder Morgan, Inc. on December 31, 1999. For comparative purposes, transported gas volumes on our natural gas assets increased almost 6% in 2000 compared with 1999 when these assets were owned by Kinder Morgan, Inc. The overall increase includes an almost 9% increase in volumes shipped on the Trailblazer Pipeline. Higher capacity to receive natural gas on the Trailblazer Pipeline during 2000 resulted in an increase in the available quantity of gas delivered to the Trailblazer Pipeline. Segment operating expenses totaled $51.2 million in 2000 and segment operating income was $97.2 million. Earnings for 2000 from the segment's 49% equity investment in Red Cedar Gathering Company, net of amortization of excess costs, were $15.0 million. Segment results for 1999 and 1998 primarily represent activity from our since divested partnership interest in the Mont Belvieu fractionation facility. Segment earnings of $16.8 million in 1999 includes $2.5 million in equity earnings from our 25% interest in the Mont Belvieu Fractionator and $14.1 million from our third quarter gain on the sale of that interest to Enterprise Products Partners, L.P. In 1998, the segment reported earnings of $4.9 million, including equity income of $4.6 million. This amount represents earnings from our interest in the Mont Belvieu facility for a full twelve-month period. CO2 PIPELINES Our CO2 Pipelines segment consists of Kinder Morgan CO2 Company, L.P. After our acquisition of the remaining 80% interest in Kinder Morgan CO2 Company, L.P., on April 1, 2000, we no longer accounted for our investment on an equity basis. Our 2000 results also include the segment's acquisition of significant carbon dioxide pipeline assets and oil-producing property interests on June 1, 2000. For the year 2000, the segment reported 51 52 earnings of $68.0 million on revenues of $89.2 million. CO2 Pipelines reported operating expenses of $26.8 million and operating income of $47.9 million. Equity earnings from the segment's 50% interest in the Cortez Pipeline Company, net of amortization of excess costs, were $19.3 million. Segment results from 1999 and 1998 primarily represent equity earnings from our original 20% interest in Kinder Morgan CO2 Company, L.P. Segment earnings of $15.2 million in 1999 include $14.5 million in equity earnings from our interest in Kinder Morgan CO2 Company, L.P. In 1998, our CO2 Pipelines segment reported earnings of $15.5 million, including $14.5 million in equity earnings from our Kinder Morgan CO2 Company, L.P. investment. Under the terms of the prior Kinder Morgan CO2 Company, L.P. partnership agreement, we received a priority distribution of $14.5 million per year during 1998, 1999 and the first quarter of 2000. After our acquisition of the remaining 80% ownership interest, we amended this partnership agreement, among other things, to eliminate the priority distribution and other provisions rendered irrelevant by our sole ownership. BULK TERMINALS Our Bulk Terminals segment reported its highest amount of revenues, operating income and earnings in 2000. Following our acquisition of Kinder Morgan Bulk Terminals, Inc. effective July 1, 1998, we continued to make selective acquisitions and increase capital spending in order to grow and expand our bulk terminal businesses. Our 2000 results include the operations of Milwaukee Bulk Terminals, Inc. and Dakota Bulk Terminal, Inc., effective January 1, 2000, and Delta Terminal Services, Inc., acquired on December 1, 2000. The 1999 results include the full-year of operations for Kinder Morgan Bulk Terminals, Inc. and the Pier IX and Shipyard River terminals, acquired on December 18, 1998. The Bulk Terminals segment reported earnings of $37.6 million in 2000, $35.0 million in 1999 and $19.2 million in 1998. Segment revenues were $132.8 million in 2000, $114.6 million in 1999 and $62.9 million in 1998. In addition to our acquisitions made in 2000, which generated revenues of $11.4 million, our Bulk Terminals segment's overall increases in year-to-year revenues were due to a 10% increase in coal transfer revenues earned by the segment's Cora and Grand Rivers coal terminals in 1999 and 2000. Combined, these two coal terminals reported a $2.0 million increase in transfer revenues in 2000 over 1999 due to a 6% increase in coal volumes accompanied by a 4% increase in average coal transfer rates. A $1.7 million increase in 1999 transfer revenues over 1998 transfer revenues resulted from an 18% increase in coal volumes handled at the terminals, partially offset by a 7% decrease in average transfer rates. The growth in the Bulk Terminals segment revenues over the two-year period was partially offset by lower revenue from coal marketing activities. Bulk Terminals combined operating expenses totaled $81.7 million in 2000 compared to $66.6 million in 1999 and $36.9 million in 1998. The increase in 2000 versus 1999 was the result of acquisitions made in 2000, higher operating expenses associated with the transfer of higher coal volumes and an increase in fuel costs. The increase in 1999 compared to 1998 was the result of including a full year of operations for Kinder Morgan Bulk Terminals, Inc., partially offset by higher 1998 cost of sales expenses related to purchase/sale marketing contracts. Depreciation and amortization expense was $9.6 million in 2000, $7.5 million in 1999 and $3.9 million in 1998. The increases in depreciation were primarily due to the addition of Kinder Morgan Bulk Terminals, Inc. and the Pier IX and Shipyard River terminals in 1998 and the Milwaukee and Dakota Bulk Terminals in 2000, and higher property balances as a result of increased capital spending. OTHER Items not attributable to any segment include general and administrative expenses, interest income and expense and minority interest. General and administrative expenses totaled $60.1 million in 2000 compared with $35.6 million in 1999 and $40.0 million in 1998. The increase in our 2000 general and administrative expenses over the prior year was mainly due to our larger and more diverse operations. During 2000, we assimilated the operations of our Natural Gas Pipelines and CO2 Pipelines business segments. We continue to manage aggressively our infrastructure expense and to focus on our productivity and expense controls. Our total interest expense, net of interest income, was $93.3 million in 2000, $52.6 million in 1999 and $38.6 million in 1998. The increases were primarily due to debt we assumed as part of the acquisition of our Pacific operations as well as additional debt related to the financing of our 2000 and 1999 investments. Minority interest increased to $8.0 million in 2000 compared with $2.9 million in 1999 and $1.0 million in 1998. The $5.1 million increase in 2000 over 1999 primarily resulted from the inclusion of earnings attributable to the Trailblazer Pipeline Company. The $1.9 million increase in 1999 over 1998 resulted from higher earnings attributable to our Pacific operations as well as to our higher overall income. 52 53 OUTLOOK We actively pursue a strategy to increase our operating income. We will use a three-pronged strategy to accomplish this goal. o Cost Reductions. We have reduced by approximately 15 percent the total operating, maintenance, general and administrative expenses of those operations that we owned at the time Kinder Morgan (Delaware), Inc. acquired our general partner in February 1997. In addition, we have made similar percentage reductions in the operating, maintenance, general and administrative expenses of many of the businesses and assets that we acquired since February 1997, including our Pacific operations and Plantation Pipe Line Company. Generally, these reductions in expense have been achieved by eliminating functions which we and the acquired businesses each maintained prior to their combination. We expect to make similar percentage reductions in expenses of the recently acquired GATX pipelines and terminals and intend to continue to seek further reductions throughout our businesses where appropriate. o Internal Growth. We intend to expand the operations of our current facilities. We have taken a number of steps that management believes will increase revenues from existing operations, including the following: o completed the expansion of our San Diego Line in June 2000. The expansion project cost approximately $18 million and consisted of the construction of 23 miles of 16-inch diameter pipe and other appurtenant facilities. The new facilities will increase capacity on our San Diego Line by approximately 25%; o entered into an agreement to provide pipeline transportation services on the North System for Aux Sable Liquid Products, L.P. in the Chicago area beginning in the first quarter of 2001; o constructed a multi-million dollar cement import and distribution facility at the Shipyard River terminal, which was completed in the fourth quarter of 2000, as part of a 30 year cement contract with Blue Circle Cement; o announced an expansion project on the Trailblazer Pipeline in August 2000. The project will involve the installation of two new compressor stations and the addition of horsepower at an existing compressor station; and o continued a $13 million upgrade to the coal loading facilities at the Cora and Grand Rivers coal terminals. The two terminals handled an aggregate of 17.0 million tons of coal during 2000 compared with 16.0 million tons in 1999. o Strategic Acquisitions. Since January 1, 2000, we have made the following acquisitions: o Milwaukee Bulk Terminals, Inc. January 1, 2000 o Dakota Bulk Terminal, Inc. January 1, 2000 o Kinder Morgan CO2 Company, L.P. (80%) April 1, 2000 o CO2 June 1, 2000 o Transmix Assets October 25, 2000 o Cochin Pipeline System November 3, 2000 o Delta Terminal Services, Inc. December 1, 2000 o Kinder Morgan Texas Pipeline L.P. December 21, 2000 o Casper-Douglas Gas Gathering and Processing Assets December 21, 2000 o Coyote Gas Treating, LLC (50%) December 21, 2000 o Thunder Creek Gas Services, LLC (25%) December 21, 2000 o CO2 Investment to be contributed to Joint Venture with Marathon December 28, 2000 o Colton Transmix Processing Facility (50%) December 31, 2000 o GATX Domestic Pipelines and Terminals March 1, 2001 and March 30, 2001 o Pinney Dock and Transportation Company March 13, 2001 53 54 The costs and methods of financing for each significant acquisition are discussed under "Capital Requirements for Recent Transactions." We regularly seek opportunities to make additional strategic acquisitions, to expand existing businesses and to enter into related businesses. We periodically consider potential acquisition opportunities as they are identified. We cannot assure you that we will be able to consummate any such acquisition. Our management anticipates that we will finance acquisitions by borrowings under our bank credit facilities or by issuing commercial paper, and subsequently reduce these short term borrowings by issuing new debt securities and/or units. On January 17, 2001, we announced a quarterly distribution of $0.95 per unit for the fourth quarter of 2000. The distribution for the fourth quarter of 1999 was $0.725 per unit. On March 15, 2001, we announced our intention to increase the quarterly distribution for the first quarter of 2001 to $1.00 per common unit, or $4.00 per common unit on an annualized basis. LIQUIDITY AND CAPITAL RESOURCES Our primary cash requirements, in addition to normal operating expenses, are debt service, sustaining capital expenditures, expansion capital expenditures, and quarterly distributions to our unitholders and general partner. In addition to utilizing cash generated from operations, we could meet our cash requirements through borrowings under our credit facilities or issuing short-term commercial paper, long-term notes or additional units. We expect to fund: o future cash distributions and sustaining capital expenditures with existing cash and cash flows from operating activities; o expansion capital expenditures through additional borrowings or issuance of additional units; o interest payments from cash flows from operating activities; and o debt principal payments with additional borrowings as they become due or by the issuance of additional units. At December 31, 2000, our current commitments for capital expenditures were approximately $37 million. This amount has primarily been committed for the purchase of plant and equipment. We expect to fund these commitments through additional borrowings or the issuance of additional units. All of our capital expenditures, with the exception of sustaining capital expenditures, are discretionary. OPERATING ACTIVITIES Net cash provided by operating activities was $301.6 million in 2000 compared to $182.9 million in 1999. The $118.7 million increase in our period-to-period cash flows from operations resulted from a net increase of $118.5 million in cash receipts from the sales of services and products, net of cash operating expenses. Higher net cash flows generated from sales and expenses were primarily due to the business acquisitions and capital investments we made during 2000. Other significant year-to-year changes in cash from operating activities include: o a $52.5 million payment of accrued rate refund liabilities; o a $20.3 million increase in collections of trade receivables, net of payments on trade payables; o a $13.8 million increase in distributions from equity investments; and o a $11.3 million net increase in insurance receivables. The payment of the rate refunds was made under settlement agreements with shippers on our natural gas pipelines. Higher cash inflows from collections on accounts receivable, net of accounts payable payments, were mainly due to collections from our natural gas pipelines, which were included in our 2000 operating results. The increase in distributions from equity investments was mainly due to distributions we received in 2000 from our 50% ownership interest in Cortez Pipeline Company and our 49% ownership interest in Red Cedar Gathering Company. Following our acquisition of the remaining ownership interest in Kinder Morgan CO2 Company, L.P. on April 1, 2000, we accounted for our investment in Cortez Pipeline Company under the equity method of accounting. We acquired our interest in Red Cedar Gathering Company from Kinder Morgan, Inc. on December 31, 1999. The 54 55 overall increase in distributions from equity investments was partially offset by the absence of distributions from our original 20% interest in Kinder Morgan CO2 Company, L.P. from April 1, 2000 through December 31, 2000 due to the fact we no longer accounted for this investment on an equity basis. The increase in cash flows from insurance receivables reflects higher collections on our Pacific operations' insurance receivables. INVESTING ACTIVITIES Net cash used in investing activities was $1,197.6 million in 2000 compared to $196.5 million in 1999, an increase of $1,001.1 million chiefly attributable to the $1,008.6 million of asset acquisitions we made in 2000. Our 2000 acquisition outlays included: o a $478.3 million payment to Kinder Morgan, Inc. for the Natural Gas Pipelines assets; o a $188.9 million net payment for the remaining 80% interest in Kinder Morgan CO2 Company, L.P.; o a $120.5 million payment for our 32.5% ownership interest in the Cochin Pipeline System; o a $114.3 million payment for Bulk Terminal acquisitions, including Milwaukee Bulk Terminals, Inc., Dakota Bulk Terminal, Inc. and Delta Terminal Services, Inc.; o a $53.4 million payment for our interests in the Canyon Reef Carriers CO2 Pipeline and SACROC oil field; and o a $45.7 million payment for the acquisition of Kinder Morgan Transmix Company, LLC formerly Buckeye Refining Company, LLC. We expended an additional $42.8 million for capital expenditures in 2000 compared to 1999. Including expansion and maintenance projects, our capital expenditures were $125.5 million in 2000 and $82.7 million in 1999. The increase was driven primarily by continued investment in our Pacific operations and in our Bulk Terminals business segment. Proceeds from the sale of investments, property, plant and equipment, net of removal costs, were lower by $29.7 million in 2000 versus 1999. Proceeds received from sales and retirements of investments, property, plant and equipment were $13.4 million in 2000 and $43.1 million in 1999. The decrease was due to the $41.8 million we received for the sale of our interest in the Mont Belvieu fractionation facility in September 1999. The overall increase in funds used in investing activities was offset by a $82.4 million decrease in cash used for acquisitions of investments. We used $79.4 million for acquisitions of investments in 2000 compared with $161.8 million in 1999. Our 2000 investment outlays included: o $34.2 million for a 7.5% interest in the Yates oil field subsequently contributed to the carbon dioxide joint venture with Marathon Oil Company; o $44.6 million for our 25% interest in Thunder Creek Gas Services, LLC and our 50% interest in Coyote Gas Treating, LLC. Our 1999 investment outlays consisted of: o $124.2 million for a 27% interest in Plantation Pipe Line Company (increasing our interest to 51%); and o $37.6 million for a one-third interest in Trailblazer Pipeline Company. FINANCING ACTIVITIES Net cash provided by financing activities amounted to $915.3 million in 2000, an increase of $893.3 million from the prior year that was mainly the result of an additional $817.1 million we received from overall debt financing activities. The increase in borrowings was mainly due to 2000 acquisitions. We completed a private placement of $400 million in debt securities during the first quarter of 2000, resulting in a cash inflow of $397.9 million, net of discounts and issuing costs. We completed a second private placement of $250 million in debt securities during the fourth quarter of 2000, resulting in a cash inflow of $246.8 million, net of discounts and issuing costs. In addition, we received $171.4 million as proceeds from our issuance of units during 2000, most significantly realized from our public offering of 4,500,000 common units on April 4, 2000. The overall increase in funds provided by our financing activities was partially offset by a $102.8 million increase in our distributions to partners. Distributions to 55 56 all partners increased to $293.6 million in 2000 compared to $190.8 million in 1999. The increase in distributions was due to: o an increase in our per unit distributions paid; o an increase in our number of units outstanding; o our general partner incentive distributions, which resulted from increased distributions to our unitholders; and o distributions paid by Trailblazer Pipeline Company, which were included in our consolidated results following the acquisition of our controlling 66 2/3% interest on December 31, 1999. We paid distributions of $3.20 per unit in 2000 compared to $2.775 per unit in 1999. The 15% increase in paid distributions per unit resulted from favorable operating results in 2000. PARTNERSHIP DISTRIBUTIONS Our partnership agreement requires that we distribute 100% of our available cash to our partners within 45 days following the end of each calendar quarter in accordance with their respective percentage interests. Our available cash consists generally of all of our cash receipts, including cash received by our operating partnerships, 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 Santa Fe Pacific Pipeline, L.P. in respect of its 0.5% interest in SFPP, L.P. Our general partner is granted discretion by our partnership agreement 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 our general partner determines our quarterly distributions, they consider current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level. For 1998, 1999, and 2000 we distributed 93%, 97%, and 102%, of the total of cash receipts less cash disbursements, respectively. The difference between these numbers and 100% reflects net additions to or reductions in reserves. Our available cash is initially distributed 98% to our limited partners and 2% to our general partner, Kinder Morgan G.P., Inc. These distribution percentages are modified to provide for incentive distributions to be made to our general partner in the event that quarterly distributions to unitholders exceed certain specified targets. Our available cash for each quarter is distributed: o 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 $0.3025 per unit in cash for that quarter; o 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 $0.3575 per unit in cash for that quarter; o 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 $0.4675 per unit in cash for that quarter; and o fourth, 50% of any available cash then remaining to the owners of all classes of units pro rata, paid in cash to owners of all classes of common units, and 50% in cash to our general partner. Incentive distributions are generally defined as all cash distributions made to our general partner that are in excess of 2% of the aggregate amount of cash being distributed. The general partner's incentive distributions declared by us for 2000 were $107,764,885, while the incentive distributions paid during 2000 were $89,399,771. DEBT AND CREDIT FACILITIES Our debt and credit facilities as of December 31, 2000, consist primarily of: o a $600 million unsecured 364-day credit facility due October 25, 2001, which also supports a commercial paper program of equivalent size; 56 57 o a $300 million unsecured five-year credit facility due September 29, 2004; o $200 million of Floating Rate Senior Notes due March 22, 2002; o $200 million of 8.00% Senior Notes due March 15, 2005; o $250 million of 6.30% Senior Notes due February 1, 2009; o $250 million of 7.50% Senior Notes due November 1, 2010; o $20.2 million of Senior Secured Notes due September 2002 (Trailblazer Pipeline Company, of which we own 66 2/3%, is the obligor on the notes); o $119 million of Series F First Mortgage Notes due December 2004 (our subsidiary, SFPP L.P., is the obligor on the notes); and o $23.7 million of tax-exempt bonds due 2024 (our subsidiary, Kinder Morgan Operating L.P. "B," is the obligor on these bonds). First Union National Bank is the administrative agent under the $600 million and $300 million credit facilities referred to above. Interest on borrowings is payable quarterly. Interest on the credit facilities accrues at our option at a floating rate equal to either: o First Union National Bank's base rate (but not less than the Federal Funds Rate, plus .5%) (As of March 31, 2001, First Union National Bank's base rate was 8.0%); or o LIBOR, plus a margin, which varies depending upon the credit rating of our long-term senior unsecured debt (As of March 31, 2001, we could borrow for one month at a rate of 5.5% under the 364-day facility and 5.55% under the 5-year facility). These rates have decreased since the beginning of the year as short-term interest rates have fallen. The five-year credit facility also permits us to obtain bids for fixed rate loans from members of the lending syndicate. The credit facilities include the following restrictive covenants: o requirements to maintain certain financial ratios; total debt divided by EBITDA for the prior four quarters may not exceed 4.5 prior to July 1, 2001 and 4.0 thereafter and EBITDA for the prior four quarters divided by interest expense for the prior four quarters may not fall below 3.0 prior to July 1, 2001 and 3.5 thereafter; o restrictions on the type of additional indebtedness that may be incurred and on the incurrence of additional indebtedness of our subsidiaries; o restrictions on entering into mergers, consolidations and sales of assets; o restrictions on granting liens; o prohibitions on making cash distributions to holders of units more frequently than quarterly; o prohibitions on making cash distributions in excess of 100% of available cash for the immediately preceding calendar quarter; and o prohibitions on making any distribution to holders of units if an event of default exists or would exist upon making such distribution. We are in compliance with these covenants. As of December 31, 2000, we had outstanding borrowings under our credit facilities of $789.6 million. At December 31, 2000, the interest rate on our credit facilities was 7.115% per annum. Our borrowings at December 31, 2000 included the following: o $193 million borrowed to fund the purchase price of natural gas pipelines assets acquired in December 2000; o $175 million used to pay the outstanding balance on SFPP, L.P.'s credit facility; o $118 million borrowed to fund the purchase price of our 32.5% interest in the Cochin Pipeline system in December 2000; 57 58 o $114 million borrowed to fund the purchase price of Delta Terminal Services, Inc. in December 2000; o $72 million borrowed to fund principal and interest payments on SFPP, L.P.'s Series F First Mortgage Notes in December 2000; o $34 million borrowed to fund the purchase price of our 7.5% interest in the Yates oil field in December 2000; and o $83.6 million borrowed to fund expansion capital projects. Our short-term debt at December 31, 2000, consisted of: o $582 million of borrowings under our unsecured 364-day credit facility due October 25, 2001; o $52 million of commercial paper borrowings; o $35 million under SFPP L.P.'s 10.70% Series F First Mortgage Notes; and o $14.6 million in other borrowings. During 2000, our cash used for acquisitions and expansions exceeded $600 million. Historically, we have utilized our short-term credit facilities to fund acquisitions and expansions and then refinanced our short-term borrowings utilizing long-term credit facilities and by issuing equity or long-term debt securities. We intend to refinance our short-term debt during 2001 through a combination of long-term debt and equity. Based on prior successful short-term debt refinancings and current market conditions, we do not anticipate any liquidity problems. We have an outstanding letter of credit issued under our five-year credit facility in the amount of $23.7 million that backs-up our tax-exempt bonds due 2024. The letter of credit reduces the amount available for borrowing under that credit facility. 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. At December 31, 2000, the interest rate was 5.00%. In addition, as of December 31, 1999, we financed $330 million through Kinder Morgan, Inc. to fund part of the acquisition of assets acquired from Kinder Morgan, Inc. on December 31, 1999. In accordance with the Closing Agreement entered into as of January 20, 2000, we paid Kinder Morgan, Inc. a per diem fee of $180.56 for each $1,000,000 financed. We paid Kinder Morgan, Inc. $200 million on January 21, 2000, and the remaining $130 million on March 23, 2000 with a portion of the proceeds from our issuance of notes on March 22, 2000. 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 and then on October 25, 2000, in conjunction with our new 364-day credit facility, we increased the commercial paper program to provide for the issuance of up to $600 million of commercial paper. Borrowings under our commercial paper program reduce the borrowings allowed under our 364-day and five-year credit facilities combined. As of December 31, 2000, we had $52 million of commercial paper outstanding with an interest rate of 7.02%. At December 31, 2000, the outstanding balance under SFPP, L.P.'s Series F notes was $119.0 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. The Series F notes are payable in annual installments of $39.5 million in 2001, $42.5 million in 2002 and $37.0 million in 2003. The Series F notes may also be prepaid in full or in part at a price equal to par plus, in certain circumstances, a premium. 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. At December 31, 1999, the outstanding balance under SFPP, L.P.'s bank credit facility was $174 million. On August 11, 2000, we replaced the outstanding balance under SFPP, L.P.'s secured credit facility with a $175 million unsecured borrowing under our five-year credit facility. SFPP, L.P. executed a $175 million intercompany note in our favor to evidence this obligation. In December 1999, Trailblazer Pipeline Company entered into a 364-day revolving credit agreement with Toronto Dominion, Inc. providing for loans up to $10 million. At December 26, 2000, the outstanding balance due 58 59 under Trailblazer Pipeline Company's bank credit facility was $10 million. On December 27, 2000, Trailblazer Pipeline Company paid the outstanding balance under its credit facility with a $10 million borrowing under an intercompany account payable in favor of Kinder Morgan, Inc. 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 agreement expires December 27, 2001. The borrowings were used to pay the account payable to Kinder Morgan, Inc. At January 31, 2001, the outstanding balance under Trailblazer Pipeline Company's revolving credit agreement was $10 million. The agreement provides for an interest rate of LIBOR plus 0.875%. At January 31, 2001 the interest rate on the credit facility debt was 6.625%. Pursuant to the terms of the revolving credit agreement with Credit Lyonnais New York Branch, Trailblazer Pipeline Company partnership distributions are restricted by certain financial covenants. From time to time we issue long-term debt securities. All of our long-term debt securities issued to date, other than those issued under our revolving credit facilities, generally have the same terms except for interest rates, maturity dates and prepayment restrictions. All of our outstanding debt securities are unsecured obligations that rank equally with all of our other senior debt obligations. Our outstanding debt securities as of December 31, 2000, consist of the following: o $250 million in principal amount of 6.3% senior notes due February 1, 2009. These notes were issued on January 29, 1999 at a price to the public of 99.67% per note. In the offering, we received proceeds, net of underwriting discounts and commissions, of approximately $248 million. We used the proceeds to pay the outstanding balance on our credit facility and for working capital and other partnership purposes. At December 31, 2000, the unamortized liability balance on the 6.30% senior notes was $249.3 million; o $200 million of floating rate notes due March 22, 2002 and $200 million of 8.0% notes due March 15, 2005. We used the proceeds to reduce outstanding commercial paper. At December 31, 2000, the interest rate on our floating rate notes was 7.0%; and o $250 million of 7.5% notes due November 1, 2010. These notes were issued on November 8, 2000. The proceeds from this offering, net of underwriting discounts, were $246.8 million. These proceeds were used to reduce our outstanding commercial paper. At December 31, 2000, the unamortized liability balance on the 7.5% notes was $248.4 million. The fixed rate notes provide that we may redeem the notes at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date plus a make-whole premium. We may not prepay the floating rate notes prior to their maturity. 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. Trailblazer Pipeline Company provided security for the notes principally by an assignment of certain Trailblazer Pipeline Company transportation contracts. 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 security for the notes, added a limitation on the amount of additional money that Trailblazer Pipeline Company could borrow and relieved Trailblazer Pipeline Company from its security deposit obligation. At December 31, 2000, Trailblazer Pipeline Company's outstanding balance under the Senior Secured Notes was $20.2 million. The Senior Secured Notes have a fixed annual interest rate of 8.03% and will be repaid in semiannual installments of $5.05 million from March 1, 2001 through September 1, 2002, the final maturity date. Interest is payable semiannually in March and September. Pursuant to the terms of this Note Purchase Agreement, Trailblazer Pipeline Company partnership distributions are restricted by certain financial covenants. Currently, Trailblazer Pipeline Company's proposed expansion project is pending before the Federal Energy Regulatory Commission. If the expansion is approved, which is expected in the first quarter of 2001, we plan to refinance these notes. CAPITAL REQUIREMENTS FOR RECENT TRANSACTIONS Milwaukee Bulk Terminals, Inc. Effective January 1, 2000, we acquired Milwaukee Bulk Terminals, Inc. for approximately $14.6 million in aggregate consideration consisting of $0.6 million and 0.3 million common units. Dakota Bulk Terminal, Inc. Effective January 1, 2000, we acquired Dakota Bulk Terminal, Inc. for approximately $9.5 million in aggregate consideration consisting of $0.2 million and 0.2 million common units. 59 60 Kinder Morgan CO2 Company, L.P. On April 1, 2000, we acquired the remaining 80% ownership interest in Shell CO2 Company, Ltd. that we did not own for approximately $212.1 million before purchase price adjustments. We paid this amount with approximately $171.4 million received from our public offering of 4.5 million units on April 4, 2000 and approximately $40.7 million received from the issuance of commercial paper. Carbon Dioxide Assets. On June 1, 2000, we acquired an interest in SACROC oil field and Canyon Reef Carrier CO2 Pipeline assets from Devon Energy Production Company, L.P. for approximately $55 million before purchase price adjustments. We borrowed the necessary funds under our commercial paper program. Transmix Operations. On October 25, 2000, we acquired Kinder Morgan Transmix Company, LLC, formerly known as Buckeye Refining Company, LLC, for $45.6 million after purchase price adjustments. We borrowed the necessary funds under our commercial paper program. Delta Terminal Services, Inc. Effective on December 1, 2000, we acquired Delta Terminal Services, Inc. for $114.1 million. We borrowed $114 million under our credit facilities and our commercial paper program to fund this acquisition. Cochin Pipeline. On November 3, 2000, we acquired a 32.5% ownership interest in the Cochin Pipeline system for $120.5 million from NOVA Chemicals Corporation. We borrowed $118 million under our credit facilities to partially fund this acquisition. Colton Transmix Processing Facility. On December 31, 2000 we acquired an additional 50% ownership interest in the Colton Transmix Processing Facility from Duke Energy Merchants for $11.2 million. We borrowed the necessary funds under our commercial paper program. Carbon Dioxide Joint Venture With Marathon Oil Company. On December 28, 2000, we paid $34.2 million for a 7.5% interest in the Yates oil field which was subsequently contributed to a carbon dioxide joint venture with Marathon Oil Company. The joint venture was formed on January 1, 2001. We borrowed $34 million under our credit facilities to fund this acquisition. Natural Gas Pipelines. On December 31, 2000, we acquired certain assets of Kinder Morgan Inc. for approximately $349.0 million in aggregate consideration consisting of $192.7 million, 0.64 million common units and 2.7 million Class B units. We borrowed $193 million under our credit facilities to fund the cash portion of the purchase price. GATX Acquisition. On February 22, 2001, we entered into an additional $1.1 billion unsecured credit facility that expires on December 31, 2001 with a syndicate of financial institutions to fund the GATX acquisition. With the proceeds from issuing $1 billion in notes described below, on March 23, 2001, this facility was reduced by $600 million to $500 million. This facility supports the issuance of commercial paper used to finance the GATX acquisition. Following the closing of this offering, we expect to terminate this facility. First Union National Bank, an affiliate of First Union Securities, Inc., is the administrative agent under this facility. As of March 31, 2001, we could borrow for one month at a rate of 5.5% under this 364-day facility. We issued $700 million of 6.75% notes due 2011 and $300 million of 7.40% notes due 2031 and applied the proceeds to retire short-term debt used to fund the GATX acquisition. Pinney Dock. On March 13, 2001, we purchased Pinney Dock and Transportation Company for approximately $41.5 million in cash. We borrowed the necessary funds under our commercial paper program. RISK MANAGEMENT The following discussion should be read in conjunction with note 14 to the Consolidated Financial Statements included elsewhere in this report. To minimize the risk of price changes in the crude oil, natural gas liquids and natural gas and associated transportation markets, we use certain financial instruments for hedging purposes. These instruments include energy products traded on the New York Mercantile Exchange and over-the-counter markets including, but not limited to, 60 61 futures and options contracts, fixed-price swaps and basis swaps. 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 credit ratings of the parties from whom we purchase financial instruments are as follows:
Credit Rating ------------- Enron North American, Corp. BBB+ Reliant Energy Services, Inc. BBB AEP Energy Services, Inc. A-
Pursuant to our management's approved policy, we are to engage in these activities only as a hedging mechanism against price volatility associated with: o pre-existing or anticipated physical natural gas, natural gas liquids, crude oil and carbon dioxide sales; o gas purchases; and o system use and storage. Our risk management activities are only used in order to protect our profit margins and we are prohibited 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. Gains and losses on hedging positions are deferred and recognized as natural gas purchases expense in the periods in which the underlying physical transactions occur. Through December 31, 2000, gains and losses on hedging positions have been deferred and recognized as cost of sales in the periods in which the underlying physical transactions occur. On January 1, 2001, we began accounting for derivative instruments under Statement of Financial Accounting Standards No. 133 "Accounting for Derivative Instruments and Hedging Activities" (after amendment by SFAS 137 and SFAS 138). As discussed above, our principal use of derivative financial instruments is to mitigate the market price risk associated with anticipated transactions for the purchase and sale of natural gas, natural gas liquids and crude oil. SFAS No. 133 allows these transactions to continue to be treated as hedges for accounting purposes, although the changes in the market value of these instruments will affect comprehensive income in the period in which they occur and any ineffectiveness in the risk mitigation performance of the hedge will affect net income currently. The change in the market value of these instruments representing effective hedge operation will continue to affect net income in the period in which the associated physical transactions are consummated. Adoption of SFAS No. 133 has resulted in $1.7 million of deferred net gain as of January 1, 2001, being reported as part of other comprehensive income in 2001, as well as subsequent changes in the market value of these derivatives prior to consummation of the transaction being hedged. We measure the risk of price changes in the natural gas, natural gas liquids and crude oil markets utilizing a Value-at-Risk model. 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 utilize a closed form model to evaluate risk on a daily basis. The Value-at-Risk computations utilize a confidence level of 97.7% 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% probability that the mark-to-market losses for a single day will not exceed the Value-at-Risk number presented. Financial instruments evaluated by the model include commodity futures and options contracts, fixed price swaps, basis swaps and over-the-counter options. During 2000, Value-at-Risk reached a high of $6.2 million and a low of $0.0 million. Value-at-Risk at December 31, 2000, was $6.2 million and averaged $0.3 million for 2000. Our calculated Value-at-Risk exposure represents an estimate of the reasonably possible net losses that would be recognized on our portfolio or 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. 61 62 YEAR 2000 There was no interruption to any business operation because of any Year 2000 glitch in programming. All operations were running smoothly on January 1, 2000. All business operations ran smoothly on January 3, 2000, when a full staff returned to work, and have continued running without incident throughout the year. There have been no incidents of consequence reported by material suppliers, customers or service providers, and no disruption to business through any electronic interface with third party companies. Expenditures to handle the Year 2000 issue were less than the moneys allocated and were not material. No further Year 2000 expenditures are planned. We have contingency plans and emergency response plans to address any unexpected incidents. 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 which could cause actual results to differ from those in the forward-looking statements, include: o price trends and overall demand for natural gas liquids, refined petroleum products, carbon dioxide, natural gas, coal and other bulk materials in the United States. Economic activity, weather, alternative energy sources, conservation and technological advances may affect price trends and demand; o changes in our tariff rates implemented by the Federal Energy Regulatory Commission or the California Public Utilities Commission; o our ability to integrate any acquired operations into our existing operations; o any difficulties or delays experienced by railroads in delivering products to the bulk terminals; o our ability to successfully identify and close strategic acquisitions and make cost saving changes in operations; o shut-downs or cutbacks at major refineries, petrochemical plants, utilities, military bases or other businesses that use our services; o interruptions of electric power supply to our facilities due to natural disasters, power shortages, strikes, riots or other causes; o the condition of the capital markets and equity markets in the United States; and o the political and economic stability of the oil producing nations of the world. You should not put undue reliance on any forward-looking statements. See Items 1 and 2 "Business and Properties - Risk Factors" for a more detailed description of these and other factors that may affect the forward looking statements. When considering forward looking statements, one should keep in mind the risk factors described in "Risk Factors" above. The risk factors could cause our actual results to differ materially from those contained in any forward looking statement. We disclaim any obligation to update the above list or to announce publicly the result of any revisions to any of the forward looking statements to reflect future events or developments. In addition, our classification as a partnership for federal income tax purposes means that we do not generally pay federal income taxes on our net income. We do, however, pay taxes on the net income of subsidiaries that are corporations. We are relying on a legal opinion from our counsel, and not a ruling from the Internal Revenue Service, as to our proper classification for federal income tax purposes. See Items 1 and 2 "Business and Properties - Tax Treatment of Publicly Traded Partnerships Under the Internal Revenue Code." 62 63 ITEM 7a. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK ENERGY FINANCIAL INSTRUMENTS We use energy financial instruments to reduce our risk of price changes in the spot and fixed price natural gas, natural gas liquids and crude oil markets. For a complete discussion of our risk management activities, see note 14 to the Consolidated Financial Statements included elsewhere in this report. INTEREST RATE RISK The market risk inherent in our market risk sensitive instruments and positions is the potential change arising from increases or decreases in interest rates as discussed below. Generally, our market risk sensitive instruments and positions are characterized as "other than trading." Our exposure to market risk as discussed below includes "forward-looking statements" and represents an estimate of possible changes in fair value or future earnings that would occur assuming hypothetical future movements in interest rates. Our views on market risk are not necessarily indicative of actual results that may occur and do not represent the maximum possible gains and losses that may occur, since actual gains and losses will differ from those estimated, based on actual fluctuations in interest rates and the timing of transactions. We utilize both variable rate and fixed rate debt in our financing strategy. See note 9 to the Consolidated Financial Statements included elsewhere in this report for additional information related to our debt instruments. For fixed rate debt, changes in interest rates generally affect the fair value of the debt instrument, but not our earnings or cash flows. Conversely, for variable rate debt, changes in interest rates generally do not impact the fair value of the debt instrument, but may affect our future earnings and cash flows. We do not have an obligation to prepay fixed rate debt prior to maturity and, as a result, interest rate risk and changes in fair value should not have a significant impact on our fixed rate debt until we would be required to refinance such debt. As of December 31, 2000 and 1999, the carrying values of our long-term fixed rate debt were approximately $836.7 million and $460.6 million, respectively, compared to fair values of $944.1 million and $471.9 million, respectively. Fair values were determined using quoted market prices, where applicable, or future cash flow discounted at market rates for similar types of borrowing arrangements. A hypothetical 10% change in the average interest rates applicable to such debt for 2000 and 1999, respectively, would result in changes of approximately $23.6 million and $12.8 million, respectively, in the fair values of these instruments. The carrying value and fair value of our variable rate debt, including accrued interest, was $1,070.5 million as of December 31, 2000 and $740.0 million as of December 31, 1999. Fair value was determined using future cash flows discounted based on market rates for similar types of borrowing arrangements. A hypothetical 10% change in the average interest rate applicable to this debt would result in a change of approximately $7.4 million in our annualized pre-tax earnings. As of December 31, 2000, we were party to interest rate swap agreements with a notional principal amount of $200 million for the purpose of hedging the interest rate risk associated with our variable rate debt obligations. A hypothetical 10% change in the average interest rates related to these swaps would not have a material effect on our annual pre-tax earnings. We monitor our mix of fixed rate and variable rate debt obligations in light of changing market conditions and from time to time may alter that mix by, for example, refinancing balances outstanding under our variable rate debt with fixed rate debt (or vice versa) or by entering into interest rate swaps or other interest rate hedging agreements. As of December 31, 2000, our cash and investment portfolio did not include fixed-income securities. Due to the short-term nature of our investment portfolio, a hypothetical 10% increase in interest rates would not have a material effect on the fair market value of our portfolio. Since we have the ability to liquidate this portfolio, we do not expect our operating results or cash flows to be materially affected to any significant degree by the effect of a sudden change in market interest rates on our investment portfolio. 63 64 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The information required in this Item 8 is included in this report as set forth in the "Index to Financial Statements" on page F-1. ITEM 9. CHANGES IN AND DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. 64 65 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT DIRECTORS AND EXECUTIVE OFFICERS OF OUR GENERAL PARTNER As is commonly the case with publicly traded limited partnerships, we do not employ any of the persons responsible for managing or operating our business, but instead reimburse our general partner for its services. Set forth below is certain information concerning the directors and executive officers of our general partner. All directors of our general partner are elected annually by, and may be removed by, Kinder Morgan (Delaware), Inc. as its sole shareholder. All officers serve at the discretion of the board of directors of our general partner.
Name Age Position with our General Partner ---- --- --------------------------------- Richard D. Kinder 56 Director, Chairman and CEO William V. Morgan 57 Director, Vice Chairman and President Edward O. Gaylord 69 Director Gary L. Hultquist 57 Director Perry M. Waughtal 65 Director William V. Allison 53 President, Natural Gas Pipelines Thomas A. Bannigan 47 President, Products Pipelines David G. Dehaemers, Jr. 40 Vice President, Corporate Development Joseph Listengart 32 Vice President, General Counsel and Secretary Michael C. Morgan 32 Vice President, Strategy and Investor Relations C. Park Shaper 32 Vice President, Treasurer and Chief Financial Officer Thomas B. Stanley 50 President, Bulk Terminals James E. Street 44 Vice President, Human Resources and Administration
Richard D. Kinder was elected Director, Chairman and Chief Executive Officer of our general partner in February 1997. From 1992 to 1994, Mr. Kinder served as Chairman of our general partner. From October 1990 until December 1996, Mr. Kinder was President of Enron Corp. Enron and its affiliates and predecessors employed Mr. Kinder for over 16 years. William V. Morgan was elected Director of our general partner in June 1994, Vice Chairman of our general partner in February 1997 and President of our general partner in November 1998. He has held legal and management positions in the energy industry since 1975, including the presidencies of three major interstate natural gas companies which are now a part of Enron: Florida Gas Transmission Company, Transwestern Pipeline Company and Northern Natural Gas Company. In addition, Mr. Morgan served as President of Cortez Holdings Corporation, a pipeline investment company, from October 1992.through March 2000. Prior to joining Florida Gas in 1975, Mr. Morgan was engaged in the private practice of law in Washington, D.C. Edward O. Gaylord was elected Director of our general partner in February 1997. Mr. Gaylord is the Chairman of the Board of Directors of Jacintoport Terminal Company, a liquid bulk storage terminal on the Houston, Texas ship channel. Mr. Gaylord also serves on the Board of Directors for EOTT Energy Corporation, an oil trading and transportation company located in Houston, Texas, Seneca Foods Corporation and Imperial Sugar Company. Gary L. Hultquist was elected Director of our general partner in October 1999. Mr. Hultquist is the Managing Director of Hultquist Capital, LLC, a San Francisco-based strategic and merger advisory firm. He also serves as Chairman and Chief Executive Officer of TitaniumX Corporation, a supplier of high-performance storage disk substrates and magnetic media to the disk drive industry. He is also a member of the Board of Directors of Rodel, Inc. Previously, Mr. Hultquist practiced law in two San Francisco area firms for over 15 years, specializing in business, intellectual property, securities and venture capital litigation. Perry M. Waughtal was elected Director of our general partner in April 2000. Mr. Waughtal is a Limited Partner and 40% owner of Songy Partners Limited, an Atlanta, Georgia based real estate investment company. Mr. Waughtal advises Songy's management on real estate investments and has overall responsibility for strategic planning, management and operations. Previously, Mr. Waughtal served for over 30 years as Vice Chairman of Development 65 66 and Operations and as Chief Financial Officer for Hines Interests Limited Partnership, a real estate and development entity based in Houston, Texas. William V. Allison was elected President, Natural Gas Pipelines of our general partner in September 1999. He served as President, Pipeline Operations of our general partner from February 1999 to September 1999. From April 1998 to February 1999, he served as Vice President and General Counsel of our general partner. From 1977 to April 1998, Mr. Allison was employed at Enron Corp. where he held various executive positions, including President of Enron Liquid Services Corporation, Florida Gas Transmission Company and Houston Pipeline Company and Vice President and Associate General Counsel of Enron Corp. Prior to joining Enron Corp., he was an attorney at the FERC. Thomas A. Bannigan was elected President, Products Pipelines of our general partner in October 1999. Since 1980, Mr. Bannigan has held various legal and management positions in the energy industry, including General Counsel and Secretary of Plantation Pipe Line Company, and from May 1998 until October 1999, President and Chief Executive Officer of Plantation Pipe Line Company. David G. Dehaemers, Jr. was elected Vice President, Corporate Development of our general partner in January 2000. He was Treasurer of our general partner from February 1997 to January 2000 and Vice President and Chief Financial Officer of our general partner from July 1997 to January 2000. He served as Secretary of our general partner from February 1997 to August 1997. From October 1992 to January 1997, he was Chief Financial Officer of Morgan Associates, Inc., an energy investment and pipeline management company. Mr. Dehaemers was previously employed by the national CPA firms of Ernst & Whinney and Arthur Young. He is a CPA, and received his undergraduate Accounting degree from Creighton University in Omaha, Nebraska. Mr. Dehaemers received his law degree from the University of Missouri-Kansas City and is a member of the Missouri Bar. Joseph Listengart was elected Vice President and General Counsel of our general partner in October 1999. Mr. Listengart became an employee of our general partner in March 1998 and was elected its Secretary in November 1998. From March 1995 through February 1998, Mr. Listengart worked as an attorney for Hutchins, Wheeler & Dittmar, a Professional Corporation. Mr. Listengart received his Juris Doctor, magna cum laude, from Boston University in May 1994, his Masters in Business Administration from Boston University in January 1995 and his Bachelors of Arts degree in Economics from Stanford University in June 1990. Michael C. Morgan was elected Vice President, Strategy and Investor Relations of our general partner in January 2000. He was Vice President, Corporate Development of our general partner from February 1997 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 at PSI Energy, Inc., an electric utility, including Assistant to the Chairman. 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. C. Park Shaper was elected Vice President, Treasurer and Chief Financial Officer of our general partner in January 2000. Previously, 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 also served as Vice President and Chief Financial Officer of First Data Analytics, a wholly-owned subsidiary of First Data Corporation, from 1997 until June 1999. From 1995 to 1997, he was a consultant with The Boston Consulting Group. Mr. Shaper has prior experience with TeleCheck Services, Inc. and as a management consultant with the Strategic Services Division of Andersen Consulting. Mr. Shaper has a Bachelor of Science degree in Industrial Engineering and a Bachelor of Arts degree in Quantitative Economics from Stanford University. He also received a Master of Management degree from the J.L. Kellogg Graduate School of Management at Northwestern University. Thomas B. Stanley was elected President, Bulk Terminals of our general partner in August 1998. From 1993 to July 1998, he was President of Hall-Buck Marine, Inc. (now known as Kinder Morgan Bulk Terminals, Inc.), for which he has worked since 1980. Mr. Stanley is a CPA with ten years' experience in public accounting, banking, and insurance accounting prior to joining Hall-Buck. He received his bachelor's degree from Louisiana State University in 1972. 66 67 James E. Street was elected Vice President, Human Resources and Administration of our general partner in August 1999. From October 1996 to August 1999, Mr. Street was Senior Vice President, Human Resources and Administration for Coral Energy. Prior to joining Coral Energy, he was Vice President, Human Resources of Enron Corp. from July 1989 to August 1992. Mr. Street received a Bachelor of Science degree from the University of Nebraska at Kearney in 1979 and a Masters of Business Administration degree from the University of Nebraska at Omaha in 1984. 67 68 ITEM 11. EXECUTIVE COMPENSATION We have no executive officers, but we are obligated to reimburse our general partner for compensation paid to our general partner's executive officers in connection with their operation of our business. The following table summarizes all compensation paid to our general partner's chief executive officer and to each of our general partner's four other most highly compensated executive officers for services rendered to us during 2000, 1999 and 1998.
Summary Compensation Table Annual Compensation Long-Term Compensation Awards -------------------------------- ----------------------------- Units/ Restricted KMI Shares Stock Underlying All Other Name and Principal Position Year Salary Bonus(2) Awards(3) Options Compensation(6) - --------------------------- ---- -------- -------- ---------- ---------- --------------- Richard D. Kinder(1) 2000 $ 1 $ -- $ -- -- $ -- Director, Chairman and CEO 1999 150,003 -- -- -- 7,554 1998 200,004 -- -- -- 13,584 David G. Dehaemers, Jr 2000 200,000 300,000(4) 498,750 0/150,000(5) 10,920 Vice President, 1999 161,249 250,000(4) -- 0/250,000 7,408 Corporate Development 1998 141,247 200,000 -- -- 34,393 Michael C. Morgan 2000 200,000 300,000(4) 498,750 0/150,000(5) 10,836 Vice President, 1999 161,249 250,000(4) -- 0/250,000 7,408 Strategy and Investor Relations 1998 141,247 200,000 -- -- 50,421 William V. Allison 2000 200,000 300,000 498,750 -- 11,466 President, 1999 192,497 250,000 -- 0/250,000 9,335 Natural Gas Pipelines 1998 99,998 200,000 -- 10,000/0 11,366 Joseph Listengart(7) 2000 181,250 225,000 498,750 0/6,300 10,798 Vice President, 1999 124,336 175,000 -- 0/175,000 5,890 General Counsel and Secretary 1998 124,007 140,436 -- 5,000/0 78,620
(1) Effective October 1, 1999, Mr. Kinder's annual salary was reduced to $1.00. Mr. Kinder is not eligible for annual bonuses or option grants. (2) Amounts earned in year shown and paid the following year. (3) Represent shares of KMI stock awarded in 2001 that relate to performance in 2000. Value computed as the number of shares awarded (10,000) times the closing price on date of grant ($49.875 at 01/17/01). Twenty five percent of the shares vest on each of the first four anniversaries after the date of grant. The holders of the restricted stock awards are eligible to vote and to receive dividends declared on such shares. (4) Does not include for 1999, $3,753,868, or for 2000, $7,010,000 paid to Messrs. Dehaemers and Morgan under our Executive Compensation Plan. The payments made in 2000 were the last payments Messrs. Dehaemers and Morgan are to receive under our Executive Compensation Plan. We do not intend to compensate any of our general partner's employees under the Executive Compensation Plan on a going forward basis. See "-Executive Compensation Plan." (5) The 150,000 options in KMI shares were granted and became fully vested on April 20, 2000. The options were granted to Messrs. Dehaemers and Morgan in connection with the execution of their employment agreements. See "-Employment agreements." (6) Represents our general partner's contributions to the Retirement Savings Plan (a 401(k) plan), the imputed value of general partner-paid group term life insurance exceeding $50,000, and compensation attributable to taxable moving and parking expenses allowed. For 2000, contributions to Retirement Savings Plan, value of group-term life insurance exceeding $50,000 and parking compensation respectively were Messrs. Dehaemers ($10,200 / $420 / $300), Morgan ($10,200 / $336 / $300), Allison ($10,200 / $966 / $300) and Listengart ($10,200 / $298 / $300). (7) The 2000 options were granted in 2001, but relate to performance in 2000. The options were granted and became fully exercisable on 01/17/01 at a grant price of $49.875 per share. 68 69 Retirement Savings Plan. Effective July 1, 1997, our general partner established the Kinder Morgan Retirement Savings Plan, a defined contribution 401(k) plan, that permits all full-time employees of our general partner to contribute 1% to 15% of base compensation, on a pre-tax basis, into participant accounts. This plan was subsequently amended and merged to form the Kinder Morgan Savings Plan. In addition to a mandatory contribution equal to 4% of base compensation per year for each plan participant, our general partner may make discretionary contributions in years when specific performance objectives are met. 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 options at the employee's discretion. In the first quarter of 2001, an additional 2% discretionary contribution was made to individual accounts based on 2000 financial targets to unitholders. 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. Because levels of future compensation, participant contributions and investment yields cannot be reliably predicted over the span of time contemplated by a plan of this nature, it is impractical to estimate the annual benefits payable at retirement to the individuals listed in the Summary Compensation Table above. Executive Compensation Plan. Pursuant to our Executive Compensation Plan, executive officers of our general partner are eligible for awards equal to a percentage of the "incentive compensation value", which is defined as cash distributions to our general partner during the four calendar quarters preceding the date of redemption multiplied times eight (less a participant adjustment factor, if any). Under the plan, no eligible employee may receive a grant in excess of 2% and total awards under the plan may not exceed 10%. In general, participants may redeem vested awards in whole or in part from time to time by written notice. We may, at our option, pay the participant in units (provided, however, the unitholders approve the plan prior to issuing such units) or in cash. We may not issue more than 200,000 units in the aggregate under the plan. Units will not be issued to a participant unless such units have been listed for trading on the principal securities exchange on which the units are then listed. The plan terminates January 1, 2007 and any unredeemed awards will be automatically redeemed. The board of directors of our general partner may, however, terminate the plan before such date, and upon such early termination, we will redeem all unpaid grants of compensation at an amount equal to the highest incentive compensation value, using as the determination date any day within the previous twelve months, multiplied by 1.5. The plan was established in July 1997 and on July 1, 1997, the board of directors of our general partner granted awards totaling 2% of the incentive compensation value to each of David Dehaemers and Michael Morgan. Originally, 50% of such awards were to vest on each of January 1, 2000 and January 1, 2002. No awards were granted during 1998 and 1999. On January 4, 1999, the awards granted to Mr. Dehaemers and Mr. Morgan were amended to provide for the immediate vesting and pay-out of 50% of their awards, or 1% of the incentive compensation value. On April 28, 2000, the awards granted to Mr. Dehaemers and Mr. Morgan were amended to provide for the immediate vesting and pay-out of the remaining 50% of their awards, or 1% of the incentive compensation value. The board of directors of our general partner believes that accelerating the vesting and pay-out of the awards was in our best interest because it capped the total payment the participants were entitled to receive with respect to their awards. Unit Option Plan. Pursuant to our Common Unit Option Plan our and our affiliates' key personnel are eligible to receive grants of options to acquire units. The total number of units available under the option plan is 250,000. None of the options granted under the option plan may be "incentive stock options" under Section 422 of the Internal Revenue Code. If an option expires without being exercised, the number of units covered by such option will be available for a future award. The exercise price for an option may not be less than the fair market value of a unit on the date of grant. Either the board of directors of our general partner or a committee of the board of directors will administer the option plan. The option plan terminates on March 5, 2008. No individual employee may be granted options for more than 10,000 units in any year. Our board of directors or the committee will determine the duration and vesting of the options to employees at the time of grant. As of December 31, 2000, options for 206,800 units were granted to 99 employees of our general partner and our subsidiaries. Forty percent of such options will vest on the first anniversary of the date of grant and twenty percent on each anniversary, thereafter. The options expire seven years from the date of grant. 69 70 The option plan also granted to each of our non-employee directors as of April 1, 1998, an option to acquire 5,000 units at an exercise price equal to the fair market value of the units on such date. In addition, each new non-employee director will receive options to acquire 5,000 units on the first day of the month following his or her election. Under this provision, as of December 31, 2000, options for 15,000 units were granted to our three non-employee directors. Forty percent of such options will vest on the first anniversary of the date of grant and twenty percent on each anniversary, thereafter. The non-employee director options will expire seven years from the date of grant. The following table sets forth certain information at December 31, 2000 and for the fiscal year then ended with respect to unit options granted to the individuals named in the Summary Compensation Table above. Mr. Allison and Mr. Listengart were the only persons named in the Summary Compensation Table that have been granted unit options. No unit options were granted at an option price below fair market value on the date of grant.
Aggregated Unit Option Exercises in 2000, and 2000 Year-End Unit Option Values Number of Units Underlying Unexercised Value of Unexercised Options at In-the-Money Options Units Acquired Value 2000 Year-End at 2000 Year-End(1) Name on Exercise Realized Exercisable Unexercisable Exercisable Unexercisable - ---- -------------- -------- ----------- ------------- ----------- ------------- William V. Allison -- -- 6,000 4,000 $139,125 $ 92,750 Joseph Listengart -- -- 3,000 2,000 $ 65,250 $ 43,500
(1) Calculated on the basis of the fair market value of the underlying units at year-end, minus the exercise price. KMI Option Plan. Under Kinder Morgan, Inc.'s stock option plans, key personnel of KMI and its affiliates, including employees of our general partner and its subsidiaries, are eligible to receive grants of options to acquire shares of common stock of KMI. KMI's board of directors administers this option plan. The primary purpose for granting stock options under this plan to employees of our general partner and our subsidiaries is to provide them with an incentive to increase the value of common stock of KMI. A secondary purpose of the grants is to provide compensation to those employees for services rendered to our subsidiaries and us. The following tables set forth certain information at December 31, 2000 and for the fiscal year then ended with respect to KMI stock options granted to the individuals named in the Summary Compensation Table above. Mr. Dehaemers and Mr. Morgan are the only persons named in the Summary Compensation Table that have been granted KMI stock options during 2000. None of these KMI stock options were granted with an exercise price below the fair market value of the common stock on the date of grant. The options expire 10 years after the date of grant.
KMI Stock Option Grants in 2000 Number of % of Total Potential Realizable Value Securities Options at Assumed Annual Rates Underlying Granted to Exercise of Stock Price Appreciation Options Employees Price Expiration for Option Term(1) Name Granted in 2000 Per Share Date 5% 10% - ---- ---------- ----------- --------- ----------- ----------- ---------- David G. Dehaemers, Jr 150,000 12.8% $33.125 04/20/2010 $3,124,820 $7,918,908 Michael C. Morgan 150,000 12.8% $33.125 04/20/2010 $3,124,820 $7,918,908
(1) The dollar amounts under these columns use the 5% and 10% rates of appreciation prescribed by the Securities and Exchange Commission. The 5% and 10% rates of appreciation would result in per share prices of $53.96 and $85.92, respectively. We express no opinion regarding whether this level of appreciation will be realized and expressly disclaim any representation to that effect. 70 71
Aggregated KMI Stock Option Exercises in 2000, and 2000 Year-End KMI Stock Option Values Number of Shares Underlying Unexercised Value of Unexercised Options at In-the-Money Options Shares Acquired Value 2000 Year-End at 2000 Year-End(1) Name on Exercise Realized Exercisable Unexercisable Exercisable Unexercisable - ---- --------------- -------- ----------- ------------- ----------- ------------- David G. Dehaemers, Jr -- -- 212,500 187,500 $4,632,813 $5,320,313 Michael C. Morgan -- -- 212,500 187,500 $4,632,813 $5,320,313 William V. Allison -- -- 62,500 187,500 $1,773,438 $5,320,313 Joseph Listengart -- -- 43,750 131,250 $1,241,406 $3,724,219
(1) Calculated on the basis of the fair market value of the underlying shares at year-end, minus the exercise price. Cash Balance Retirement Plan. 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 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 are credited with the current fair value of any benefits they have previously accrued through the defined benefit plan. On January 1, 2001, we commenced 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. Interest is credited to the employee's personal retirement account 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. Compensation Committee Interlocks and Insider Participation. We do not have a separate compensation committee. Our general partner's compensation committee, comprised of Mr. Edward O. Gaylord, Mr. Gary L. Hultquist and Mr. Perry M. Waughtal, makes compensation decisions regarding our executive officers. Mr. Richard D. Kinder and Mr. William V. Morgan, who are executive officers of our general partner, participate in the deliberations of the board of directors of our general partner concerning executive officer compensation. Messrs. Kinder and Morgan each receive $1.00 annually in total compensation for services to KMI and us. Directors fees. During 2000, each of the three non-employee members of the board of directors of our general partner was paid an annual retainer of $25,000 in lieu of all attendance fees. Non-employee directors will each receive $10,000 for each quarter in 2001 in which they serve on the board of directors. Employment agreements. In April 2000, Mr. David G. Dehaemers, Jr. and Mr. Michael C. Morgan entered into four-year employment agreements with Kinder Morgan, Inc. and our general partner. Under the employment agreements, each of Mr. Dehaemers, Jr. and Mr. Michael C. Morgan receives an annual base salary of $200,000 and bonuses at the discretion of the compensation committee of our general partner. In connection with the execution of the employment agreements, Messrs. Dehaemers and Morgan no longer participate under our Executive Compensation Plan. In addition, each are prevented from competing with KMI and us for a period of four years from the date of the agreements, provided Mr. Richard D. Kinder or Mr. William V. Morgan continues to serve as chief executive officer of KMI or its successor. A copy of each employment agreement has been filed as an exhibit to this report. 71 72 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The following table sets forth information as of February 15, 2001, regarding (a) the beneficial ownership of (i) our units and (ii) the common stock of Kinder Morgan, Inc., the parent company of our general partner, by all directors of our general partner, each of the named executive officers and all directors and executive officers as a group and (b) all persons known by our general partner to own beneficially more than 5% of our units.
Amount and Nature of Beneficial Ownership(1) Common Units Class B Units KMI Voting Stock ----------------------- ---------------------- ------------------------ Number Percent Number Percent Number Percent of Units(2) of Class of Units(3) of Class of Shares(4) of Class ----------- -------- ----------- -------- ------------ -------- Richard D. Kinder(5) 145,000 * -- -- 23,989,992 20.87% William V. Morgan(6) 2,000 * -- -- 4,500,000 3.92% Edward O. Gaylord(7) 19,000 * -- -- -- -- Gary L. Hultquist(8) 2,500 * -- -- -- -- Perry M. Waughtal 10,000 * -- -- 10,000 * William V. Allison(9) 6,000 * -- -- 85,000 * David G. Dehaemers, Jr.(10) 4,000 * -- -- 197,500 * Joseph Listengart(11) 4,699 * -- -- 49,050 * Michael C. Morgan(12) 2,500 * -- -- 223,500 * Directors and Executive 261,765 * -- -- 29,227,690 25.29% Officers as a group (13 persons)(13) Goldman, Sachs & Co.(14) 4,894,303 7.55% -- -- -- -- Kinder Morgan, Inc.(15) 11,312,000 17.44% 2,656,700 100.00% -- --
*Less than 1% (1) Except as noted otherwise, all units and KMI shares involve sole voting power and sole investment power. (2) As of February 15, 2001, we had 64,861,509 common units issued and outstanding. (3) As of February 15, 2001, we had 2,656,700 class B units issued and outstanding. (4) As of February 15, 2001, Kinder Morgan, Inc. ("KMI") had a total of 114,931,387 shares of outstanding voting common stock. (5) Does not include (a) 2,987 common units owned by Mr. Kinder's spouse, Nancy G. Kinder (b) 463,683 KMI shares held by a Kinder family charitable foundation, a charitable not-for-profit corporation and (c) 2,500 KMI shares held by Mrs. Kinder. Mr. Kinder disclaims any and all beneficial or pecuniary interest in these units and shares. (6) Morgan Associates, Inc., a Kansas corporation, wholly owned by Mr. Morgan, holds the KMI shares. Mr. Morgan may be deemed to own the 4,500,000 KMI shares and thereby shares in the voting and disposition power with Morgan Associates, Inc. (7) Includes options to purchase 4,000 common units exercisable within 60 days of February 15, 2001. (8) Includes options to purchase 2,000 common units exercisable within 60 days of February 15, 2001. (9) Includes options to purchase 6,000 common units and 75,000 KMI shares exercisable within 60 days of February 15, 2001, and includes 10,000 shares of restricted KMI stock, 25% of which vests on each of the first four anniversaries after the date of grant. (10) Includes options to purchase 187,500 KMI shares exercisable within 60 days of February 15, 2001, and includes 10,000 shares of restricted KMI stock, 25% of which vests on each of the first four anniversaries after the date of grant. (11) Includes options to purchase 4,000 common units and 39,050 KMI shares exercisable within 60 days of February 15, 2001, and includes 10,000 shares of restricted KMI stock, 25% of which vests on each of the first four anniversaries after the date of grant. (12) Includes options to purchase 212,500 KMI shares exercisable within 60 days of February 15, 2001, and includes 10,000 shares of restricted KMI stock, 25% of which vests on each of the first four anniversaries after the date of grant. (13) Includes options to purchase 22,000 common units and 656,200 KMI shares exercisable within 60 days of February 15, 2001, and includes 65,000 shares of restricted KMI stock, 25% of which vests on each of the first four anniversaries after the date of grant. (14) As reported on the Schedule 13G/A filed February 13, 2001 by The Goldman Sachs Group, Inc. and Goldman, Sachs & Co. The Goldman Sachs companies report that they have sole voting power over 0 common units, shared voting power over 4,894,303 common units, sole disposition power over 0 common units and shared disposition power over 4,894,303 common units. The Goldman Sachs companies' address is 10 Hanover Square, New York, New York 10005. (15) Kinder Morgan, Inc.'s address is 500 Dallas St., Ste. 1000, Houston, Texas 77002. Common units owned include units owned by KMI and its subsidiaries, including 862,000 common units held by Kinder Morgan G.P., Inc. 72 73 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS GENERAL AND ADMINISTRATIVE EXPENSES Our general partner provides us with general and administrative services and is entitled to reimbursement of all direct and indirect costs related to our business activities. Our general partner incurred general and administrative expenses of $54.4 million in 2000, $30.7 million in 1999 and $38.0 million in 1998. Since K N Energy, Inc. acquired Kinder Morgan (Delaware), Inc. in October 1999, our general partner has shared administrative personnel with KMI to operate both KMI's business and our business. As a result, our general partner's officers, who in some cases may also be officers of KMI, must allocate, in their reasonable and sole discretion, the time our general partner's employees and KMI's employees spend on behalf of KMI and on behalf of us. For 2000, KMI paid our general partner a net payment of $1.0 million in January 2001 as reimbursement for the services of our general partner's employees. Although we believe this amount received from KMI for the services it provided in 2000 fairly reflects the net value of the services performed, the determination of this amount was not the result of arms length negotiations. However, due to the nature of the allocations, this reimbursement may not have exactly matched the actual time and overhead spent. We believe the agreed-upon amount was a reasonable allocation of the expenses for the services rendered. Our general partner and KMI will continue to evaluate the net amount to be charged for the services provided to KMI and us by the employees of our general partner and KMI. PARTNERSHIP DISTRIBUTIONS See Item 7. for information regarding Partnership Distributions. ASSET ACQUISITIONS Effective December 31, 2000, we acquired over $300 million of assets from KMI. As consideration for these assets, we paid to KMI $192.7 million, 640,000 common units and 2,656,700 Class B units. The common units and Class B units were valued at $156.3 million. We acquired Kinder Morgan Texas Pipeline, L.P. and MidCon NGL Corp., 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 not the result of arms length negotiation, but 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 KMIGT, 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, KMIGT 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. For 2000, this amount was $6.1 million. For 2001, the amount will increase to $9.6 million due to the addition of the natural gas assets acquired from KMI in December 2000. See "Asset Acquisitions" discussed above. Although we believe the amount paid to KMI for the services provided by them in 2000 fairly reflects the value of the services performed, the determination of this amount was not the result of arms length negotiation. However, due to the nature of the allocations, this reimbursement may not have exactly matched the actual time and overhead spent. We believe the agreed-upon amount was, 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 subsidiaries in performing such services. We also reimburse KMI and its 73 74 subsidiaries for operating and maintenance costs and capital expenditures incurred with respect to these assets. OTHER Our general partner makes all decisions relating to the management of our business, and KMI owns all the common stock of our general partner. Certain conflicts of interest could arise as a result of the relationships among 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, our general partner has a fiduciary duty to manage us in a manner beneficial to our unitholders. The partnership agreements contain provisions that allow our general partner 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 our general partner to our unitholders. Our general partner's Conflicts and Audit Committee of the board of directors will, at the request of our general partner, 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. 74 75 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a)(1) AND (2) FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES Financial Statements - See "Index to Financial Statements" set forth on page F-1. Financial Statement Schedules KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES SCHEDULE II. - VALUATION AND QUALIFYING ACCOUNTS (In Thousands)
Year Ended December 31, 2000 ----------------------------------------------------------------------------------- Balance at Additions Balance at Beginning of Charged to costs Charged to End of Period and expenses other accounts(1) Deductions(2) Period ------------ ---------------- ----------------- ------------- ---------- Allowance for Doubtful Accounts $ 6,717 $ -- $ 2,718 $(5,284) $ 4,151
(1) Additions represent the allowance recognized when we acquired our Natural Gas Pipelines. (2) Deductions represent the write-off of receivables and the revaluation of the allowance account.
Year Ended December 31, 1999 ---------------------------------------------------------------------------------- Balance at Additions Balance at Beginning of Charged to costs Charged to End of Period and expenses other accounts Deductions(1) Period ------------ ---------------- -------------- ------------- ---------- Allowance for Doubtful Accounts $ 9,883 $ -- $ -- $(3,166) $ 6,717
(1) Deductions represents the write-off of receivables and the revaluation of the allowance account.
Year Ended December 31, 1998 -------------------------------------------------------------------------------------------- Balance at Additions Balance at Beginning of Charged to costs Charged to End of Period and expenses other accounts(1) Deductions Period ------------ ---------------- ----------------- ---------- ---------- Allowance for Doubtful Accounts $ -- $ -- $9,883 $ -- $9,883
(1) Additions of $5,441 represent the allowance recognized when we acquired our Pacific operations and our Bulk Terminals. Additions of $4,442 represent a revaluation of the allowance account. (a)(3) EXHIBITS *2.1 - Stock Purchase Agreement dated November 30, 2000 between GATX Rail Corporation, GATX Terminals Holding Corporation and Kinder Morgan Energy Partners, L.P. (filed as Exhibit 99(b) to the Partnership's Current Report on Form 8-K filed December 1, 2000) *3.1 - Second Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. effective as of February 14, 1997 (filed as Exhibit 3.1 to Amendment No. 1 to Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-4, file No. 333-46709, filed on April 14, 1998) 75 76 *3.2 - Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. dated as of January 20, 2000 (filed as Exhibit 4.1 to the Partnership's Current Report on Form 8-K filed January 20, 2000). 3.3 - Amendment No. 2 to Second Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. dated as of December 21, 2000. *4.1 - Specimen Certificate evidencing Common Units representing Limited Partner Interests (filed as Exhibit 4.1 to Amendment No. 1 to Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-4, file No. 333-44519, filed on February 4, 1998). *4.2 - Indenture dated as of January 29, 1999 among Kinder Morgan Energy Partners, L.P., the guarantors listed on the signature page thereto and U.S. Trust Company of Texas, N.A., as trustee, relating to Senior Debt Securities (filed as Exhibit 4.1 to the Partnership's Current Report on Form 8-K filed February 16, 1999 (the "February 16, 1999 Form 8-K")). *4.3 - First Supplemental Indenture dated as of January 29, 1999 among Kinder Morgan Energy Partners, L.P., the subsidiary guarantors listed on the signature page thereto and U.S. Trust Company of Texas, N.A., as trustee, relating to $250,000,000 of 6.30% Senior Notes due February 1, 2009 (filed as Exhibit 4.2 to the February 16, 1999 Form 8-K). *4.4 - Second Supplemental Indenture dated as of September 30, 1999 among Kinder Morgan Energy Partners, L.P. and U.S. Trust Company of Texas, N.A., as trustee, relating to release of subsidiary guarantors under the $250,000,000 of 6.30% Senior Notes due February 1, 2009 (filed as Exhibit 4.4 to the Partnership's Form 10-Q for the quarter ended September 30, 1999 (the "1999 Third Quarter Form 10-Q")). *4.5 - Indenture dated March 22, 2000 between Kinder Morgan Energy Partners and First Union National Bank, as Trustee (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-4 (file no. 333-35112) filed on April 19, 2000 (the "April 2000 Form S-4")). *4.6 - Form of Floating Rate Note and Form of 8% Note (contained in the Indenture filed as Exhibit 4.1 to the April 2000 Form S-4). *4.7 - Registration Rights Agreement dated March 22, 2000 among Kinder Morgan Energy Partners, Goldman, Sachs & Co., Merrill Lynch & Co., Banc of America Securities LLC and First Union Securities, Inc. (filed as Exhibit 4.3 to the April 2000 Form S-4). 4.8 - Indenture dated November 8, 2000 between Kinder Morgan Energy Partners and First Union National Bank, as Trustee. 4.9 - Form of 7.50% Note (contained in the Indenture filed as Exhibit 4.8). 4.10 - Registration Rights Agreement dated November 8, 2000 between Kinder Morgan Energy Partners and Banc of America Securities LLC. 4.11 - Indenture dated January 2, 2001 between Kinder Morgan Energy Partners and First Union National Bank, as trustee, relating to Senior Debt Securities (including form of Senior Debt Securities). 4.12 - Indenture dated January 2, 2001 between Kinder Morgan Energy Partners and First Union National Bank, as trustee, relating to Subordinate Debt Securities (including form of Subordinate Debt Securities). 4.13 - Certain instruments with respect to long-term debt of the Partnership and its consolidated subsidiaries which relate to debt that does not exceed 10% of the total assets of the Partnership and its consolidated subsidiaries are omitted pursuant to Item 601(b) (4) (iii) (A) of Regulation S-K, 17 C.F.R. Section 229.601. The Partnership hereby agrees to furnish supplementally to the Securities and Exchange Commission a copy of each such instrument upon request. *10.1 - Kinder Morgan Energy Partners, L.P. Common Unit Option Plan (filed as Exhibit 10.6 to the Partnership's 1997 Form 10-K). *10.2 - Employment Agreement with William V. Morgan (filed as Exhibit 10.1 to the Partnership's Form 10-Q for the quarter ended March 31, 1997). *10.3 - Kinder Morgan Energy Partners L.P. Executive Compensation Plan (filed as Exhibit 10 to the Partnership's Form 10-Q for the quarter ended June 30, 1997). *10.4 - 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). *10.5 - 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). 76 77 * 10.6 - Intrastate Pipeline system Lease, dated December 31, 1996, between MidCon Texas Pipeline, L.P. and MidCon Texas Pipeline Operator, Inc. (filed as Exhibit 10(y) to Kinder Morgan, Inc.'s 1997 Form 10-K). * 10.7 - Amendment Number One to Intrastate Pipeline system Lease, dated December 31, 1996, between MidCon Texas Pipeline, L.P. and MidCon Texas Pipeline Operator, Inc. (filed as Exhibit 10(z) to Kinder Morgan, Inc.'s 1997 Form 10-K). 21.1 - List of Subsidiaries. 23.1 - Consent of PricewaterhouseCoopers LLP. - --------- * Asterisk indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith. (b) REPORTS ON FORM 8-K Report dated November 6, 2000, on Form 8-K was filed on November 6, 2000, pursuant to Item 9 of that form. Notice that on November 6, 2000, Kinder Morgan, Inc., a subsidiary of which serves as general partner of Kinder Morgan Energy Partners, L. P., and the Partnership intend to make a presentation to a group of analysts and others to address various strategic and financial issues relating to the business plans and objectives of Kinder Morgan, Inc. and the Partnership was disclosed pursuant to Item 9. Furthermore, notice was given that Kinder Morgan, Inc. and the Partnership maintain a web site at www.kindermorgan.com, on which Kinder Morgan, Inc. and the Partnership have posted the materials furnished pursuant to this Item 9. A copy of the visual portion of the materials to be presented and discussed at the meeting was furnished as an exhibit and was incorporated by reference into this Item 9. Report dated November 30, 2000, on Form 8-K was filed on December 1, 2000, pursuant to Items 5, 7 and 9 of that form. Notice of a press release announcing a definitive agreement with GATX to acquire its U.S. pipeline and terminal businesses was disclosed pursuant to Item 5. The press release and Stock Purchase Agreement between GATX Rail Corporation, GATX Terminals Holding Corporation and Kinder Morgan Energy Partners, L.P. were filed as exhibits pursuant to Item 7. Notice of a live web cast conference call on December 1, 2000, with a group of analysts and others to discuss the proposed purchase by the Partnership of GATX Corporation's U.S. pipeline and terminal businesses, and various strategic and financial issues relating to the business plans and objectives of Kinder Morgan, Inc. and the Partnership was disclosed pursuant to Item 9. Report dated December 7, 2000, on Form 8-K was filed on December 7, 2000, pursuant to Items 5 and 7 of that form. Notice that on December 4, 2000, the Partnership issued a press release announcing that it has purchased Delta Terminal Services, Inc. for approximately $114 million in cash was disclosed pursuant to Item 5. A copy of the press release was disclosed as an exhibit pursuant to Item 7. 77 78 INDEX TO FINANCIAL STATEMENTS
Page ---- KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES Report of Independent Accountants F-2 Consolidated Statements of Income for the years ended December 31, 2000, 1999, and 1998 F-3 Consolidated Balance Sheets for the years ended December 31, 2000 and 1999 F-4 Consolidated Statements of Cash Flows for the years ended December 31, 2000, 1999, and 1998 F-5 Consolidated Statements of Partners' Capital for the years ended December 31, 2000, 1999, and 1998 F-6 Notes to Consolidated Financial Statements F-7
Certain supplementary financial statement schedules have been omitted because the information required to be set forth therein is either not applicable or is shown in the financial statements or notes thereto. F-1 79 REPORT OF INDEPENDENT ACCOUNTANTS To the Partners of Kinder Morgan Energy Partners, L.P. In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of cash flows and of partners' capital present fairly, in all material respects, the financial position of Kinder Morgan Energy Partners, L.P. and its subsidiaries (the Partnership) at December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000 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 75, 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. PricewaterhouseCoopers LLP Houston, Texas February 14, 2001 F-2 80 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (In Thousands Except Per Unit Amounts)
Year Ended December 31, --------------------------------------- 2000 1999 1998 --------- --------- --------- Revenues Services $ 653,968 $ 393,131 $ 301,671 Product sales and other 162,474 35,618 20,946 --------- --------- --------- 816,442 428,749 322,617 --------- --------- --------- Costs and Expenses Cost of products sold 124,641 16,241 5,860 Operations and maintenance 164,379 95,121 65,022 Fuel and power 43,216 31,745 22,385 Depreciation and amortization 82,630 46,469 36,557 General and administrative 60,065 35,612 39,984 Taxes, other than income taxes 25,950 16,154 12,140 --------- --------- --------- 500,881 241,342 181,948 --------- --------- --------- Operating Income 315,561 187,407 140,669 Other Income (Expense) Earnings from equity investments 71,603 42,918 25,732 Amortization of excess cost of equity investments (8,195) (4,254) (764) Interest, net (93,284) (52,605) (38,600) Other, net 14,584 14,085 (7,263) Gain on sale of equity interest, net of special charges -- 10,063 -- Minority Interest (7,987) (2,891) (985) --------- --------- --------- Income Before Income Taxes and Extraordinary Charge 292,282 194,723 118,789 Income Taxes (13,934) (9,826) (1,572) Income Before Extraordinary Charge 278,348 184,897 117,217 Extraordinary Charge on Early Extinguishment of Debt -- (2,595) (13,611) --------- --------- --------- Net Income $ 278,348 $ 182,302 $ 103,606 ========= ========= ========= Calculation of Limited Partners' Interest in Net Income: Income Before Extraordinary Charge $ 278,348 $ 184,897 $ 117,217 Less: General Partner's interest in Net Income (109,470) (56,273) (33,447) --------- --------- --------- Limited Partners' Net Income before Extraordinary Charge 168,878 128,624 83,770 Less: Extraordinary Charge on Early Extinguishment of Debt -- (2,595) (13,611) --------- --------- --------- Limited Partners' Net Income $ 168,878 $ 126,029 $ 70,159 ========= ========= ========= Basic Limited Partners' Net Income per Unit: Income before Extraordinary Charge $ 2.68 $ 2.63 $ 2.09 Extraordinary Charge -- (.06) (.34) --------- --------- --------- Net Income $ 2.68 $ 2.57 $ 1.75 ========= ========= ========= Weighted Average Units Outstanding 63,106 48,974 40,120 ========= ========= ========= Diluted Limited Partners' Net Income per Unit: Income before Extraordinary Charge $ 2.67 $ 2.63 $ 2.09 Extraordinary Charge -- (.06) (.34) --------- --------- --------- Net Income $ 2.67 $ 2.57 $ 1.75 ========= ========= ========= Weighted Average Units Outstanding 63,150 48,993 40,121 ========= ========= =========
The accompanying notes are an integral part of these consolidated financial statements. F-3 81 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In Thousands)
December 31, ------------------------- 2000 1999 ---------- ---------- ASSETS Current Assets Cash and cash equivalents $ 59,319 $ 40,052 Accounts and notes receivable Trade 345,065 71,738 Related parties 3,384 45 Inventories Products 24,137 8,380 Materials and supplies 4,972 4,703 Gas imbalances 26,878 7,014 Gas in underground storage 27,481 -- Other current assets 20,025 -- ---------- ---------- 511,261 131,932 ---------- ---------- Property, Plant and Equipment, net 3,306,305 2,578,313 Investments 417,045 418,651 Notes receivable 9,101 10,041 Intangibles, net 345,305 56,630 Deferred charges and other assets 36,193 33,171 ---------- ---------- TOTAL ASSETS $4,625,210 $3,228,738 ========== ========== LIABILITIES AND PARTNERS' CAPITAL Current Liabilities Accounts payable Trade $ 293,268 $ 15,692 Related parties 8,255 3,569 Current portion of long-term debt 648,949 209,200 Accrued rate refunds 1,100 36,607 Deferred Revenues 43,978 -- Gas imbalances 48,834 6,189 Accrued other liabilities 54,572 47,904 ---------- ---------- 1,098,956 319,161 ---------- ---------- Long-Term Liabilities and Deferred Credits Long-term debt 1,255,453 989,101 Other 95,565 97,379 ---------- ---------- 1,351,018 1,086,480 ---------- ---------- Commitments and Contingencies (Notes 13 and 16) Minority Interest 58,169 48,299 ---------- ---------- Partners' Capital Common Units (64,858,109 and 59,137,137 units issued and outstanding at December 31, 2000 and 1999, respectively) 1,957,357 1,759,142 Class B Units (2,656,700 and 0 units issued and outstanding at December 31, 2000 and 1999, respectively) 125,961 -- General Partner 33,749 15,656 ---------- ---------- 2,117,067 1,774,798 ---------- ---------- TOTAL LIABILITIES AND PARTNERS' CAPITAL $4,625,210 $3,228,738 ========== ==========
The accompanying notes are an integral part of these consolidated financial statements. F-4 82 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (In Thousands)
Year Ended December 31, --------------------------------------------- 2000 1999 1998 ----------- ----------- ----------- Cash Flows From Operating Activities Reconciliation of net income to net cash provided by operating activities Net income $ 278,348 $ 182,302 $ 103,606 Extraordinary charge on early extinguishment of debt -- 2,595 13,611 Depreciation and amortization 82,630 46,469 36,557 Amortization of excess cost of equity investments 8,195 4,254 764 Earnings from equity investments (71,603) (42,918) (25,732) Distributions from equity investments 47,512 33,686 19,670 Gain on sale of equity interest, net of special charges -- (10,063) -- Changes in components of working capital Accounts receivable 6,791 (12,358) 1,203 Other current assets (6,872) -- -- Inventories (1,376) (2,817) (734) Accounts payable (8,374) (9,515) 197 Accrued liabilities 26,479 11,106 (14,115) Accrued taxes (1,302) 497 (1,266) Rate refunds settlement (52,467) -- -- El Paso settlement -- -- (8,000) Other, net (6,394) (20,382) 8,220 ----------- ----------- ----------- Net Cash Provided by Operating Activities 301,567 182,856 133,981 ----------- ----------- ----------- Cash Flows From Investing Activities Acquisitions of assets (1,008,648) 5,678 (107,144) Additions to property, plant and equipment for expansion and maintenance projects (125,523) (82,725) (38,407) Sale of investments, property, plant and equipment, net of removal costs 13,412 43,084 64 Acquisitions of investments (79,388) (161,763) (135,000) Other 2,581 (800) (1,234) ----------- ----------- ----------- Net Cash Used in Investing Activities (1,197,566) (196,526) (281,721) ----------- ----------- ----------- Cash Flows From Financing Activities Issuance of debt 2,928,304 550,287 492,612 Payment of debt (1,894,904) (333,971) (407,797) Debt issue costs (4,298) (3,569) (16,768) Proceeds from issuance of common units 171,433 68 212,303 Contributions from General Partner's minority interest 7,434 146 12,349 Distributions to partners Common units (194,691) (135,835) (93,352) General Partner (91,366) (52,674) (27,450) Minority interest (7,533) (2,316) (1,614) Other, net 887 (149) (420) ----------- ----------- ----------- Net Cash Provided by Financing Activities 915,266 21,987 169,863 ----------- ----------- ----------- Increase in Cash and Cash Equivalents 19,267 8,317 22,123 Cash and Cash Equivalents, beginning of period 40,052 31,735 9,612 ----------- ----------- ----------- Cash and Cash Equivalents, end of period $ 59,319 $ 40,052 $ 31,735 =========== =========== =========== Noncash Investing and Financing Activities: Contribution of net assets to partnership investments $ -- $ 20 $ 60,387 Assets acquired by the issuance of units 179,623 420,850 1,003,202 Assets acquired by the assumption of liabilities 333,301 111,509 569,822 Supplemental disclosures of cash flow information: Cash paid during the year for Interest (net of capitalized interest) 88,821 48,222 47,616 Income taxes 1,806 529 1,354
The accompanying notes are an integral part of these consolidated financial statements. F-5 83 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL (Dollars in Thousands)
Total Common Units Class B Units General Partners' Units Amount Units Amount Partner Capital ---------- ----------- --------- ----------- ----------- ----------- Partners' capital at December 31, 1997 14,111,200 $ 146,840 -- $ -- $ 3,384 $ 150,224 Net income -- 70,159 -- -- 33,447 103,606 Net proceeds from issuance of common units 34,740,490 1,213,372 -- -- -- 1,213,372 Capital contributions -- 10,234 -- -- 2,678 12,912 Distributions -- (91,063) -- -- (27,437) (118,500) Repurchases (30,000) (951) -- -- -- (951) ---------- ----------- --------- ----------- ----------- ----------- Partners' capital at December 31, 1998 48,821,690 1,348,591 -- -- 12,072 1,360,663 Net income -- 126,029 -- -- 56,273 182,302 Net proceeds from issuance of common units 10,322,147 420,678 -- -- (15) 420,663 Distributions -- (135,835) -- -- (52,674) (188,509) Repurchases (6,700) (321) -- -- -- (321) ---------- ----------- --------- ----------- ----------- ----------- Partners' capital at December 31, 1999 59,137,137 1,759,142 -- -- 15,656 1,774,798 Net income -- 168,878 -- -- 109,470 278,348 Net proceeds from issuance of units 5,720,972 224,028 2,656,700 125,961 (11) 349,978 Distributions -- (194,691) -- -- (91,366) (286,057) ---------- ----------- --------- ----------- ----------- ----------- Partners' capital at December 31, 2000 64,858,109 $ 1,957,357 2,656,700 $ 125,961 $ 33,749 $ 2,117,067 ========== =========== ========= =========== =========== ===========
The accompanying notes are an integral part of these consolidated financial statements. F-6 84 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 Master Limited Partnership managing a diversified portfolio of midstream energy assets consisting of refined petroleum product pipelines, natural gas pipelines, carbon dioxide pipelines and bulk material terminals that provide fee-based services to customers. Customers contract with us to provide transportation of refined petroleum products, natural gas and carbon dioxide through our pipelines and to transfer materials principally between railway cars and waterborne vessels at our bulk terminal sites. We trade under the New York Stock Exchange symbol "KMP" and presently conduct our business through four reportable business segments: o Product Pipelines; o Natural Gas Pipelines; o CO2 Pipelines; and o Bulk Terminals. Acquisitions in 2000 required a reevaluation of our previously reported Pacific Operations, Mid-Continent Operations, Natural Gas Operations and Bulk Terminals business segments. Our previous Pacific Operations segment, previous Mid-Continent Operations segment, with the exception of our Mid-Continent's natural gas liquids separation activities and carbon dioxide pipeline transportation activities, and our 32.5% interest in the Cochin Pipeline System, acquired in the fourth quarter of 2000, have been combined to present our current Product Pipelines segment. Our prior interest in the Mont Belvieu fractionation facility has been combined with our acquisition of certain assets from Kinder Morgan, Inc., effective December 31, 1999 and December 31, 2000, to present our current Natural Gas Pipelines segment. Finally, due to our acquisition of the remaining 80% of Kinder Morgan CO2 Company, L.P., effective April 1, 2000, we began reporting the CO2 Pipelines segment. Prior to April 1, 2000, we only owned a 20% equity interest in Shell CO2 Company, Ltd. and reported its results under the equity method of accounting in the Mid-Continent Operations. Other than acquisitions made during 2000, there was no change in our Bulk Terminals business segment. See note 3 for more information on these acquisitions and note 15 for financial information on these segments. 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 generating 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 America, operating more than 30,000 miles of natural gas and product pipelines. KMI also has significant retail distribution, electric generation and terminal assets. KMI, through its subsidiary Kinder Morgan (Delaware), Inc., remains the sole stockholder of our general partner. KMI also owns approximately 20.7% of our outstanding units. 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. USE OF ESTIMATES The preparation of our financial statements in conformity with generally accepted accounting principles requires our management to make estimates and assumptions that affect: F-7 85 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS o the amounts we report for assets and liabilities; o our disclosure of contingent assets and liabilities at the date of the financial statements; and o the amounts we report for revenues and expenses during the reporting period. Actual results could differ from those estimates. 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. GAS IMBALANCES We value gas imbalances due to or due from shippers and operators at the appropriate index price. Gas imbalances represent the difference between gas receipts from and gas deliveries to our transportation and storage customers. Gas imbalances arise when these customers deliver more or less gas into the pipeline than they take out. Natural gas imbalances are settled in cash or made up in-kind subject to the pipelines' various terms. 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 and oil 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 account for our interests in carbon dioxide and oil properties under the successful efforts method of accounting. 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. 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 We amortize our 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. We amortize this excess for undervalued F-8 86 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 report amortization of excess cost over fair value of net assets (goodwill) as amortization expense in our accompanying consolidated statement of income. For our investments accounted for under the equity method, we report amortization of excess cost on investments as amortization of excess cost of equity investments in our accompanying consolidated statement of income. Our total unamortized excess cost over fair value of net assets on investments in consolidated affiliates was approximately $158.1 million as of December 31, 2000 and $48.6 million as of December 31, 1999. These amounts are included within intangibles on our accompanying consolidated balance sheet. Our total unamortized excess cost over underlying book value of net assets on investments accounted for under the equity method was approximately $350.2 million as of December 31, 2000 and $273.5 million as of December 31, 1999. 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 this time, we believe no such impairment has occurred and no reduction in estimated useful lives is warranted. 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 transmix processing revenues based on volumes processed or sold, and if applicable, title has passed. We recognize energy-related product sales revenues based on delivered quantities of product. 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: o the 1.0101% general partner interest in our operating partnerships; o the 0.5% special limited partner interest in SFPP, L.P.; o the 33 1/3% interest in Trailblazer Pipeline Company; o the 50% interest in Globalplex Partners, a Louisiana joint venture owned 50% and controlled by Kinder Morgan Bulk Terminals, Inc.; and o 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 or 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 F-9 87 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 Due to the absence of items of other comprehensive income, our comprehensive income equaled our net income in each of the periods presented. 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. 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. 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 for us on January 1, 2001. See note 14 for more information on our risk management activities. 3. ACQUISITIONS AND JOINT VENTURES During 1998, 1999 and 2000, 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. PRODUCT PIPELINES Santa Fe On March 6, 1998, we acquired 99.5% of SFPP, L.P., the operating partnership of Santa Fe Pacific Pipeline Partners, L.P. SFPP owns our Pacific operations. The transaction was valued at more than $1.4 billion inclusive of liabilities assumed. We acquired the interest of Santa Fe Pacific Pipeline's common unitholders in SFPP in exchange for approximately 26.6 million units (1.39 of our units for each Santa Fe Pacific Pipeline common unit). In addition, we paid $84.4 million to Santa Fe Pacific Pipelines, Inc. in exchange for the general partner interest in Santa Fe Pacific Pipeline Partners, L.P. Also on March 6, 1998, SFPP redeemed from Santa Fe Pacific Pipelines, Inc. a 0.5% interest in SFPP for $5.8 million. The redemption was paid from SFPP's cash reserves. After the redemption, Santa Fe Pacific Pipelines, Inc. continues to own a 0.5% special limited partner interest in SFPP. Assets acquired in this transaction comprise our Pacific operations, which include over 3,300 miles of pipeline and thirteen owned and operated terminals. Plantation Pipe Line Company On September 15, 1998, we acquired an approximate 24% interest in Plantation Pipe Line Company for $110 million. On June 16, 1999, we acquired an additional approximate 27% interest in Plantation Pipe Line Company for $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 F-10 88 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Company, and therefore, we account for our investment in Plantation under the equity method of accounting. 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 $18.3 million (before purchase price adjustments) and 510,147 units valued at approximately $14.3 million. 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 $8.3 million for net working capital and other items. 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, including working capital purchase price adjustments. 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. 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. We record our proportional share of joint venture revenues and expenses and cost of joint venture assets as part of our Product Pipelines business segment. NATURAL GAS PIPELINES 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 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 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 under the equity method of accounting. Effective December 31, 1999, following our acquisition of an additional 33 1/3% interest in Trailblazer, which is discussed below, we included Trailblazer's activities as part of our consolidated financial statements. Kinder Morgan, Inc. Asset Contributions Effective December 31, 1999, we acquired over $700 million of assets from KMI. We paid to KMI $330 million and 9.81 million units, valued at approximately $406.5 million as consideration for the assets. We acquired Kinder Morgan Interstate Gas Transmission LLC (formerly K N Interstate Gas Transmission Co.), a 33 1/3% interest in Trailblazer and a 49% equity interest in Red Cedar Gathering Company. The acquired interest in Trailblazer, 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 $300 million of assets from KMI. As consideration for these assets, we paid to KMI $192.7 million, 640,000 common units and 2,656,700 Class B units. The units were valued at $156.3 million. We acquired Kinder Morgan Texas Pipeline, Inc. 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. F-11 89 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS CO2 PIPELINES Kinder Morgan CO2 Company, L.P. On March 5, 1998, we and affiliates of Shell Oil Company agreed to combine our carbon dioxide activities and assets into a partnership, Shell CO(2) Company, Ltd., to be operated by a Shell affiliate. We acquired a 20% interest in Shell CO2 Company, Ltd. in exchange for contributing our Central Basin Pipeline and approximately $25 million in cash. Effective April 1, 2000, we acquired the remaining 78% limited partner interest and the 2% general partner interest in Shell CO2 Company, Ltd. from Shell for $212.1 million. We renamed the limited partnership Kinder Morgan CO2 Company, L.P., and going forward from April 1, 2000, we have included its results as part of our consolidated financial statements under our CO2 Pipelines business segment. As is the case with all of our operating partnerships, we own a 98.9899% limited partner ownership interest in KMCO2 and our general partner owns a direct 1.0101% general partner ownership interest. Other Acquisitions and Joint Ventures 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 $55 million, before purchase price adjustments. Included in the acquisition was an approximate 81% equity interest in the Canyon Reef Carriers CO2 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. On December 28, 2000, we announced that KMCO2 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 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 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 KMCO2 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 will account for this investment under the equity method. BULK TERMINALS Hall-Buck Marine, Inc. Effective July 1, 1998, we acquired Hall-Buck Marine, Inc. for approximately $100 million. Hall-Buck, headquartered in Sorrento, Louisiana, is one of the nation's largest independent operators of dry bulk terminals. In addition, Hall-Buck owns all of the common stock of River Consulting Incorporated, a nationally recognized leader in the design and construction of bulk material facilities and port related structures. The $100 million of consideration consisted of approximately 2.1 million units and assumed indebtedness of $23 million. After the acquisition, we changed the name of Hall-Buck Marine, Inc. to Kinder Morgan Bulk Terminals, Inc. 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 $24.1 million, including 574,172 units and approximately $0.8 million in cash. The Milwaukee terminal, 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 salt and grain products. F-12 90 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Delta Terminal Services, Inc. Effective December 1, 2000, we acquired all of the shares of the capital stock of Delta Terminal Services, Inc. for approximately $114.1 million. The acquisition includes two liquid bulk storage terminals in New Orleans, Louisiana and Cincinnati, Ohio. PRO FORMA INFORMATION The following summarized unaudited Pro Forma Consolidated Income Statement information for the twelve months ended December 31, 2000 and 1999, assumes the 2000 and 1999 acquisitions and joint ventures had occurred as of January 1, 1999. 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 2000 and 1999 acquisitions and joint ventures as of January 1, 1999 or the results which will be attained in the future. Amounts presented below are in thousands, except for the per unit amounts:
Pro Forma Twelve Months Ended December 31, 2000 1999 ------------- ------------- Income Statement (Unaudited) Revenues $ 2,954,180 $ 1,806,453 Operating Income 393,982 350,075 Net Income before extraordinary charge 334,817 290,134 Net Income 334,817 287,539 Basic Limited Partners' Net Income per unit before extraordinary charge $ 2.82 $ 2.63 Basic Limited Partners' Net Income per unit $ 2.82 $ 2.59 Diluted Limited Partners' Net Income per unit before extraordinary charge $ 2.81 $ 2.63 Diluted Limited Partners' Net Income per unit $ 2.81 $ 2.59
Acquisitions Subsequent to December 31, 2000 On November 30, 2000, we announced that we had signed a definitive agreement with GATX Corporation to purchase its United States' pipeline and terminal businesses for approximately $1.15 billion, consisting of cash, assumed debt and other obligations. Primary assets included in the transaction are the CALNEV Pipe Line Company, the Central Florida Pipeline Company and twelve terminals that store refined petroleum products and chemicals. The transaction closed March 1, 2001, except for CALNEV, which closed on March 30, 2001. 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 Product Pipelines business segment, and a charge of $0.4 million relating to prior years' over-billed storage tank lease fees, also within our Product 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): F-13 91 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Year Ended December 31, 2000 1999 1998 ------- ------- ------- Taxes currently payable: Federal $10,612 $ 8,169 $ 1,432 State 1,416 1,002 168 ------- ------- ------- Total 12,028 9,171 1,600 Taxes deferred: Federal 1,627 583 (25) State 279 72 (3) ------- ------- ------- Total 1,906 655 (28) ------- ------- ------- Total tax provision $13,934 $ 9,826 $ 1,572 ======= ======= ======= Effective tax rate 4.8% 5.0% 1.3%
The difference between the statutory federal income tax rate and our effective income tax rate is summarized as follows:
Year Ended December 31, 2000 1999 1998 ---- ---- ---- Federal Income Tax Rate 35.0% 35.0% 35.0% Increase (Decrease) as a Result of: Partnership earnings not subject to tax (35.0)% (35.3)% (35.4)% Corporate subsidiary earnings subject to tax 0.6% 1.0% 0.8% Income tax expense attributable to corporate equity earnings 4.1% 4.4% 1.6% Gain on distribution of appreciated property from corporate subsidiary -- -- 3.7% Utilization of net operating loss -- -- (1.0)% Utilization of alternative minimum tax credits -- -- (1.5)% Prior year adjustments -- -- (2.0)% State taxes 0.1% 0.1% 0.5% Other -- (0.2)% (0.4)% ---- ---- ---- Effective Tax Rate 4.8% 5.0% 1.3% ==== ==== ====
Deferred tax assets and liabilities result from the following (in thousands):
December 31, 2000 1999 ------ ------ Deferred tax assets: State taxes $ 184 $ -- Book accruals 176 1,110 Alternative minimum tax credits 1,376 1,376 ------ ------ Total deferred tax assets 1,736 2,486 Deferred tax liabilities: Property, plant and equipment 4,223 3,323 Book accruals -- 661 Other -- 2 ------ ------ Total deferred tax liabilities 4,223 3,986 ------ ------ Net deferred tax liabilities $2,487 $1,500 ====== ======
F-14 92 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS We had available, at December 31, 2000, approximately $1.4 million of alternative minimum tax credit carryforwards, which are available indefinitely. 6. PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment consists of the following (in thousands):
December 31, --------------------------- 2000 1999 ----------- ----------- Natural Gas, liquids and carbon dioxide pipelines $ 1,732,607 $ 1,729,034 Natural Gas, liquids and carbon dioxide pipeline station equip. 1,072,185 550,044 Coal and bulk tonnage transfer, storage and services 191,313 107,052 Natural Gas and transmix processing 95,624 45,232 Land 79,653 72,259 Land right-of-way 116,456 93,909 Construction work in process 90,067 38,653 Other 117,981 59,939 ----------- ----------- Total cost 3,495,886 2,696,122 Accumulated depreciation and depletion (189,581) (117,809) ----------- ----------- $ 3,306,305 $ 2,578,313 =========== ===========
Depreciation and depletion expense charged against property, plant and equipment consists of the following (in thousands):
2000 1999 1998 --------- -------- -------- Depreciation and depletion expense $ 79,740 $ 44,553 $ 35,288
7. INVESTMENTS Our significant equity investments at December 31, 2000 consisted of: o Plantation Pipe Line Company (51%); o Red Cedar Gathering Company (49%); o Thunder Creek Gas Services, LLC (25%); o Coyote Gas Treating, LLC (Coyote Gulch) (50%); o Cortez Pipeline Company (50%); and o 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 CO2 Company, Ltd. and renamed the entity Kinder Morgan CO2 Company, L.P. (KMCO2). 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 effective December 31, 1999. We acquired our investment in Cortez as part of our KMCO2 acquisition and we acquired our investments in Coyote Gas Treating and Thunder Creek from KMI on December 31, 2000. Please refer to notes 3 and 4 for more information. F-15 93 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Our total equity investments consisted of the following (in thousands):
December 31, 2000 1999 ---------- ---------- Plantation Pipe Line Company $ 223,627 $ 229,349 Red Cedar Gathering Company 96,388 88,249 Thunder Creek Gas Services, LLC 27,625 -- Coyote Gas Treating, LLC 17,000 -- Cortez Pipeline Company 9,559 -- Heartland Pipeline Company 6,025 4,818 Shell CO2 Company, Ltd. -- 86,675 Colton Transmix Processing Facility -- 5,263 All Others 2,658 4,297 ---------- ---------- Total Equity Investments $ 382,882 $ 418,651 Investment in oil and gas assets to be contributed to joint venture 34,163 -- ---------- ---------- Total Investments $ 417,045 $ 418,651 ========== ==========
Our earnings from equity investments were as follows (in thousands):
Year ended December 31, 2000 1999 1998 ---------- ---------- ---------- Plantation Pipe Line Company $ 31,509 $ 22,510 $ 4,421 Cortez Pipeline Company 17,219 -- -- Red Cedar Gathering Company 16,110 -- -- Shell CO2 Company, Ltd. 3,625 14,500 14,500 Colton Transmix Processing Facility 1,815 1,531 803 Heartland Pipeline Company 1,581 1,571 1,394 Coyote Gas Treating, LLC -- -- -- Thunder Creek Gas Services, LLC -- -- -- Mont Belvieu Associates -- 2,500 4,577 Trailblazer Pipeline Company (24) 284 -- All Others (232) 22 37 ---------- ---------- ---------- Total $ 71,603 $ 42,918 $ 25,732 ========== ========== ========== Amortization of excess costs $ (8,195) $ (4,254) $ (764) ========== ========== ==========
F-16 94 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Summarized combined unaudited financial information for our significant equity investments is reported below (in thousands):
Year ended December 31, Income Statement 2000 1999 1998 ----------- ---------- ----------- Revenues $ 399,335 $ 344,017 $ 236,534 Costs and expenses 276,000 244,515 148,616 Earnings before extraordinary items 123,335 99,502 87,918 Net income 123,335 99,502 87,918
December 31, Balance Sheet 2000 1999 ----------- ----------- Current assets $ 117,050 $ 137,828 Non-current assets 665,435 450,791 Current liabilities 92,027 64,333 Non-current liabilities 576,278 289,671 Partners'/Owners' equity 114,180 234,615
On December 28, 2000, we announced that KMCO2 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 KMCO2 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 will account for this investment under the equity method. 8. INTANGIBLES Our intangible assets include value associated with acquired: o goodwill; o contracts and agreements; and o intangible lease value associated with our acquisition of Kinder Morgan Texas Pipeline, L.P. on December 31, 2000. All of our intangible assets are amortized on a straight-line basis over their estimated useful lives. Goodwill is being amortized over a period of 40 years. Beginning in 2001, the intangible lease value will be amortized over 26 years, the remaining life of an operating lease covering the use of KMTP's natural gas pipeline. F-17 95 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Intangible assets consisted of the following (in thousands):
December 31, 2000 1999 --------- --------- Goodwill $ 162,271 $ 50,546 Accumulated amortization (4,201) (1,941) --------- --------- Goodwill, net $ 158,070 $ 48,605 Lease value $ 185,982 $ 6,592 Contracts and agreements 1,768 1,768 Other 93 93 --------- --------- Accumulated amortization (608) (428) --------- --------- Other intangibles, net $ 187,235 $ 8,025 --------- --------- Total intangibles, net $ 345,305 $ 56,630 ========= =========
9. DEBT Our debt facilities as of December 31, 2000, consist primarily of: o a $600 million unsecured 364-day credit facility due October 25, 2001; o a $300 million unsecured five-year credit facility due September 29, 2004; o $250 million of 6.30% Senior Notes due February 1, 2009; o $200 million of 8.00% Senior Notes due March 15, 2005; o $250 million of 7.50% Senior Notes due November 1, 2010; o $200 million of Floating Rate Senior Notes due March 22, 2002; o $119 million of Series F First Mortgage Notes (our subsidiary, SFPP, is the obligor on the notes); o $20.2 million of Senior Secured Notes (our subsidiary, Trailblazer, is the obligor on the notes); o $23.7 million of tax-exempt bonds due 2024 (our subsidiary, Kinder Morgan Operating L.P. "B" is the obligor on these bonds); and o a $600 million short-term commercial paper program. Our short-term debt at December 31, 2000, consisted of: o $582 million of borrowings under our unsecured 364-day credit facility due October 25, 2001; o $52 million of commercial paper borrowings; o $35 million under the SFPP 10.7% First Mortgage Notes; and o $14.6 million in other borrowings. During 2000, our cash acquisitions and expansions exceeded $600 million. Historically, we have utilized our short-term credit facilities to fund acquisitions and expansions and then refinanced our short-term borrowings utilizing long-term credit facilities and by issuing equity or long-term debt securities. We intend to refinance our short-term debt during 2001 through a combination of long-term debt and equity. Based on prior successful short-term debt refinancings and current market conditions, we do not anticipate any liquidity problems. Credit Facilities In February 1998, we refinanced our first mortgage notes and existing bank credit facilities with a $325 million secured revolving credit facility expiring in February 2005. On December 1, 1998, the credit facility was amended to release the collateral and the credit facility became unsecured. Borrowings under the credit facility were primarily used to fund our investment in Plantation Pipe Line Company in June 1999. On September 29, 1999, the $325 million credit facility was replaced with a $300 million unsecured five-year credit facility expiring in F-18 96 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 the $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. The terms of the new credit facility are substantially similar to the terms of the previous facility. The two credit facilities are with a syndicate of financial institutions. First Union National Bank is the administrative agent under the agreements. The outstanding balance under our five-year credit facility was $197.6 million at December 31, 1999. On August 11, 2000, we refinanced the outstanding balance under SFPP'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 364-day credit facility at December 31, 1999. The outstanding balance under our 364-day credit facility was $582 million at December 31, 2000. Interest on our credit facilities accrues at our option at a floating rate equal to either: o First Union National Bank's base rate (but not less than the Federal Funds Rate, plus 0.5%); or o LIBOR, plus a margin, which varies depending upon the credit rating of our long-term senior unsecured debt. The five-year credit facility also permits us to obtain bids for fixed rate loans from members of the lending syndicate. At December 31, 2000, the interest rate on our credit facilities was 7.115% per annum. The weighted average interest rate on our borrowings under our credit facilities was 6.8987% during 2000 and 6.1313% during 1999. Senior Notes On January 29, 1999, we closed a public offering of $250 million in principal amount of 6.30% senior notes due February 1, 2009 at a price to the public of 99.67% per note. In the offering, we received proceeds, net of underwriting discounts and commissions, of approximately $248 million. We used the proceeds to pay the outstanding balance on our credit facility and for working capital and other partnership purposes. In connection with the refinancing of our credit facility on September 29, 1999, our subsidiaries were released from their guarantees of the credit facility. As a result, the subsidiary guarantees under these senior notes were also automatically released in accordance with the terms of the notes. At December 31, 2000, the unamortized liability balance on the 6.30% senior notes was $249.3 million. 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 the issuance of these notes were used to reduce our outstanding commercial paper. At December 31, 2000, the unamortized liability balance on the 8.0% notes was $199.7 million and the unamortized liability balance on the floating rate notes was $200 million. At December 31, 2000, the interest rate on our floating rate notes was 7.0%. On November 8, 2000, we closed a private placement of $250 million of 7.5% notes due November 1, 2010. We agreed to offer to exchange these notes with substantially identical notes that are registered under the Securities Act of 1933 within 210 days of the close of this transaction. The proceeds from this offering, net of underwriting discounts, were $246.8 million. These proceeds were used to reduce our outstanding commercial paper. At December 31, 2000, the unamortized liability balance on the 7.5% notes was $248.4 million. In addition, as of December 31, 1999, we financed $330 million through KMI to fund part of the acquisition of assets acquired from KMI on December 31, 1999. In accordance with the Closing Agreement entered into as of January 20, 2000, we paid KMI a per diem fee of $180.56 for each $1,000,000 financed. We paid KMI $200 million on January 21, 2000, and the remaining $130 million on March 23, 2000 with a portion of the proceeds from our issuance of notes on March 22, 2000. F-19 97 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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. As of December 31, 1999, we had not issued any commercial paper. 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. Borrowings under our commercial paper program reduce the borrowings allowed under our 364-day and five-year credit facilities combined. As of December 31, 2000, we had $52 million of commercial paper outstanding with an interest rate of 7.02%. SFPP Debt At December 31, 2000, the outstanding balance under SFPP's Series F notes was $119.0 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. The Series F notes are payable in annual installments of $39.5 million in 2001, $42.5 million in 2002 and $37.0 million in 2003. The Series F notes may also be prepaid in full or in part at a price equal to par plus, in certain circumstances, a premium. The Series F notes are secured by mortgages on substantially all of the properties of SFPP (the "Mortgaged Property"). The Series F notes contain certain covenants limiting the amount of additional debt or equity that may be issued and limiting the amount of cash distributions, investments, and property dispositions. At December 31, 1999, the outstanding balance under SFPP's bank facility was $174.0 million. On August 11, 2000, we refinanced the outstanding balance under SFPP's secured credit facility with a $175.0 million borrowing under our five-year credit facility. Upon refinancing, SFPP executed a $175 million intercompany note in favor of Kinder Morgan Energy Partners, L.P. The weighted average interest rate on the SFPP bank facility was 5.477% for 1999 and 6.4797% in 2000. Trailblazer Debt 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. Trailblazer provided security for the notes principally by an assignment of certain Trailblazer transportation contracts. Effective April 29, 1997, Trailblazer amended the Note Purchase Agreement. This amendment allowed Trailblazer to include several additional transportation contracts as security for the notes, added a limitation on the amount of additional money that Trailblazer could borrow and relieved Trailblazer from its security deposit obligation. At December 31, 2000, Trailblazer's outstanding balance under the Senior Secured Notes was $20.2 million. The Senior Secured Notes have a fixed annual interest rate of 8.03% and will be repaid in semiannual installments of $5.05 million from March 1, 2001 through September 1, 2002, the final maturity date. Interest is payable semiannually in March and September. Pursuant to the terms of this Note Purchase Agreement, Trailblazer partnership distributions are restricted by certain financial covenants. Currently, Trailblazer's proposed expansion project is pending before the FERC. If the expansion is approved, which is expected in the first quarter of 2001, we plan to refinance these notes. In December 1999, Trailblazer entered into a 364-day revolving credit agreement with Toronto Dominion, Inc. providing for loans up to $10 million. At December 26, 2000, the outstanding balance due under Trailblazer's bank facility was $10 million. Trailblazer paid the outstanding balance under its credit facility with a $10 million borrowing under an intercompany account payable in favor of KMI on December 27, 2000. In January 2001, Trailblazer entered into a 364-day revolving credit agreement with Credit Lyonnais New York Branch, providing for loans up to $10 million. The agreement expires December 27, 2001. At January 31, 2001, the outstanding balance under Trailblazer's revolving credit agreement was $10 million. The borrowings were used to pay the account payable to KMI. The agreement provides for an interest rate of LIBOR plus 0.875%. At January 31, 2001, the interest rate on the credit facility debt was 6.625%. Pursuant to the terms of the revolving credit agreement, Trailblazer partnership distributions are restricted by certain financial covenants. F-20 98 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 2000, the weighted-average interest rate on these bonds was 4.47% per annum, and at December 31, 2000 the interest rate was 5.00%. 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 KMCO2, 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, 2000, the debt facilities of Cortez Capital Corporation consisted of: o a $127 million uncommitted 364-day revolving credit facility; o a $48 million committed 364-day revolving credit facility; o a $175 million in short term commercial paper program; and o $151.7 million of Series D notes. MATURITIES OF DEBT The scheduled maturities of our outstanding debt at December 31, 2000, are summarized as follows (in thousands): 2001 $ 683,649 2002 253,116 2003 37,016 2004 207,617 2005 199,670 Thereafter 523,334 ------------ Total $ 1,904,402 ============
Of the $683.6 million scheduled to mature in 2001, we intend and have the ability to refinance $34.7 million on a long-term basis under our existing credit facilities. 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, 2000 and December 31, 1999 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, 2000 December 31, 1999 --------------------------------- ---------------------------------- Carrying Estimated Carrying Estimated Value Fair Value Value Fair Value -------------- -------------- --------------- -------------- (in thousands) Total Debt $ 1,904,402 $ 2,011,818 $ 1,198,301 $ 1,209,625
F-21 99 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 10. PENSIONS AND OTHER POSTRETIREMENT BENEFITS In connection with the acquisition of SFPP and Kinder Morgan Bulk Terminals in 1998, we acquired certain liabilities for pension and postretirement benefits. We have a noncontributory defined benefit pension plan covering the former employees of Kinder Morgan Bulk Terminals. The benefits under this plan were based primarily upon years of service and final average pensionable earnings. 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. SFPP's postretirement benefit plan is frozen and no additional participants may join the plan. Similarly, benefit accruals were frozen as of December 31, 1998 for the Hall-Buck plan. As a result of these events, we recognized a curtailment gain related to the SFPP's plan of $3.9 million in 1999 and a gain related to Hall-Buck's plan of $0.4 million in 1998. Net periodic benefit costs and weighted-average assumptions for these plans include the following components (in thousands):
2000 1999 1998 -------------------------- -------------------------- -------------------------- Other Other Other Pension Postretirement Pension Postretirement Pension Postretirement Benefits Benefits Benefits Benefits Benefits Benefits ------- -------------- ------- -------------- ------- -------------- Net periodic benefit cost Service cost $ -- $ 46 $ -- $ 80 $ 98 $ 636 Interest cost 145 755 141 696 76 983 Expected return on plan assets (171) -- (150) -- (70) -- Amortization of transition obligation 1 -- -- -- -- -- Amortization of prior service cost -- (493) -- (493) -- (493) Actuarial loss (gain) -- (290) -- (340) -- (208) ------- -------------- ------- -------------- ------- -------------- Net periodic benefit cost $ (25) $ 18 $ (9) $ (57) $ 104 $ 918 ======= ============== ======= ============== ======= ============== Additional amounts recognized Curtailment (gain) loss $ -- $ -- $ -- $ (3,859) $ (425) $ -- Weighted-average assumptions as of December 31: Discount rate 7.5% 7.75% 7.0% 7.0% 7.0% 7.5% Expected return on plan assets 8.5% -- 8.5% -- 8.5% -- Rate of compensation increase -- -- -- -- 4.0% 4.0%
F-22 100 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Information concerning benefit obligations, plan assets, funded status and recorded values for these plans follows (in thousands):
2000 1999 --------------------------- --------------------------- Other Other Pension Postretirement Pension Postretirement Benefits Benefits Benefits Benefits -------- --------------- -------- --------------- Change in benefit obligation Benefit obligation at Jan. 1 $ 1,737 $ 9,564 $ 1,862 $ 14,734 Service cost -- 46 -- 80 Interest cost 145 755 141 696 Amendments -- (371) -- -- Administrative expenses (9) -- (12) -- Actuarial (gain) loss 299 1,339 86 (1,521) Curtailment (gain) -- -- -- (3,859) Benefits paid from plan assets (189) (435) (340) (566) -------- --------------- -------- --------------- Benefit obligation at Dec. 31 $ 1,983 $ 10,898 $ 1,737 $ 9,564 ======== =============== ======== =============== Change in plan assets Fair value of plan assets at Jan. 1 $ 2,060 $ -- $ 1,833 $ -- Actual return on plan assets (138) -- 300 -- Employer contributions 92 435 279 566 Administrative expenses (9) -- (12) -- Benefits paid from plan assets (189) (435) (340) (566) -------- --------------- -------- --------------- Fair value of plan assets at Dec. 31 $ 1,816 $ -- $ 2,060 $ -- ======== =============== ======== =============== Funded status $ (167) $ (10,898) $ 323 $ (9,564) Unrecognized net transition obligation 1 -- 2 -- Unrecognized net actuarial (gain) loss 359 (1,383) (250) (3,012) Unrecognized prior service (benefit) -- (1,656) -- (1,777) -------- --------------- -------- --------------- Prepaid (accrued) benefit cost $ 193 $ (13,937) $ 75 $ (14,353) ======== =============== ======== ===============
In 2001, SFPP modified benefits associated with its postretirement benefit plan. This plan amendment resulted in a $0.4 million decrease in its benefit obligation for 2000. 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, an 8% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2000. The rate was assumed to decrease gradually to 5% by 2005 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: F-23 101 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1-Percentage Point 1-Percentage Point Increase Decrease ------------------- ------------------- Effect on total of service and interest cost components $ 61 $ (52) Effect on postretirement benefit obligation $ 773 $ (665)
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 contributed $0.6 million during each of the years 2000 and 1999. 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 $0.5 million for each of the years 2000 and 1999. The amount charged from the period of acquisition through December 31, 1998 was $0.5 million. We terminated the Employee Stock Ownership Plan held by Kinder Morgan Bulk Terminals for the benefit of its employees on August 13, 1998. All ESOP participants became fully vested retroactive to July 1, 1998, the effective date of our acquisition of Kinder Morgan Bulk Terminals. We distributed the assets remaining in the plan during 1999. 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, that permits all full-time employees of our general partner to contribute 1% to 15% of base compensation, on a pre-tax basis, into participant accounts. This plan was subsequently amended and merged to form the Kinder Morgan Savings Plan. In addition to a mandatory contribution equal to 4% of base compensation per year for each plan participant, our general partner may make discretionary contributions in years when specific performance objectives are met. 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 2001, an additional 2% discretionary contribution was made to individual accounts based on 2000 financial targets to unitholders. The total amount charged to expense for our Retirement Savings Plan was $1.8 million during 2000. 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. 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. F-24 102 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 11. PARTNERS' CAPITAL In connection with KMI's transfer to us of Natural Gas Pipelines assets effective December 31, 2000, we paid to KMI cash consideration and issued to KMI 640,000 common units and 2,656,700 Class B units representing limited partnership interests in us. These units will not participate in our distribution declared for the fourth quarter of 2000. Our Class B units are similar to our common units except our Class B units are not eligible for trading on the New York Stock Exchange. Our Class B unitholders (KMI) have the same rights as our common unitholders with respect to, without limitation, distributions from us, voting rights and allocations of income, gain, loss or deductions. The Class B units are convertible into common units after such time as the New York Stock Exchange has advised us that common units issuable upon such conversion are eligible for listing on the NYSE. At any time after December 21, 2001, the holders of a majority of our Class B units may notify us of their desire to convert their Class B units into our common units. At December 31, 2000, Partners' capital consisted of 64,858,109 common units and 2,656,700 Class B units. Together, these 67,514,809 units represent the limited partners' interest and an effective 98% economic interest in the Partnership, exclusive of our general partner's incentive distribution. The common unit total consisted of 53,546,109 units held by third parties, 10,450,000 units held by KMI and 862,000 units held by our general partner. The Class B units were held entirely by KMI. At December 31, 1999 and 1998 there were 59,137,137 and 48,821,690 common units outstanding, respectively. The general partner has an effective 2% interest in the Partnership, excluding the general partner's incentive distribution. During 1998, we issued 26,548,879 on March 6, 1998 for the acquisition of SFPP and 2,121,033 units on August 13, 1998 for the acquisition of Hall-Buck. Additionally, we issued 6,070,578 units in a primary public offering on June 12, 1998 and we repurchased 30,000 units in December 1998. During 1999, we issued 510,147 units on September 10, 1999 for the acquisition of assets from Primary Corporation and 9,810,000 units on December 31, 1999 related to the acquisition of assets from KMI. Additionally, in 1999, we issued 2,000 units in accordance with unit option exercises, and we repurchased 6,000 units in January 1999 and 700 units in December 1999. During 2000, we issued 574,172 units on February 2, 2000 for the acquisition of Milwaukee Bulk Terminals, Inc. and Dakota Bulk Terminal, Inc. On April 4, 2000, we issued 4,500,000 units in a public offering at an issuance price of $39.75 per unit, less commissions and underwriting expenses. We used the proceeds from the April 2000 unit issuance to acquire the remaining ownership interest in Kinder Morgan CO2 Company, L.P. On December 21, 2000, we issued 3,296,700 units to KMI as partial consideration for acquired assets (see note 3). Additionally, in 2000, we issued 6,800 common units in accordance with common unit option exercises. For purposes of maintaining partner capital accounts, our partnership agreement specifies that items of income and loss shall be allocated among the partners 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, 2000, 1999 and 1998, we distributed $3.425, $2.85 and $2.4725, respectively, per unit. Our distributions to unitholders for 2000, 1999 and 1998 required incentive distributions to our general partner in the amount of $107.8 million, $55.0 million and $32.7 million, respectively. The increased incentive distributions paid for 2000 over 1999 and 1999 over 1998 reflect the increase in amounts distributed per unit as well as the issuance of additional units. On January 17, 2001, we declared a cash distribution for the quarterly period ended December 31, 2000, of $0.95 per unit. This distribution was paid on February 14, 2001, to unitholders of record as of January 31, 2001, except for the 640,000 common units and 2,656,700 Class B units issued to KMI on December 21, 2000. This distribution required an incentive distribution to our general partner in the amount of $32.8 million. Since this distribution was declared after the end of the quarter, no amount is shown in the December 31, 2000 balance sheet as a Distribution Payable. F-25 103 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 12. RELATED PARTY TRANSACTIONS GENERAL AND ADMINISTRATIVE EXPENSES Our general partner provides us with general and administrative services and is entitled to reimbursement of all direct and indirect costs related to our business activities. Our general partner incurred on behalf of us general and administrative expenses of $54.4 million in 2000, $30.7 million in 1999 and $38.0 million in 1998. We believe that these amounts were a reasonable allocation of the expenses incurred on our behalf. Since K N Energy, Inc. acquired Kinder Morgan (Delaware), Inc. in October 1999, our general partner has shared administrative personnel with KMI to operate both KMI's business and our business. As a result, our general partner's officers, who in some cases may also be officers of KMI, must allocate, in their reasonable and sole discretion, the time our general partner's employees and KMI's employees spend on behalf of KMI and on behalf of us. For 2000, KMI paid our general partner a net payment of $1.0 million in January 2001 as reimbursement for the services of our general partner's employees. Although we believe this amount received from KMI for the services it provided in 2000 fairly reflects the net value of the services performed, the determination of this amount was not the result of arms length negotiations. However, due to the nature of the allocations, this reimbursement may not have exactly matched the actual time and overhead spent. We believe the agreed-upon amount was a reasonable allocation of the expenses for the services rendered. Our general partner and KMI will continue to evaluate the net amount to be charged for the services provided to KMI and us by the employees of our general partner and KMI. 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: 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, 2000, our general partner owned 862,000 common units, representing approximately 1.3% of the outstanding 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 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 in respect of its remaining 0.5% special limited partner interest in SFPP. Available Cash is initially distributed 98% to our limited partners (including the approximate 1.3% limited partner interest owned by our general partner) 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; o 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 $0.3025 per unit for such quarter; o second, 85% 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 $0.3575 per unit for such quarter; o third, 75% 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 $0.4675 per unit for such quarter; and o fourth, thereafter 50% to the owners of all classes of units pro rata and 50% to our general partner. F-26 104 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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, 2000, 1999 and 1998 were $107.8 million, $55.0 million and $32.7 million, respectively. Kinder Morgan, Inc. KMI, through its subsidiary Kinder Morgan (Delaware), Inc., remains the sole stockholder of our general partner. At December 31, 2000, KMI directly owned 10,450,000 common units and 2,656,700 Class B units. These units, excluding the common units indirectly owned by our general partner, represent approximately 19.4% of the outstanding units. 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 43 years. Future commitments related to these leases at December 31, 2000 are as follows (in thousands): 2001 $ 30,622 2002 50,021 2003 48,497 2004 46,480 2005 45,591 Thereafter 670,711 -------------- Total minimum payments $ 891,922 ==============
We have not reduced our total minimum payments for future minimum sublease rentals aggregating approximately $2.4 million. Total lease and rental expenses, including related variable charges were $7.5 million for 2000, $8.8 million for 1999 and $7.3 million for 1998. During 1998, we established a unit option plan, which provides that key personnel are eligible to receive grants of options to acquire units. The number of units available under the option plan is 250,000. The option plan terminates in March 2008. As of December 31, 2000, options for 206,800 units were granted to certain personnel with a term of seven years at exercise prices equal to the market price of the units at the grant date. In addition, as of December 31, 2000, options for 15,000 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 unit options granted under our 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. 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, 1998, two executive officers of our general partner each had outstanding awards totaling 2% of the incentive compensation value eligible to be granted under the Executive Compensation Plan. On January 4, 1999, 50% of the awards granted to these executive officers were vested and paid out. On April 28, 2000, the remaining 50% of the awards granted to these executive officers were vested and paid out. F-27 105 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 14. RISK MANAGEMENT We use energy financial instruments to reduce our risk of price changes in the spot and fixed price 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: o commodity futures and options contracts; o fixed-price swaps; and o 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: o pre-existing or anticipated physical natural gas, natural gas liquids, crude oil and carbon dioxide sales; o gas purchases; and o system use and storage. Our risk management activities are only used in order to protect our profit margins and we are prohibited 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. Gains and losses on hedging positions are deferred and recognized as natural gas purchases expense in the periods in which the underlying physical transactions occur. Purchases or sales of commodity contracts require a dollar amount to be placed in margin accounts. In addition, 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. At December 31, 2000, we had $7.0 million in margin deposits associated with commodity contract positions and $0.0 million in margin deposits associated with over-the-counter swap partners. The differences between the current market value and the original physical contracts value associated with hedging activities are reflected, depending on maturity, as deferred charges or credits and other current assets or liabilities in the accompanying consolidated balance 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. Given our portfolio of businesses as of December 31, 2000, 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. The short and long positions shown in the table that follows are principally associated with the activities described above. Current deferred net gains (losses) are reported as Deferred Revenues in the current liability section on the accompanying consolidated balance sheet at December 31, 2000. Long-term deferred net gains (losses) are included with Other Long-Term Liabilities and Deferred Credits on the accompanying consolidated balance sheet at December 31, 2000. In 2001, these amounts will be included with other comprehensive income as discussed below. F-28 106 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS As of December 31, 2000, our commodity contracts and over-the-counter swaps and options (in thousands) consisted of the following:
Commodity Over the Counter Contracts Swaps and Options Total ------------ ----------------- ------------ Deferred Net (Loss) Gain $ 6,977 $ (36,229) $ (29,252) Contract Amounts - Gross $ 816,216 $ 1,537,671 $ 2,353,887 Contract Amounts - Net $ (58,679) (156,966) $ (215,645) Credit Exposure of Loss $ -- $ 23,570 $ 23,570 Natural Gas Notional Volumetric Positions: Long 5,206 11,837 Notional Volumetric Positions: Short (5,475) (14,298) Net Notional Totals to Occur in 2001 186 (2,014) Net Notional Totals to Occur in 2002 and Beyond (455) (447) Crude Oil Notional Volumetric Positions: Long 34 102 Notional Volumetric Positions: Short (1,585) (5,108) Net Notional Totals to Occur in 2001 (1,107) (2,147) Net Notional Totals to Occur in 2002 and Beyond (444) (2,589) Natural Gas Liquids Notional Volumetric Positions: Long -- 120 Notional Volumetric Positions: Short -- (951) Net Notional Totals to Occur in 2001 -- (510) Net Notional Totals to Occur in 2002 and Beyond -- (321)
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities". The statement establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset of liability measured at its fair value. The statement requires that changes in the derivatives fair value be recognized currently in earnings unless specific hedge accounting criteria are met. If the derivatives meet these criteria, the statement allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company formally designate a derivative as a hedge and document and assess the effectiveness of derivatives associated with transactions that receive hedge accounting. SFAS No. 133, after amendment by SFAS No. 137 and SFAS No. 138, is effective for all quarters of all fiscal years beginning after June 15, 2000. The statement cannot be applied retroactively. As discussed above, our principal use of derivative financial instruments is to mitigate the market price risk associated with anticipated transactions for the purchase and sale of natural gas, natural gas liquids, crude oil and carbon dioxide. The statement allows these transactions to continue to be treated as hedges for accounting purposes, although the changes in the market value of these instruments will affect comprehensive income in the period in which they occur and any ineffectiveness in the risk mitigation performance of the hedge will affect net income currently. The change in the market value of these instruments representing effective hedge operation will continue to affect net income in the period in which the associated physical transactions are consummated. Adoption of the statement will result in the deferred net loss shown in the preceding table being reported as part of other comprehensive income, as well as subsequent changes in the market value of these derivatives. 15. REPORTABLE SEGMENTS We compete in four reportable business segments (see note 1): F-29 107 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS o Product Pipelines; o Natural Gas Pipelines; o CO2 Pipelines; and o Bulk 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 excludes 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. Our Product 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 CO2 Pipelines segment's revenues are primarily derived from the marketing and transportation of carbon dioxide used as a flooding medium for recovering crude oil from mature oil fields. Our Bulk Terminals segment derives its revenues from transloading and storing multiple dry and liquid bulk products, including coal, petroleum coke, cement, alumina and salt. Financial information by segment follows (in thousands):
2000 1999 1998 --------- --------- --------- Revenues Product Pipelines $ 421,423 $ 314,113 $ 258,722 Natural Gas Pipelines 173,036 -- -- CO2 Pipelines 89,214 23 979 Bulk Terminals 132,769 114,613 62,916 --------- --------- --------- Total consolidated revenues $ 816,442 $ 428,749 $ 322,617 ========= ========= ========= Operating income Product Pipelines $ 193,531 $ 186,086 $ 159,227 Natural Gas Pipelines 97,198 -- (103) CO2 Pipelines 47,901 18 957 Bulk Terminals 36,996 36,917 20,572 --------- --------- --------- Total segment operating income 375,626 223,021 180,653 Corporate administrative expenses (60,065) (35,614) (39,984) --------- --------- --------- Total consolidated operating Income $ 315,561 $ 187,407 $ 140,669 ========= ========= ========= Earnings from equity investments, net of amortization of excess costs Product Pipelines $ 29,105 $ 21,395 $ 5,854 Natural Gas Pipelines 14,975 2,759 4,577 CO2 Pipelines 19,328 14,487 14,500 Bulk Terminals -- 23 37 --------- --------- --------- Consolidated equity earnings, net of amortization $ 63,408 $ 38,664 $ 24,968 --------- --------- ---------
F-30 108 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2000 1999 1998 --------- --------- --------- Interest revenue Product Pipelines $ -- $ -- $ 22 Natural Gas Pipelines -- -- -- CO2 Pipelines -- -- -- Bulk Terminals -- -- -- --------- --------- --------- Total segment interest revenue -- -- 22 Unallocated interest revenue 3,818 1,731 2,234 --------- --------- --------- Total consolidated interest revenue $ 3,818 $ 1,731 $ 2,256 ========= ========= ========= Interest (expense) Product Pipelines $ -- $ -- $ -- Natural Gas Pipelines -- -- (338) CO2 Pipelines -- -- -- Bulk Terminals -- -- -- --------- --------- --------- Total segment interest (expense) -- -- (338) Unallocated interest (expense) (97,102) (54,336) (40,518) --------- --------- --------- Total consolidated interest (expense) $ (97,102) $ (54,336) $ (40,856) ========= ========= ========= Other, net Product Pipelines $ 10,492 $ 10,008 $ (6,492) Natural Gas Pipelines 744 14,099 (6) CO2 Pipelines 741 710 -- Bulk Terminals 2,607 (669) (765) --------- --------- --------- Total consolidated other, net $ 14,584 $ 24,148 $ (7,263) ========= ========= ========= Income tax benefit (expense) Product Pipelines $ (11,960) $ (8,493) $ (1,698) Natural Gas Pipelines -- (45) 726 CO2 Pipelines -- -- -- Bulk Terminals (1,974) (1,288) (600) --------- --------- --------- Total consolidated income tax benefit (expense) $ (13,934) $ (9,826) $ (1,572) ========= ========= ========= Segment earnings Product Pipelines $ 221,168 $ 208,996 $ 156,913 Natural Gas Pipelines 112,917 16,813 4,856 CO2 Pipelines 67,970 15,215 15,457 Bulk Terminals 37,629 34,983 19,244 --------- --------- --------- Total segment earnings 439,684 276,007 196,470 Interest and corporate administrative expenses (a) (161,336) (93,705) (92,864) --------- --------- --------- Total consolidated net income $ 278,348 $ 182,302 $ 103,606 ========= ========= =========
(a) Includes interest and debt expense, general and administrative expenses, minority interest expense, extraordinary charges and other insignificant items. F-31 109 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2000 1999 1998 ----------- ----------- ----------- Assets at December 31 Product Pipelines $ 2,230,287 $ 2,015,995 $ 1,817,126 Natural Gas Pipelines 1,544,489 879,076 27,518 CO2 Pipelines 417,278 86,684 86,760 Bulk Terminals 357,689 203,601 186,298 ----------- ----------- ----------- Total segment assets 4,549,743 3,185,356 2,117,702 Corporate assets (a) 75,467 43,382 34,570 ----------- ----------- ----------- Total consolidated assets $ 4,625,210 $ 3,228,738 $ 2,152,272 =========== =========== =========== (a) Includes cash, cash equivalents and certain unallocable deferred charges Depreciation and amortization Product Pipelines $ 41,659 $ 38,928 $ 32,687 Natural Gas Pipelines 20,780 -- -- CO2 Pipelines 10,559 -- -- Bulk Terminals 9,632 7,541 3,870 ----------- ----------- ----------- Total consolidated depreciation and amortization $ 82,630 $ 46,469 $ 36,557 =========== =========== =========== Equity Investments at December 31 Product Pipelines $ 231,651 $ 243,668 $ 124,283 Natural Gas Pipelines 141,613 88,249 27,568 CO2 Pipelines 9,559 86,675 86,688 Bulk Terminals 59 59 69 ----------- ----------- ----------- Total consolidated equity investments $ 382,882 $ 418,651 $ 238,608 Investment in oil and gas assets to be contributed to joint venture 34,163 -- -- ----------- ----------- ----------- 417,045 418,651 238,608 =========== =========== =========== Capital expenditures Product Pipelines $ 69,243 $ 68,674 $ 28,393 Natural Gas Pipelines 14,496 -- -- CO2 Pipelines 16,115 -- 69 Bulk Terminals 25,669 14,051 9,945 ----------- ----------- ----------- Total consolidated capital expenditures $ 125,523 $ 82,725 $ 38,407 =========== =========== ===========
(1) The following reconciles segment earnings to net income.
2000 1999 1998 ----------- ----------- ----------- Segment earnings $ 439,684 $ 276,007 $ 196,470 Interest and corporate administrative expenses (a) (161,336) (93,705) (92,864) ----------- ----------- ----------- Net Income $ 278,348 $ 182,302 $ 103,606 =========== =========== =========== (a) Includes interest and debt expense, general and administrative expenses, minority interest expense, extraordinary charges and other insignificant items.
(2) The following reconciles segment assets to consolidated assets.
2000 1999 1998 ----------- ----------- ----------- Segment assets $ 4,549,743 $ 3,185,356 $ 2,117,702 Corporate assets (a) 75,467 43,382 34,570 ----------- ----------- ----------- Total assets $ 4,625,210 $ 3,228,738 $ 2,152,272 =========== =========== =========== (a) Includes cash, cash equivalents and certain unallocable deferred charges.
F-32 110 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Our total operating revenues are derived from a wide customer base. During each of the years ended December 31, 2000 and December 31, 1999, no revenues from transactions with a single external customer amounted to 10% or more of our consolidated revenues. In 1998, revenues from one customer of our Products Pipelines and Bulk Terminals segments represented approximately $42.5 million (13.2%) of our consolidated revenues. Additionally, in 1998, three other customers of our Product Pipelines segment accounted for more than 10% of our consolidated revenues. Revenues from these customers were approximately $39.7 million (12.3%), $35.29 million (11.0%) and $35.28 million (10.9%), respectively, of consolidated revenues. Our management believes that we are exposed to minimal credit risk, and we generally do not require collateral for our receivables. 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, 2000, 1999 and 1998, the application of the indexing methodology did not significantly affect our tariff rates. FEDERAL ENERGY REGULATORY COMMISSION PROCEEDINGS SFPP, L.P. SFPP, L.P. is the partnership that owns our Pacific operations. Tariffs charged by SFPP are subject to certain proceedings involving shippers' protests 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: o challenging SFPP's East Line rates from El Paso, Texas to Tucson and Phoenix, Arizona; o challenging SFPP's proration policy; and o 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: o Chevron U.S.A. Products Company; o Navajo Refining Company; o ARCO Products Company; o Texaco Refining and Marketing Inc.; o Refinery Holding Company, L.P. (a partnership formed by El Paso Refinery's long-term secured creditors that purchased its refinery in May 1993); o Mobil Oil Corporation; and o 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 F-33 111 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS "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: o the capital structure to be used in computing SFPP's 1985 starting rate base under FERC Opinion 154-B; o the level of income tax allowance; and o the recoverability of civil and regulatory litigation expense and certain pipeline reconditioning costs. 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. SFPP and a number of the complainants each sought rehearing by FERC of elements of Opinion No. 435. 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. SFPP and certain complainants sought rehearing of Opinion No. 435 by the FERC, asking that a number of rulings be modified. 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. F-34 112 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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: o decision to require use of the December 1988 partnership capital structure for the period 1994-98 in computing the starting rate base; o elimination of civil litigation costs; o refusal to allow any recovery of civil litigation settlement payments; and o 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: o consolidate those petitions with prior ARCO and RHC petitions to review Opinion No. 435; o dismiss the Chevron, RHC and SFPP petitions; and o 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. 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. F-35 113 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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. Upon the filing by SFPP and other parties of briefs opposing and supporting the initial decision with the FERC, the ultimate disposition of SFPP's market rate application will be before the FERC. Since the issuance of the initial decision in the Sepulveda case, the FERC judge has indicated an intention to proceed to consideration of the justness and reasonableness of the existing rate for service on the Sepulveda Lines. SFPP has 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. Further proceedings on this matter have been suspended pending resolution of SFPP's motion for clarification to the FERC. 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. Discovery in this new proceeding is currently being conducted, with a hearing scheduled for August 2001 and an initial decision by the administrative law judge due in January 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 F-36 114 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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. 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. 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. 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 together with reparations for periods from the date of the complaint to the date of the implementation of the new rates. 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. KMIGT On January 23, 1998, KMIGT filed a general rate case with the FERC requesting a $30.2 million increase in annual revenues. As a result of the FERC's action, KMIGT was allowed to place its rates into effect on August 1, 1998, subject to refund. On November 3, 1999, KMIGT filed a comprehensive Stipulation and Agreement to resolve all issues in this proceeding. The FERC approved the Stipulation and Agreement on December 22, 1999. The settlement rates have been placed in effect, and KMIGT paid refunds of $34.7 million during 2000. The refunds did not exceed amounts previously accrued. Trailblazer On July 1, 1997, Trailblazer filed a rate case with the FERC (Docket No. RP97-408) which reflected a proposed annual revenue increase of $3.3 million. The timing of the rate case filing was in accordance with the requirements of Trailblazer's previous rate case settlement in Docket No. RP93-55. The FERC issued an order on July 31, 1997, which suspended the rates to be effective January 1, 1998. Major issues in the rate case included: o throughput levels used in the design of rates; o levels of depreciation rates; o return on investment; and o the cost of service treatment of the Columbia settlement revenues. Trailblazer filed a proposed settlement agreement with the administrative law judge on May 8, 1998. The presiding administrative law judge certified the settlement to the FERC in an order dated June 25, 1998. The FERC issued an order on October 19, 1998 remanding the settlement, which was contested by two parties, to the presiding administrative law judge for further action. A revised settlement was filed on November 20, 1998. The presiding administrative law judge certified the revised settlement to the FERC on January 25, 1999. The FERC issued orders on April 28, 1999 and August 3, 1999, approving the revised settlement as to all parties except the two parties who contested the settlement. As to the two contesting parties, the FERC established hearing procedures. On March 3, 2000, Trailblazer and the two parties filed a joint motion indicating that a settlement in principle had been reached. On March 6, 2000, the presiding administrative law judge issued an order suspending the procedural schedule and hearing pending the filing of the appropriate documents necessary to terminate the proceeding. On March 16, 2000, the two contesting parties filed a motion to withdraw their requests for rehearing of the FERC orders approving the settlement and concurrently those parties and Trailblazer jointly moved to terminate the proceeding. On March 30, 2000, the administrative law judge issued an order granting motion to terminate further proceedings, followed by an initial decision on April 7, 2000, terminating the F-37 115 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS proceedings. On May 18, 2000, the FERC issued a notice of the finality of the initial decision. Refunds related to the rate case were made in April 28, 2000 and totaled approximately $17.8 million. Adequate reserves had previously been established. 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. 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. Procedurally, the rehearing complaint will be heard first, followed by consideration of the April 2000 complaint and SFPP's market-based application, which have been consolidated for hearing by the CPUC. The rehearing complaint was the subject of evidentiary hearings in October 2000, and a decision is expected within two to six months. The April 2000 complaint and SFPP's market-based application will be the subject of evidentiary hearings in February 2001, with a decision expected within six months of the hearings. 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. FERC ORDER 637 On June 15, 2000, KMIGT made its filing to comply with the FERC's Orders 637 and 637-A. That filing contained KMIGT's compliance plan to implement the changes required by the FERC dealing with the way business is conducted on interstate pipelines. All interstate pipelines are required to make such compliance filings, according to a schedule established by the FERC. KMIGT's filing is currently pending FERC action, and any changes to its tariff provisions are not expected to take effect until after the entire Order 637 process is finished for all pipelines. Separately, numerous petitioners, including KMIGT, have filed appeals of Order No. 637 in the D.C. Circuit, potentially raising a wide array of issues. F-38 116 CARBON DIOXIDE LITIGATION Kinder Morgan CO2 Company, L.P., as the successor to Shell CO2 Company, Ltd. and directly and 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 are comprised of royalty, overriding royalty and small share working interest owners who claim that they were underpaid by the defendants. These cases are: CO2 Claims Coalition, LLC v. Shell Oil Co., et al., No. 96-Z-2451 (U.S.D.C. Colo.); Rutter & Wilbanks et al. v. Shell Oil Co., et al., No. 00-Z-1854 (U.S.D.C. Colo.); Watson v. Shell Oil Co., et al., No. 00-Z-1855 (U.S.D.C. Colo.); Ainsworth et al. v. Shell Oil Co., et al., No. 00-Z-1856 (U.S.D.C. Colo.); United States ex rel. Crowley v. Shell Oil Company, et al., No. 00-Z-1220 (U.S.D.C. Colo.); Ptasynski et al. v. Shell Western E&P Inc., et al., No. 3:97-CV-1208-R (U.S.D.C. Tex. N. Dist. Dallas Div.); Feerer et al. v. Amoco Production Co., et al., No. 99-2231 (U.S. Ct. App. 10th Cir.); Shell Western E&P Inc. v. Bailey, et al., No 98-28630 (215th Dist. Ct. Harris County, Tex.); Shores, et al. v. Mobil Oil Corporation, et al., No. GC-99-01184 (Texas Probate Court, Denton County); and Celeste C. Grynberg v. Shell Oil Company, et al., No. 98-CV-43 (Colo. Dist. Ct. Montezuma County). Although no assurances can be given, we believe that we have meritorious defenses to 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 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 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: o 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; and o several ground water hydrocarbon remediation efforts under administrative orders issued by the California Regional Water Quality Control Board and two other state agencies. 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 five sites. Further delineation and remediation of these impacts will be conducted. A reserve was established to address the closure of these issues. 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 results of operations. We have recorded a reserve for environmental claims in the amount of $21.1 million at December 31, 2000. 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. F-39 117 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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) 2000 First Quarter $157,358 $63,061 $59,559 $0.63 $0.63 Second Quarter 193,758 79,976 71,810 0.70 0.70 Third Quarter 202,575 79,826 69,860 0.67 0.67 Fourth Quarter 262,751 92,698 77,119 0.68 0.68 1999 First Quarter $100,049 $47,645 $41,069 $0.57 $0.57 Second Quarter 102,933 47,340 43,113 0.61 0.61 Third Quarter (1) 104,388 48,830 52,553 0.77 0.77 Fourth Quarter 121,379 43,592 45,567 0.62 0.62
(1) 1999 third quarter includes an extraordinary charge of $2.6 million due to an early extinguishment of debt. Net income before extraordinary charge was $55.1 million and basic net income per unit before extraordinary charge was $0.82. F-40 118 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 on the 4th day of April 2001. KINDER MORGAN ENERGY PARTNERS, L.P. (A Delaware Limited Partnership) By: KINDER MORGAN G.P., INC. as General Partner By: /s/ JOSEPH LISTENGART -------------------------------------- Joseph Listengart Vice President and General Counsel S-1 119 EXHIBIT INDEX
EXHIBIT NUMBER DESCRIPTION ------- ----------- *2.1 Stock Purchase Agreement dated November 30, 2000 between GATX Rail Corporation, GATX Terminals Holding Corporation and Kinder Morgan Energy Partners, L.P. (filed as Exhibit 99(b) to the Partnership's Current Report on Form 8-K filed December 1, 2000). *3.1 - Second Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. effective as of February 14, 1997 (filed as Exhibit 3.1 to Amendment No. 1 to Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-4, file No. 333-46709, filed on April 14, 1998). *3.2 - Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. dated as of January 20, 2000 (filed as Exhibit 4.1 to the Partnership's Current Report on Form 8-K filed January 20, 2000). 3.3 - Amendment No. 2 to Second Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. dated as of December 21, 2000. *4.1 - Specimen Certificate evidencing Common Units representing Limited Partner Interests (filed as Exhibit 4.1 to Amendment No. 1 to Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-4, file No. 333-44519, filed on February 4, 1998). *4.2 - Indenture dated as of January 29, 1999 among Kinder Morgan Energy Partners, L.P., the guarantors listed on the signature page thereto and U.S. Trust Company of Texas, N.A., as trustee, relating to Senior Debt Securities (filed as Exhibit 4.1 to the Partnership's Current Report on Form 8-K filed February 16, 1999 (the "February 16, 1999 Form 8-K")). *4.3 - First Supplemental Indenture dated as of January 29, 1999 among Kinder Morgan Energy Partners, L.P., the subsidiary guarantors listed on the signature page thereto and U.S. Trust Company of Texas, N.A., as trustee, relating to $250,000,000 of 6.30% Senior Notes due February 1, 2009 (filed as Exhibit 4.2 to the February 16, 1999 Form 8-K). *4.4 - Second Supplemental Indenture dated as of September 30, 1999 among Kinder Morgan Energy Partners, L.P. and U.S. Trust Company of Texas, N.A., as trustee, relating to release of subsidiary guarantors under the $250,000,000 of 6.30% Senior Notes due February 1, 2009 (filed as Exhibit 4.4 to the Partnership's Form 10-Q for the quarter ended September 30, 1999 (the "1999 Third Quarter Form 10-Q")). *4.5 - Indenture dated March 22, 2000 between Kinder Morgan Energy Partners and First Union National Bank, as Trustee (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-4 (file no. 333-35112) filed on April 19, 2000 (the "April 2000 Form S-4")). *4.6 - Form of Floating Rate Note and Form of 8% Note (contained in the Indenture filed as Exhibit 4.1 to the April 2000 Form S-4). *4.7 - Registration Rights Agreement dated March 22, 2000 among Kinder Morgan Energy Partners, Goldman, Sachs & Co., Merrill Lynch & Co., Banc of America Securities LLC and First Union Securities, Inc. (filed as Exhibit 4.3 to the April 2000 Form S-4). 4.8 - Indenture dated November 8, 2000 between Kinder Morgan Energy Partners and First Union National Bank, as Trustee. 4.9 - Form of 7.50% Note (contained in the Indenture filed as Exhibit 4.8). 4.10 - Registration Rights Agreement dated November 8, 2000 between Kinder Morgan Energy Partners and Banc of America Securities LLC. 4.11 - Indenture dated January 2, 2001 between Kinder Morgan Energy Partners and First Union National Bank, as trustee, relating to Senior Debt Securities (including form of Senior Debt Securities). 4.12 - Indenture dated January 2, 2001 between Kinder Morgan Energy Partners and First Union National Bank, as trustee, relating to Subordinate Debt Securities (including form of Subordinate Debt Securities). 4.13 - Certain instruments with respect to long-term debt of the Partnership and its consolidated subsidiaries which relate to debt that does not exceed 10% of the total assets of the Partnership and its consolidated subsidiaries are omitted pursuant to Item 601(b) (4) (iii) (A) of Regulation S-K, 17 C.F.R. Section 229.601. The Partnership hereby agrees to furnish supplementally to the Securities and Exchange Commission a copy of each such instrument upon request. *10.1 - Kinder Morgan Energy Partners, L.P. Common Unit Option Plan (filed as Exhibit 10.6 to the Partnership's 1997 Form 10-K). *10.2 - Employment Agreement with William V. Morgan (filed as Exhibit 10.1 to the Partnership's Form 10-Q for the quarter ended March 31, 1997). *10.3 - Kinder Morgan Energy Partners L.P. Executive Compensation Plan (filed as Exhibit 10 to the Partnership's Form 10-Q for the quarter ended June 30, 1997). *10.4 - 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). *10.5 - 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).
120 * 10.6 - Intrastate Pipeline system Lease, dated December 31, 1996, between MidCon Texas Pipeline, L.P. and MidCon Texas Pipeline Operator, Inc. (filed as Exhibit 10(y) to Kinder Morgan, Inc.'s 1997 Form 10-K). * 10.7 - Amendment Number One to Intrastate Pipeline system Lease, dated December 31, 1996, between MidCon Texas Pipeline, L.P. and MidCon Texas Pipeline Operator, Inc. (filed as Exhibit 10(z) to Kinder Morgan, Inc.'s 1997 Form 10-K). 21.1 - List of Subsidiaries. **23.1 - Consent of PricewaterhouseCoopers LLP.
- --------- * Asterisk indicates exhibits incorporated by reference as indicated. ** Double asterisk indicates exhibit filed with this Form 10-K/A. All other exhibits filed with Form 10-K for the year ended December 31, 2000. -----END PRIVACY-ENHANCED MESSAGE-----