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.