EX-99.1 4 h84357ex99-1.txt FINANCIAL STATEMENTS 1 Exhibit 99.1 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 2 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. These financial statements are the responsibility of the Partnership's management; our responsibility is to express an opinion on these financial statements 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. /s/ PricewaterhouseCoopers LLP Houston, Texas February 14, 2001 F-2 3 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 $ 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 4 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 oustanding 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 5 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 integral part of these consolidated financial statements. F-5 6 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL (In Thousands)
Total Common Class B General Partners' Units Units Partner Capital ---------- --------- --------- ---------- Partners' capital at December 31, 1997 $ 146,840 $ -- $ 3,384 $ 150,224 Net income 70,159 -- 33,447 103,606 Net proceeds from issuance of common units 1,212,421 -- -- 1,212,421 Capital contributions 10,234 -- 2,678 12,912 Distributions (91,063) -- (27,437) (118,500) ---------- --------- --------- ---------- Partners' capital at December 31, 1998 1,348,591 -- 12,072 1,360,663 Net income 126,029 -- 56,273 182,302 Net proceeds from issuance of common units 420,357 -- (15) 420,342 Distributions (135,835) -- (52,674) (188,509) ---------- --------- --------- ---------- Partners' capital at December 31, 1999 1,759,142 -- 15,656 1,774,798 Net income 168,878 -- 109,470 278,348 Net proceeds from issuance of units 224,028 125,961 (11) 349,978 Distributions (194,691) -- (91,366) (286,057) ---------- --------- --------- ---------- Partners' capital at December 31, 2000 $1,957,357 $ 125,961 $ 33,749 $2,117,067 ========== ========= ========= ==========
The accompanying notes are an integral part of these consolidated financial statements. F-6 7 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 that provide fee-based services to customers. 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 Gas Processing and Fractionation activities and CO2 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: 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. F-7 8 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS CASH EQUIVALENTS We define cash equivalents as all highly liquid short-term investments with original maturities of three months or less. INVENTORIES Our inventories of products consist of natural gas liquids, refined petroleum products, natural gas, carbon dioxide and coal. We report these assets at the lower of weighted-average cost or market. We report materials and supplies at the lower of cost or market. PROPERTY, PLANT AND EQUIPMENT We state property, plant and equipment at its acquisition cost. We expense costs for maintenance and repairs in the period incurred. The cost of property, plant and equipment sold or retired and the related depreciation are removed from our balance sheet in the period of sale or disposition. We compute depreciation using the straight-line method based on estimated economic lives. Generally, we apply composite depreciation rates to functional groups of property having similar economic characteristics. The rates range from 2.0% to 12.5%, excluding certain short-lived assets such as vehicles. Depreciation, depletion and amortization of the capitalized costs of producing CO2 properties, both tangible and intangible, are provided for on a units-of-production basis. Proved developed reserves are used in computing units-of-production rates for drilling and development costs, and total proved reserves are used for depletion of leasehold costs. The basis for units-of-production rate determination is by field. We charge the original cost of property sold or retired to accumulated depreciation and amortization, net of salvage and cost of removal. We do not include retirement gain or loss in income except in the case of significant retirements or sales. We evaluate impairment of our long-lived assets in accordance with Statement of Financial Accounting Standards No. 121 "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." We review for the impairment of long-lived assets whenever events or changes in circumstances indicate that our carrying amount of an asset may not be recoverable. We would recognize an impairment loss when estimated future cash flows expected to result from our use of the asset and its eventual disposition is less than its carrying amount. 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 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. F-8 9 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 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 LLC 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 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. F-9 10 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 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. F-10 11 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS On October 25, 2000, we acquired 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. CO2 PIPELINES Kinder Morgan CO2 Company, L.P. On March 5, 1998, we and affiliates of Shell Oil Company agreed to combine our CO2 activities and assets into a partnership, Shell CO2 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. F-11 12 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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. 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 CO2 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 field unit, 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 field unit. In January 2001, we contributed our interest in the Yates field unit together with an approximate 2% interest in the SACROC unit in return for a 15% interest in the joint venture. In January 2001, Marathon Oil Company purchased an approximate 11% interest in the SACROC unit from 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 is located on nine acres of property leased from the Port of Milwaukee, Wisconsin. Its major cargoes are coal and bulk de-icing salt. The Dakota terminal, located in St. Paul, Minnesota, primarily handles salt and grain products. 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 F-12 13 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 ----------- ----------- 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 is expected to close in the first quarter of 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):
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%
F-13 14 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 ====== ======
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 CO2 pipelines $ 1,732,607 $ 1,729,034 Natural Gas, liquids and CO2 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 =========== ===========
F-14 15 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 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. 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 $382,882 $418,651 ======== ========
F-15 16 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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) ======== ======== ======
Summarized combined unaudited financial information for our significant equity investments is reported below (in thousands):
Year ended December 31, 2000 1999 1998 -------- -------- -------- Income Statement 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, 2000 1999 -------- -------- Balance Sheet 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 Field unit. The joint venture was formed on January 1, 2001 and named MKM Partners, L.P. As of December 31, 2000, we paid $34.2 million plus committed 30 billion cubic feet of carbon dioxide for our 7.5 % interest in the Yates field unit. In January 2001, we contributed our interest in the Yates field unit together with an approximate 2% interest in the SACROC unit in return for a 15% interest in the joint venture. In January 2001, Marathon Oil Company purchased an approximate 11% interest in the SACROC unit from 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. F-16 17 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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, LLC 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. 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. F-17 18 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 $52.0 million of commercial paper borrowings; o $35 million under the SFPP 10.70% 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 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 F-18 19 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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. Commercial Paper Program In December 1999, we established a commercial paper program providing for the issuance of up to $300 million of commercial paper. 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 F-19 20 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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. 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. F-20 21 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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
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. F-21 22 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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%
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 ========== ============= =========== ============
F-22 23 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2000 1999 --------------------------- ---------------------------- Other Other Pension Postretirement Pension Postretirement Benefits Benefits Benefits Benefits --------- -------------- ----------- ------------ 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 $ -- ======= ======= ======= =======
2000 1999 --------------------------- ------------------------- Other Other Pension Postretirement Pension Postretirement Benefits Benefits Benefits Benefits ---------- ---------------- --------- -------------- 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:
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 F-23 24 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 different formula based on "grandfathered" provisions 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 or retirement. 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. 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. On the 60th day after our receipt of the redemption notice, we must redeem the class B units subject to the redemption notice, unless before the redemption date the NYSE has approved for listing the common units issuable in exchange for the class B 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. F-24 25 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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. 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. F-25 26 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 our limited partners and 2% to our general partner until our limited partners have received a total of $0.3025 per unit for such quarter; o second, 85% to our limited partners and 15% to our general partner until our limited partners have received a total of $0.3575 per unit for such quarter; o third, 75% to our limited partners and 25% to our general partner until our limited partners have received a total of $0.4675 per unit for such quarter; and o fourth, thereafter 50% to our limited partners and 50% to our general partner. 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 owned 10,450,000 common units and 2,656,700 class B units, representing approximately 19.4% of the outstanding units. F-26 27 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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. 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. F-27 28 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 29 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 or liability measured at its fair value. The statement requires that changes in the derivatives fair value be recognized currently in earnings unless specific hedge accounting criteria are met. If the derivatives meet these criteria, the statement allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company formally designate a derivative as a hedge and document and assess the effectiveness of derivatives associated with transactions that receive hedge accounting. 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. F-29 30 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 15. REPORTABLE SEGMENTS We compete in four reportable business segments (see note 1): 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. 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 Segments $ 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 Segments $ 375,626 $ 223,021 $ 180,653 ============ ============ ============= 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 ------------ ------------ ------------- Total Segments $ 63,408 $ 38,664 $ 24,968 ============ ============ ============= Interest revenue Product Pipelines $ - $ - $ 22 Natural Gas Pipelines - - - CO2 Pipelines - - - Bulk Terminals - - - ------------ ------------ ------------- Total Segments $ - $ - $ 22 ============ ============ =============
F-30 31 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2000 1999 1998 ------------ ------------ ------------- Interest (expense) Product Pipelines $ - $ - $ - Natural Gas Pipelines - - (338) CO2 Pipelines - - - Bulk Terminals - - - ------------ ------------ ------------- Total Segments $ - $ - $ (338) ============ ============ ============= 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 Segments $ 14,584 $ 24,148 $ (7,263) ============ ============ ============= 2000 1999 1998 ------------ ------------ ------------- 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 Segments $ (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 Segments (1) $ 439,684 $ 276,007 $ 196,470 ============ ============ =============
F-31 32 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 Segments (2) $ 4,549,743 $ 3,185,356 $ 2,117,702 ============ ============ ============= 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 Segments $ 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 Segments $ 382,882 $ 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 Segments $ 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.
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. F-32 33 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 "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. F-33 34 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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. 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 F-34 35 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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. 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 F-35 36 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 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 F-36 37 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 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 F-37 38 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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. 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 CO2 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 financial position or results of operations. F-38 39 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 40 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