-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, BN4xsvm+jVhiAwlXm8g0pFiXJwMdm+ShQcziQT2cBLGY8rXIw9f1XDDbePBzcZrc kDxnn4jJNEHCL/JdyksjQQ== 0000950129-01-000972.txt : 20010224 0000950129-01-000972.hdr.sgml : 20010224 ACCESSION NUMBER: 0000950129-01-000972 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 20010216 ITEM INFORMATION: ITEM INFORMATION: FILED AS OF DATE: 20010220 FILER: COMPANY DATA: COMPANY CONFORMED NAME: KINDER MORGAN INC CENTRAL INDEX KEY: 0000054502 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS TRANSMISSION & DISTRIBUTION [4923] IRS NUMBER: 480290000 STATE OF INCORPORATION: KS FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: SEC FILE NUMBER: 001-06446 FILM NUMBER: 1549741 BUSINESS ADDRESS: STREET 1: 500 DALLAS STREET 2: SUITE 1000 CITY: HOUSTON STATE: TX ZIP: 77002 BUSINESS PHONE: 3039144752 MAIL ADDRESS: STREET 1: 500 DALLAS STREET 2: SUITE 1000 CITY: HUSTON STATE: TX ZIP: 77002 FORMER COMPANY: FORMER CONFORMED NAME: K N ENERGY INC DATE OF NAME CHANGE: 19920703 FORMER COMPANY: FORMER CONFORMED NAME: KN ENERGY INC DATE OF NAME CHANGE: 19920430 FORMER COMPANY: FORMER CONFORMED NAME: KANSAS NEBRASKA NATURAL GAS CO INC DATE OF NAME CHANGE: 19830403 8-K 1 h84343e8-k.txt KINDER MORGAN INC - DATED FEBRUARY 16, 2001 1 SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 8-K CURRENT REPORT Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 February 16, 2001 (Date of earliest event reported) KINDER MORGAN, INC. (Exact name of registrant as specified in its charter) KANSAS 1-6446 48-0290000 (State or other jurisdiction (Commission (I.R.S. Employer of incorporation) File Number) Identification No.) 500 Dallas, Suite 1000 Houston, Texas 77002 (Address of principal executive offices, including zip code) 713-369-9000 (Registrant's telephone number, including area code) 2 Item 5. Other Events. The following financial information of Kinder Morgan, Inc., a Kansas corporation, is included herein commencing on page F-1: (1) Financial statements as of December 31, 2000 and 1999, and for the years ended December 31, 2000, 1999 and 1998; (2) Quarterly financial information (unaudited) for 2000 and 1999: (3) Selected financial data for each of the five years in the period ended December 31, 2000; (4) Management's discussion and analysis of financial condition and results of operation; (5) Quantitative and qualitative disclosures about market risk; and (6) Schedule II - Valuation and Qualifying Accounts. The consolidated financial statements and related notes of Kinder Morgan Energy Partners, L.P. (an equity method investee of Kinder Morgan, Inc.) included as exhibit 99.1 in its Form 8-K filing dated February 16, 2001 are filed herewith as exhibit 99.1 and are incorporated herein by reference. Item 7. Financial Statements and Exhibits 23.1 Consent of PricewaterhouseCoopers LLP 23.2 Consent of Arthur Andersen LLP 99.1 Form 8-K of Kinder Morgan Energy Partners, L.P. dated February 16, 2001, including the consolidated financial statements of Kinder Morgan Energy Partners, L.P. 3 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Stockholders of Kinder Morgan, Inc. In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of comprehensive income, of stockholders' equity and of cash flows present fairly, in all material respects, the financial position of Kinder Morgan, Inc. (formerly K N Energy, Inc.) and its subsidiaries at December 31, 2000 and 1999, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 5 of this Form 8-K presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. We also audited the adjustments described in Note 2 that were applied to restate the 1998 consolidated financial statements. In our opinion, such adjustments are appropriate and have been properly applied. /s/ PricewaterhouseCoopers LLP Houston, Texas February 14, 2001 F-1 4 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To Kinder Morgan, Inc.: We have audited the accompanying consolidated statements of income, comprehensive income, stockholders' equity, and cash flows of Kinder Morgan, Inc. (formerly K N Energy, Inc. and a Kansas corporation) and subsidiaries for the year ended December 31, 1998 prior to the restatement (and, therefore, are not presented herein) for the retroactive application of the equity method of accounting for an investment as described in Note 2 to the restated financial statements. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the results of operations and cash flows of Kinder Morgan, Inc. and subsidiaries for the year ended December 31, 1998, in conformity with accounting principles generally accepted in the United States. /s/ Arthur Andersen LLP Denver, Colorado February 2, 1999 (except with respect to the matters discussed in Note 6, as to which the dates are March 16, 2000 and February 14, 2001) F-2 5 CONSOLIDATED STATEMENTS OF INCOME KINDER MORGAN, INC. AND SUBSIDIARIES
YEAR ENDED DECEMBER 31, --------------------------------------------- RESTATED - SEE NOTE 2 ---------------------------- 2000 1999 1998 ----------- ----------- ----------- (In Thousands Except Per Share Amounts) OPERATING REVENUES: Natural Gas Sales $ 1,999,648 $ 1,004,097 $ 955,254 Natural Gas Transportation and Storage 596,774 745,179 640,906 Other 117,315 87,092 64,099 ----------- ----------- ----------- Total Operating Revenues 2,713,737 1,836,368 1,660,259 ----------- ----------- ----------- OPERATING COSTS AND EXPENSES: Gas Purchases and Other Costs of Sales 1,960,083 1,050,250 836,614 Operations and Maintenance 164,286 184,888 170,035 General and Administrative 58,087 85,591 68,502 Depreciation and Amortization 108,165 147,933 155,363 Taxes, Other Than Income Taxes 27,973 34,561 28,290 Merger-related and Severance Costs -- 37,443 5,763 ----------- ----------- ----------- Total Operating Costs and Expenses 2,318,594 1,540,666 1,264,567 ----------- ----------- ----------- OPERATING INCOME 395,143 295,702 395,692 ----------- ----------- ----------- OTHER INCOME AND (EXPENSES): Kinder Morgan Energy Partners: Equity in Earnings 140,913 15,733 -- Amortization of Excess Investment (28,317) (7,335) -- Equity in Earnings (Losses) of Other Equity Investments (6,586) 24,651 31,141 Interest Expense, Net (243,155) (251,920) (205,840) Minority Interests (24,121) (24,845) (19,483) Other, Net 72,565 194,405 21,395 ----------- ----------- ----------- Total Other Income and (Expenses) (88,701) (49,311) (172,787) ----------- ----------- ----------- INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 306,442 246,391 222,905 Income Taxes 122,727 90,733 82,710 ----------- ----------- ----------- INCOME FROM CONTINUING OPERATIONS 183,715 155,658 140,195 ----------- ----------- ----------- DISCONTINUED OPERATIONS, NET OF TAX: Loss from Discontinued Operations -- (50,941) (77,984) Loss on Disposal of Discontinued Operations (31,734) (344,378) -- ----------- ----------- ----------- Total Loss From Discontinued Operations (31,734) (395,319) (77,984) ----------- ----------- ----------- NET INCOME (LOSS) 151,981 (239,661) 62,211 Less - Preferred Dividends -- 129 350 Less - Premium Paid on Preferred Stock Redemption -- 350 -- ----------- ----------- ----------- EARNINGS (LOSS) AVAILABLE FOR COMMON STOCK $ 151,981 $ (240,140) $ 61,861 =========== =========== =========== Number of Shares Used in Computing Basic Earnings Per Common Share (Thousands) 114,063 80,284 64,021 =========== =========== =========== BASIC EARNINGS (LOSS) PER COMMON SHARE: Continuing Operations $ 1.61 $ 1.93 $ 2.19 Loss from Discontinued Operations -- (0.63) (1.22) Loss on Disposal of Discontinued Operations (0.28) (4.29) -- ----------- ----------- ----------- Total Basic Earnings (Loss) Per Common Share $ 1.33 $ (2.99) $ 0.97 =========== =========== =========== Number of Shares Used in Computing Diluted Earnings Per Common Share (Thousands) 115,030 80,358 64,636 =========== =========== =========== DILUTED EARNINGS (LOSS) PER COMMON SHARE: Continuing Operations 1.60 1.93 2.17 Loss from Discontinued Operations -- (0.63) (1.21) Loss on Disposal of Discontinued Operations (0.28) (4.29) -- ----------- ----------- ----------- Total Diluted Earnings (Loss) Per Common Share $ 1.32 $ (2.99) $ 0.96 =========== =========== =========== DIVIDENDS PER COMMON SHARE $ 0.20 $ 0.65 $ 0.76 =========== =========== ===========
The accompanying notes are an integral part of these statements. F-3 6 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME KINDER MORGAN, INC. AND SUBSIDIARIES
YEAR ENDED DECEMBER 31, -------------------------------------- RESTATED - SEE NOTE 2 ------------------------ 2000 1999 1998 --------- --------- --------- (In Thousands) NET INCOME (LOSS) 151,981 (239,661) 62,211 Realized Gain on Equity Securities, Net of Tax 1,602 852 -- Unrealized Loss on Equity Securities, Net of Tax -- -- (6,697) --------- --------- --------- COMPREHENSIVE INCOME (LOSS) $ 153,583 $(238,809) $ 55,514 ========= ========= =========
The accompanying notes are an integral part of these statements. F-4 7 CONSOLIDATED BALANCE SHEETS KINDER MORGAN, INC. AND SUBSIDIARIES
DECEMBER 31, ---------------------------- RESTATED SEE NOTE 2 ----------- 2000 1999 ----------- ----------- (In Thousands) ASSETS CURRENT ASSETS: Cash and Cash Equivalents $ 141,923 $ 26,378 Restricted Deposits 14,063 51 Customer Accounts Receivable, Net 104,209 298,805 Receivable From Kinder Morgan Energy Partners -- 330,000 Other Receivables 64,309 7,646 Inventories 19,600 50,328 Gas Imbalances 40,838 51,024 Other 48,700 19,154 Net Current Assets of Discontinued Operations -- 58,991 ----------- ----------- 433,642 842,377 ----------- ----------- INVESTMENTS: Kinder Morgan Energy Partners 1,850,397 1,791,768 Other 143,698 132,971 ----------- ----------- 1,994,095 1,924,739 ----------- ----------- PROPERTY, PLANT AND EQUIPMENT, NET 5,724,617 5,789,564 ----------- ----------- DEFERRED CHARGES AND OTHER ASSETS 265,751 209,758 ----------- ----------- NET NON-CURRENT ASSETS OF DISCONTINUED OPERATIONS -- 659,236 ----------- ----------- TOTAL ASSETS $ 8,418,105 $ 9,425,674 =========== =========== LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES: Current Maturities of Long-term Debt $ 808,167 $ 7,167 Notes Payable 100,000 574,400 Accounts Payable 126,267 224,625 Accounts Payable - Kinder Morgan Energy Partners 13,534 -- Accrued Interest 72,222 73,000 Accrued Taxes 26,584 36,075 Gas Imbalances 39,496 74,992 Payable for Purchase of Thermo Companies 15,000 44,320 Reserve for Loss on Disposal of Discontinued Operations 23,694 535,630 Other 143,761 133,620 ----------- ----------- 1,368,725 1,703,829 ----------- ----------- OTHER LIABILITIES AND DEFERRED CREDITS: Deferred Income Taxes 2,284,496 2,231,224 Other 208,570 242,926 ----------- ----------- 2,493,066 2,474,150 ----------- ----------- LONG-TERM DEBT 2,478,983 3,293,326 ----------- ----------- KINDER MORGAN-OBLIGATED MANDATORILY REDEEMABLE PREFERRED CAPITAL TRUST SECURITIES OF SUBSIDIARY TRUST HOLDING SOLELY DEBENTURES OF KINDER MORGAN 275,000 275,000 ----------- ----------- MINORITY INTERESTS IN EQUITY OF SUBSIDIARIES 4,910 9,523 ----------- ----------- COMMITMENTS AND CONTINGENT LIABILITIES (NOTES 9 AND 17) STOCKHOLDERS' EQUITY: Preferred Stock (Note 13) -- -- Common Stock- Authorized - 150,000,000 Shares, Par Value $5 Per Share Outstanding - 114,578,800 and 112,838,379 Shares, Before Deducting 96,140 and 172,402 Shares Held in Treasury 572,894 564,192 Additional Paid-in Capital 1,189,270 1,203,008 Retained Earnings (Deficit) 37,584 (91,610) Other, Including Shares Held in Treasury (2,327) (5,744) ----------- ----------- Total Stockholders' Equity 1,797,421 1,669,846 ----------- ----------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 8,418,105 $ 9,425,674 =========== ===========
The accompanying notes are an integral part of these statements. F-5 8 CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY KINDER MORGAN, INC. AND SUBSIDIARIES
YEAR ENDED DECEMBER 31, --------------------------------------------------------------------------------- 2000 1999 1998 ------------------------- ------------------------- ------------------------- SHARES AMOUNT SHARES AMOUNT SHARES AMOUNT ----------- ----------- ----------- ----------- ----------- ----------- (Dollars In Thousands) PREFERRED STOCK: Beginning Balance -- $ -- 70,000 $ 7,000 70,000 $ 7,000 Redemption of Preferred Stock -- -- (70,000) (7,000) -- -- ----------- ----------- ----------- ----------- ----------- ----------- Ending Balance -- -- -- -- 70,000 7,000 ----------- ----------- ----------- ----------- ----------- ----------- COMMON STOCK: Beginning Balance 112,838,379 564,192 68,645,906 343,230 32,024,557 160,123 Sale of Common Stock, Net -- -- -- -- 12,500,000 62,500 Acquisition of Kinder Morgan Delaware -- -- 41,683,323 208,417 -- -- Acquisitions/Sales of Other Businesses 946,207 4,731 2,065,909 10,330 689,810 3,449 Employee and Executive Benefit Plans 794,214 3,971 443,241 2,215 549,570 2,758 Common Stock Split -- -- -- -- 22,881,969 114,400 ----------- ----------- ----------- ----------- ----------- ----------- Ending Balance 114,578,800 572,894 112,838,379 564,192 68,645,906 343,230 ----------- ----------- ----------- ----------- ----------- ----------- ADDITIONAL PAID-IN CAPITAL: Beginning Balance 1,203,008 694,223 266,435 Sale of Common Stock, Net -- -- 558,053 Costs Related to PEPS Offering (1,151) (514) (62,150) Revaluation of KMEP Investment (Note 5) (51,074) -- -- Acquisition of Kinder Morgan Delaware -- 470,831 -- Acquisition of Other Businesses 23,824 34,670 30,985 Employee and Executive Benefit Plans 14,663 3,798 15,371 Common Stock Split -- -- (114,471) ----------- ----------- ----------- Ending Balance 1,189,270 1,203,008 694,223 ----------- ----------- ----------- RETAINED EARNINGS (DEFICIT): Beginning Balance - as Previously Reported (95,615) 193,925 185,658 Restatement (Note 2) 4,005 2,222 -- ----------- ----------- ----------- Beginning Balance - As Restated (91,610) 196,147 185,658 Net Income (Loss) - as Previously Reported 151,981 (241,444) 59,989 Restatement (Note 2) -- 1,783 2,222 Cash Dividends: Common (22,787) (47,967) (51,372) Preferred -- (129) (350) ----------- ----------- ----------- Ending Balance 37,584 (91,610) 196,147 ----------- ----------- ----------- OTHER: DEFERRED COMPENSATION: Beginning Balance -- (10,686) (9,203) Executive Benefit Plans -- 10,686 (1,483) ----------- ----------- ----------- Ending Balance -- -- (10,686) ----------- ----------- ----------- TREASURY STOCK, AT COST: Beginning Balance (172,402) (4,142) (48,598) (1,417) (28,482) (1,124) Treasury Stock Acquired (1,743) (62) (135,510) (2,956) (60,994) (2,834) Treasury Stock Issued 78,005 1,877 -- -- -- -- Acquisition of Businesses -- -- -- -- 39,970 1,801 Dividend Reinvestment Plan -- -- 11,706 231 17,135 740 Common Stock Split -- -- -- -- (16,227) -- ----------- ----------- ----------- ----------- ----------- ----------- Ending Balance (96,140) (2,327) (172,402) (4,142) (48,598) (1,417) ----------- ----------- ----------- ----------- ----------- ----------- ACCUMULATED OTHER COMPREHENSIVE INCOME (NET OF TAX): Beginning Balance (1,602) (2,454) 4,243 Sale of Tom Brown, Inc. Common Stock 1,602 -- -- Unrealized Gain (Loss) on Equity Securities -- 852 (6,697) ----------- ----------- ----------- Ending Balance -- (1,602) (2,454) ----------- ----------- ----------- TOTAL OTHER (96,140) (2,327) (172,402) (5,744) (48,598) (14,557) ----------- ----------- ----------- ----------- ----------- ----------- TOTAL STOCKHOLDERS' EQUITY 114,482,660 $ 1,797,421 112,665,977 $ 1,669,846 68,597,308 $ 1,226,043 =========== =========== =========== =========== =========== ===========
The accompanying notes are an integral part of these statements. F-6 9 CONSOLIDATED STATEMENTS OF CASH FLOWS KINDER MORGAN, INC. AND SUBSIDIARIES
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS YEAR ENDED DECEMBER 31, --------------------------------------------- 2000 1999 1998 ----------- ----------- ----------- (In Thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net Income (Loss) $ 151,981 $ (239,661) $ 62,211 Adjustments to Reconcile Net Income (Loss) to Net Cash Flows from Operating Activities: Loss from Discontinued Operations, Net of Tax 31,734 395,319 77,984 Depreciation and Amortization 108,165 147,933 155,363 Deferred Income Taxes 105,424 57,609 24,516 Equity in Earnings of Kinder Morgan Energy Partners (112,596) -- -- Distributions from Kinder Morgan Energy Partners 121,323 15,000 -- Deferred Purchased Gas Costs 2,685 6,646 468 Net Gains on Sales of Facilities (61,684) (189,778) (19,552) Proceeds from Buyout of Contractual Gas Obligations -- -- 27,500 Changes in Other Working Capital Items [Note 1(M)] (48,466) 36,119 (40,506) Changes in Deferred Revenues (4,457) (15,641) 6,300 Other, Net (16,622) 13,142 (7,242) ----------- ----------- ----------- Net Cash Flows Provided by Continuing Operations 277,487 226,688 287,042 Net Cash Flows Provided by (Used in) Discontinued Operations (110,399) 94,488 (191,773) ----------- ----------- ----------- NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES 167,088 321,176 95,269 ----------- ----------- ----------- CASH FLOWS FROM INVESTING ACTIVITIES: Capital Expenditures (137,477) (97,644) (120,881) Proceeds from Sales to Kinder Morgan Energy Partners 500,302 -- -- Cash Paid for Acquisition of MidCon Corp., Net of Cash Acquired -- -- (2,191,555) Other Acquisitions (19,412) (34,565) 1,086 Investments (28,688) (10,044) (9,179) Proceeds from Sale of Tom Brown, Inc. Stock 14,823 28,650 -- Sale of U.S. Government Securities -- 1,092,415 1,062,453 Purchase of U.S. Government Securities -- -- (2,154,868) Proceeds from Sales of Other Assets 14,998 87,949 38,634 ----------- ----------- ----------- Net Cash Flows Provided By (Used In) Continuing Investing Activities 344,546 1,066,761 (3,374,310) Net Cash Flows Provided By (Used In) Discontinued Investing Activities 154,176 (46,568) (119,100) ----------- ----------- ----------- NET CASH FLOWS PROVIDED BY (USED IN) INVESTING ACTIVITIES 498,722 1,020,193 (3,493,410) ----------- ----------- ----------- CASH FLOWS FROM FINANCING ACTIVITIES: Short-Term Debt, Net (474,400) (1,117,446) (32,687) Long-Term Debt - Issued -- -- 2,750,000 Long-Term Debt - Retired (14,055) (158,934) (35,787) Common Stock Issued in Public Offering -- -- 650,000 Other Common Stock Issued 17,773 8,323 13,437 Other Financing, Net (45,239) -- -- Mandatorily Redeemable Trust Securities Issued -- -- 175,000 Preferred Stock Redeemed -- (7,350) -- Treasury Stock, Issued 1,877 231 740 Treasury Stock, Acquired (62) (2,956) (2,834) Cash Dividends, Common and Preferred (22,787) (48,096) (51,722) Minority Interests, Net (2,436) 379 9,697 Premium Equity Participating Securities Contract Fee and Securities Issuance Costs (10,936) (11,097) (78,219) ----------- ----------- ----------- NET CASH FLOWS (USED IN) PROVIDED BY FINANCING ACTIVITIES (550,265) (1,336,946) 3,397,625 ----------- ----------- ----------- Net Increase (Decrease) in Cash and Cash Equivalents 115,545 4,423 (516) Cash and Cash Equivalents at Beginning of Year 26,378 21,955 22,471 ----------- ----------- ----------- Cash and Cash Equivalents at End of Year $ 141,923 $ 26,378 $ 21,955 =========== =========== ===========
The accompanying notes are an integral part of these statements. F-7 10 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (A) Nature of Operations Kinder Morgan, Inc. is one of the largest midstream energy companies in America, operating more than 30,000 miles of natural gas and products pipelines. Our common stock is traded on the New York Stock Exchange under the ticker symbol "KMI." We are an energy services provider and have operations in 16 states in the Rocky Mountain and mid-continent regions, with principal operations in Arkansas, Colorado, Illinois, Iowa, Kansas, Nebraska, Oklahoma, Texas and Wyoming. Energy services we offer include: storing, transporting and selling natural gas, providing retail natural gas distribution services, and generating and selling electricity. We have both regulated and nonregulated operations. During 1999, we made significant acquisitions, including Kinder Morgan Delaware. As a result, through our general partner interest, we operate Kinder Morgan Energy Partners, L.P., a publicly traded pipeline master limited partnership, referred to in these Notes as "Energy Partners," and receive a substantial portion of our earnings from returns on this investment. In October 1999, K N Energy, Inc., (as we were then named) a Kansas corporation, acquired Kinder Morgan, Inc., a Delaware corporation, referred to in these Notes as "Kinder Morgan Delaware." We then changed our name to Kinder Morgan, Inc. Unless the context requires otherwise, references to "we," "us," "our," or the "Company" are intended to mean Kinder Morgan, Inc. (a Kansas corporation and formerly known as K N Energy, Inc.) and its consolidated subsidiaries. During the third and fourth quarters of 1999, we adopted and implemented plans to discontinue our businesses involved in (i) wholesale marketing of natural gas and natural gas liquids, (ii) gathering and processing of natural gas, including field services and short-haul intrastate pipelines, (iii) direct marketing of non-energy products and services and (iv) international operations. During the fourth quarter of 2000, we decided that, due to the start-up nature of these operations and the unwillingness of buyers to pay for the value created to date, it was not in the best interests of the Company to dispose of our international operations and, accordingly, we decided to retain them. Additional information concerning these discontinued operations is contained in Note 6. (B) Basis of Presentation The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the reported amounts of revenues and expenses. Actual results could differ from these estimates. The consolidated financial statements include the accounts of Kinder Morgan, Inc. and its majority-owned subsidiaries. Investments in jointly owned operations in which we have the ability to exercise significant influence over their operating and financial policies are accounted for under the equity method, as is our investment in Energy Partners, which is further described in Note 2. All material intercompany transactions and balances have been eliminated. Certain prior year amounts have been reclassified to conform to the current presentation. (C) Accounting for Regulatory Activities Our regulated public utilities are accounted for in accordance with the provisions of Statement of Financial Accounting Standards ("SFAS") No. 71, "Accounting for the Effects of Certain Types of Regulation," which prescribes the circumstances in which the application of generally accepted accounting principles is affected by the economic effects of regulation. F-8 11 Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges and credits that will be recovered from or refunded to customers through the ratemaking process. The following regulatory assets and liabilities are reflected in the accompanying Consolidated Balance Sheets:
DECEMBER 31, --------------------- 2000 1999 -------- -------- (In Thousands) REGULATORY ASSETS: Employee Benefit Costs $ 6,576 $ 6,909 Debt Refinancing Costs 1,664 1,992 Deferred Income Taxes 16,801 16,853 Purchased Gas Costs 23,470 27,043 Plant Acquisition Adjustments 454 454 Rate Regulation and Application Costs 3,040 3,095 -------- -------- Total Regulatory Assets 52,005 56,346 -------- -------- REGULATORY LIABILITIES: Employee Benefit Costs 5,967 5,967 Deferred Income Taxes 28,930 31,235 Purchased Gas Costs 14,415 25,926 -------- -------- Total Regulatory Liabilities 49,312 63,128 -------- -------- NET REGULATORY ASSETS (LIABILITIES) $ 2,693 $ (6,782) ======== ========
As of December 31, 2000, $45.0 million of our regulatory assets and $43.3 million of our regulatory liabilities were being recovered from or refunded to customers through rates over periods ranging from 1 to 13 years. (D) Revenue Recognition Policies We recognize revenues as services are rendered or goods are delivered and, if applicable, title has passed. Our rate-regulated retail natural gas distribution business bills customers on a monthly cycle billing basis. Revenues are recorded on an accrual basis, including an estimate at the end of each accounting period for gas delivered and, if applicable, title has passed but for which bills have not yet been rendered. With respect to our construction activities, we utilize the percentage of completion method whereby revenues and associated expenses are recognized over the construction period based on work performed in relation to the total expected for the entire project. (E) Earnings Per Share Basic earnings per share is computed based on the monthly weighted-average number of common shares outstanding during each period. Diluted earnings per share is computed based on the monthly weighted-average number of common shares outstanding during the periods, increased by the assumed exercise or conversion of securities (stock options and premium equity participating security units) convertible into common stock for which the effect of conversion or exercise using the treasury stock method would be dilutive. Dilutive securities assumed to have been converted or exercised totaled 967,700 for 2000, 73,800 for 1999 and 614,500 for 1998. Remaining stock options outstanding totaling 307,100 for 2000, 3,824,000 for 1999 and 785,000 for 1998 were not included in the earnings per share calculation because to do so would have been antidilutive. Note 12(B) contains more information regarding premium equity participating security units, while Note 16 contains more information regarding stock options. F-9 12 (F) Restricted Deposits Restricted Deposits consist of monies on deposit with brokers that are restricted to meet exchange trading requirements; see Note 14. (G) Inventories
DECEMBER 31, ------------------- 2000 1999 ------- ------- (In Thousands) Gas in Underground Storage (Current) $ 5,145 $38,499 Materials and Supplies 14,455 11,829 ------- ------- $19,600 $50,328 ======= =======
Inventories are accounted for using the following methods, with the percent of the total dollars at December 31, 2000 shown in parentheses: average cost (85.32%), last-in, first-out (10.26%) and first-in, first-out (4.42%). All non-utility inventories held for resale are valued at the lower of cost or market. We also maintain gas in our underground storage facilities on behalf of certain third parties. We receive a fee from our storage service customers but do not reflect the value of their gas stored in our facilities in the accompanying Consolidated Balance Sheets. (H) Other Investments
DECEMBER 31, --------------------- 2000 1999 -------- -------- (In Thousands) Thermo Companies $ 72,457 $ 63,528 TransColorado Pipeline Company 34,824 31,160 Tom Brown, Inc. Common Stock (Note 5) -- 12,283 Other 36,417 26,000 -------- -------- $143,698 $132,971 ======== ========
Investments consist primarily of equity method investments in unconsolidated subsidiaries and joint ventures, and include ownership interests in net profits and net cash flows. At December 31, 2000, "Other" included a $13.5 million investment in Wrightsville Development, LLC, a $6.0 million investment in Igasamex USA, Ltd, a $5.3 million investment in Front Range Holding, LLC, and approximately $4.5 million in assets held for deferred employee compensation, among other individually insignificant items. At December 31, 1999, "Other" included a $10.4 million investment in Front Range Holding, LLC, a $6.3 million investment in Igasamex USA, Ltd, and approximately $4.9 million in assets held for deferred employee compensation, among other individually insignificant items. (I) Property, Plant and Equipment Property, plant and equipment is stated at historical cost, which for constructed plant includes indirect costs such as payroll taxes, fringe benefits, administrative and general costs. Expenditures that increase capacities, improve efficiencies or extend useful lives are capitalized. Routine maintenance, repairs and renewal costs are expensed as incurred. The cost of normal retirements of depreciable utility property, plant and equipment, plus the cost of removal less salvage, is recorded in accumulated depreciation with no effect on current period earnings. Gains or losses are recognized upon retirement of non-utility property, plant and equipment, and utility property, plant and equipment constituting an operating unit or system, when sold or abandoned. F-10 13 In accordance with the provisions of SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," we review the carrying values of our long-lived assets whenever events or changes in circumstances indicate that such carrying values may not be recoverable. As yet, no asset or group of assets has been identified for which the sum of expected future cash flows (undiscounted and without interest charges) is less than the carrying amount of the asset(s) and, accordingly, no impairment losses have been recorded. However, currently unforeseen events and changes in circumstances could require the recognition of impairment losses at some future date. (J) Depreciation and Amortization Depreciation is computed based on the straight-line method over the estimated useful lives of assets. The range of estimated useful lives used in depreciating assets for each property type are as follows:
PROPERTY TYPE RANGE OF ESTIMATED USEFUL LIVES OF ASSETS - ------------- ----------------------------------------- (In Years) Natural Gas Pipelines 24 to 68 (Transmission assets: average 56) Retail Natural Gas Distribution 33 Power Generation 10 to 30 General and Other 3 to 56
(K) Interest Expense, Net "Interest Expense, Net" as presented in the accompanying Consolidated Statements of Income is net of (i) the debt component of the allowance for funds used during construction ("AFUDC - Interest"), (ii) in 1999, interest income related to government securities associated with the acquisition of MidCon Corp. and (iii) in 2000, interest income attributable to (i) our note receivable from Energy Partners associated with the sale of certain interests (see Note 5) and (ii) interest income associated with settlement of our net cash position with ONEOK, Inc.; see (N).
YEAR ENDED DECEMBER 31, ------------------------------- 2000 1999 1998 ------- ------- ------- (In Millions) AFUDC - Interest $ 2.6 $ 1.9 $ 2.3 Interest Income $ 2.6 $ 0.5 $ 46.4
As discussed in Note 2, in conjunction with the January 30, 1998, acquisition of MidCon Corp., we were required by the definitive stock purchase agreement to assume the Substitute Note for $1.4 billion and to collateralize the Substitute Note with bank letters of credit, a portfolio of government securities or a combination of the two. As a result, we had a significant amount of interest income during 1998 associated with the issuance of the Substitute Note, which has been reported together with the related interest expense as described above. In conjunction with our sale of certain assets to ONEOK as discussed in Note 6, we agreed to continue managing cash for these assets for a period of months, following which an audit was conducted to affirm the assignment of specific amounts to the two parties based on the timing of the underlying business transactions. We reported the interest income attributable to our net receivable resulting from this transaction together with the related interest expense as described above. (L) Other, Net "Other, Net" as presented in the accompanying Consolidated Statements of Income includes $61.7 million, $189.8 million and $19.6 million in 2000, 1999 and 1998, respectively, attributable to gains from sales of assets. These transactions are discussed in Note 5. F-11 14 (M) Cash Flow Information We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. "Other, Net," presented as a component of "Net Cash Flows From Operating Activities" in the accompanying Consolidated Statements of Cash Flows includes, among other things, undistributed equity in earnings of unconsolidated subsidiaries and joint ventures (other than Energy Partners) and other non-cash charges and credits to income. ADDITIONAL CASH FLOW INFORMATION: CHANGES IN OTHER WORKING CAPITAL ITEMS: (NET OF EFFECTS OF ACQUISITIONS AND SALES) INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
YEAR ENDED DECEMBER 31, --------------------------------------- 2000 1999 1998 --------- --------- --------- (In Thousands) Accounts Receivable $(172,781) $ (16,483) $ (19,626) Material and Supplies Inventory (2,626) 2,894 (962) Gas in Underground Storage - Current 32,453 (17,626) 6,598 Other Current Assets (27,737) 114 3,329 Accounts Payable 114,908 37,506 (68,774) Other Current Liabilities 7,317 29,714 38,929 --------- --------- --------- $ (48,466) $ 36,119 $ (40,506) ========= ========= =========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
YEAR ENDED DECEMBER 31, -------------------------------------- 2000 1999 1998 --------- --------- --------- (In Thousands) CASH PAID FOR: Interest (Net of Amount Capitalized) $ 248,177 $ 284,762 $ 189,929 ========= ========= ========= Distributions on Preferred Capital Trust Securities $ 21,913 $ 21,913 $ 14,754 ========= ========= ========= Income Taxes Paid (Received) $ 7,674 $ (10,883) $ 39,756 ========= ========= =========
In April 2000, we made the final scheduled payment for our third-quarter 1998 acquisition of interests in the Thermo Companies using 961,153 shares of our common stock, approximately $30 million of value. For our December 31, 2000 sale of assets to Energy Partners, we received both cash and non-cash consideration; see Note 5. In October 1999, we acquired Kinder Morgan Delaware in a non-cash transaction. During 1998, we acquired MidCon Corp. and interests in assets from the Thermo Companies in transactions that included both cash and non-cash components. For additional information on these transactions, see Note 2. (N) Accounts Receivable The caption "Customer Accounts Receivable, Net" in the accompanying Consolidated Balance Sheets is presented net of allowances for doubtful accounts of $2.3 million and $1.7 million at December 31, 2000 and 1999, respectively. The caption "Other Receivables" principally consists of a receivable from ONEOK due to cash management services provided to them during 2000 in conjunction with their purchase of certain of our assets as discussed in Note 6. F-12 15 (O) Stock-Based Compensation SFAS 123, "Accounting for Stock-Based Compensation," encourages, but does not require, entities to adopt the fair value method of accounting for stock-based compensation plans. As allowed under SFAS 123, we continue to apply Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees." Accordingly, compensation expense is not recognized for stock options unless the options are granted at an exercise price lower than the market price on the grant date. (P) Accounting for Certain Equity Transactions by Affiliates We account for our investment in Energy Partners (among other entities) under the equity method of accounting. In each accounting period, we record our share of these investees' earnings, and amortize any "excess" investment. We adjust the amount of our excess investment when an equity method investee or a consolidated subsidiary issues additional equity (or reacquires equity shares) in any manner that alters our ownership percentage. Differences between the per unit sales proceeds from these equity issuances (or reacquisitions) and our underlying book basis, as well as the pro rata portion of the excess investment (including associated deferred taxes), are recorded directly to paid-in capital rather than being recognized as gains or losses. Two such transactions are described in Note 5. (Q) Accounting for Risk Management Activities We utilize energy derivatives for the purpose of mitigating our risk resulting from fluctuations in the market price of natural gas and associated transportation. Prior to December 31, 2000, our accounting policy for these activities was based on a number of authoritative pronouncements including SFAS No. 80, "Accounting for Futures Contracts." This policy is described in detail in Note 14, as is our new policy, which is based on the accounting standard which became effective for us on January 1, 2001, SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." (R) Income Taxes Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. Deferred tax assets are reduced by a valuation allowance for the amount of any tax benefit we do not expect to be realized. 2. BUSINESS COMBINATIONS On October 7, 1999, we completed the acquisition of Kinder Morgan Delaware, the sole stockholder of the general partner of Energy Partners. Energy Partners is the nation's largest pipeline master limited partnership. It owns and operates one of the largest product pipeline systems in the United States, delivering gasoline, diesel and jet fuel to customers through more than 10,000 miles of pipeline and over 20 associated terminals. Additional assets include 10,000 miles of natural gas transportation pipelines; natural gas gathering and storage facilities; 28 bulk terminal facilities, which transload more than 40 million tons of coal, petroleum coke and other products annually; and Kinder Morgan CO2 Company, L.P. To effect the business combination, we issued approximately 41.5 million shares of our common stock in exchange for all of the outstanding shares of Kinder Morgan Delaware. Upon closing of the transaction, Richard D. Kinder, Chairman and Chief Executive Officer of Kinder Morgan Delaware, was named our Chairman and Chief Executive Officer, and we were renamed Kinder Morgan, Inc. In addition, we issued 200,000 shares of our common stock to Petrie Parkman & Co., Inc. in consideration for Petrie Parkman's F-13 16 advisory services rendered in connection with the acquisition of Kinder Morgan Delaware. The issuance of these shares was exempt from registration under Section 4(2) of the Securities Act of 1933, as amended. This acquisition was accounted for as a purchase for accounting purposes and, accordingly, the assets acquired and liabilities assumed were recorded at their respective estimated fair market values as of the acquisition date. The allocation of the purchase price resulted in an excess of the purchase price over Kinder Morgan Delaware's share of the underlying equity in the net assets of Energy Partners totaling $1.3 billion. This excess has been fully allocated to the Kinder Morgan Delaware investment in Energy Partners and reflects the estimated fair market value of this investment at the date of acquisition. This excess investment is being amortized over 44 years, approximately the estimated remaining useful life of Energy Partners' assets, and is shown in the accompanying Consolidated Income Statements as "Amortization of Excess Investment" under the sub-heading "Kinder Morgan Energy Partners" within "Other Income and (Expenses)." The assets, liabilities and results of operations of Kinder Morgan Delaware are included with those of Kinder Morgan beginning with the October 7, 1999 acquisition date. The following pro forma information gives effect to our acquisition of Kinder Morgan Delaware as if the business combination had occurred January 1 of each year presented. This unaudited pro forma information should be read in conjunction with the accompanying consolidated financial statements. This pro forma information does not necessarily indicate the financial results that would have occurred if this acquisition had taken place on the dates indicated, nor should it necessarily be viewed as an indicator of future financial results. UNAUDITED PRO FORMA FINANCIAL INFORMATION
YEAR ENDED DECEMBER 31, --------------------------------------------- 1999 1998 ----------- ----------- (Dollars in Millions Except Per Share Amounts) Operating Revenues $ 1,745.5 $ 1,660.9 Net Income (Loss) $ (233.9) $ 62.5 Diluted Earnings (Loss) Per Common Share $ (2.09) $ 0.58 Number of Shares Used in Computing Diluted Earnings Per Common Share (In Thousands) 112,334 106,319
During the third quarter of 1998, we completed our acquisition of interests in four independent power plants in Colorado from the Denver-based Thermo Companies, representing approximately 380 megawatts of electric generation capacity and access to approximately 130 Bcf of natural gas reserves. These generating facilities are located in Ft. Lupton, Colorado (272 megawatts) and Greeley, Colorado (108 megawatts) and sell their power output to Public Service Company of Colorado under long-term agreements. Payments for the Thermo interests were made over a two-year period, with the initial payment of 1,034,715 shares of our common stock having been made on October 21, 1998. Additional payments were made on January 4, 1999, consisting of 833,623 shares of our common stock and $15 million in cash, on April 20, 1999, consisting of 1,232,286 shares of our common stock and $20 million in cash and on April 20, 2000, with 961,153 shares of our common stock. This transaction was accounted for as a purchase. Under the purchase agreement, we were entitled, as soon as the consent of the other partner was obtained, to become a partner in a 50/50 joint venture in which Thermo had previously been a partner and, in the interim, to receive cash distributions from Thermo's former owners in lieu of our share of the joint venture's earnings. In the fourth quarter of 2000, we obtained the consent, became a partner in the venture and adopted the equity method of accounting for this investment. We restated all prior periods to reflect the equity method of accounting as required by the authoritative accounting guidelines. This restatement had the effect of decreasing operating revenues by $7.4 million and $4.9 million, increasing equity in earnings of unconsolidated subsidiaries by $10.5 million and $8.7 million, and increasing income from continuing operations by $1.8 million and $2.2 million, in each case for 1999 and 1998, respectively. F-14 17 On January 30, 1998, we acquired all of the outstanding shares of capital stock of MidCon Corp. from Occidental Petroleum Corporation for $2.1 billion in cash and the assumption of a $1.4 billion short-term note (which was repaid in January, 1999), at which time MidCon Corp. became our wholly owned subsidiary. MidCon was an energy company engaged in the purchase, gathering, processing, transmission and storage of natural gas and whose principal asset was Natural Gas Pipeline Company of America (referred to as "Natural" in these notes). The assets, liabilities and results of operations of MidCon are included with those of Kinder Morgan beginning with the January 30, 1998 acquisition date. The acquisition was initially financed through a combination of credit agreements; see Note 12. The acquisition was accounted for as a purchase for accounting purposes and, accordingly, the MidCon assets acquired and liabilities assumed were recorded at their fair market values as of the acquisition date. The allocation of purchase price resulted in the recognition of a gas plant acquisition adjustment of approximately $4.0 billion, principally representing the excess of the assigned fair market value of the assets of Natural over the historical cost for ratemaking purposes. This gas plant acquisition adjustment, none of which is currently being recognized for rate-making purposes, is being amortized over 55 years (see Note 4), approximately the estimated remaining useful life of Natural's interstate pipeline system. For the years ended December 31, 2000, 1999 and 1998, $73.3 million, $96.0 million and $97.9 million of such amortization, respectively, was charged to expense; see Note 4. The following pro forma information gives effect to our acquisition of MidCon Corp. as if the business combination had occurred at January 1, 1998. This unaudited pro forma information should be read in conjunction with the accompanying consolidated financial statements. This pro forma information does not necessarily indicate the financial results that would have occurred if this acquisition had taken place on the date indicated, nor is it necessarily comparable to subsequent financial results nor should it necessarily be viewed as an indicator of future financial results. UNAUDITED PRO FORMA FINANCIAL INFORMATION (Dollars in Millions Except Per Share Amounts)
YEAR ENDED DECEMBER 31, 1998 ------------ Operating Revenues $ 4,655.9 Net Income $ 65.6 Diluted Earnings Per Common Share $ 1.01 Number of Shares Used in Computing Diluted Earnings Per Common Share (In Thousands) 64,636
On February 22, 1999, Sempra Energy and we announced that our respective boards of directors had unanimously approved a definitive agreement under which Sempra and we would combine in a stock-and-cash transaction valued in the aggregate at $6.0 billion. On June 21, 1999, Sempra and we announced that we had mutually agreed to terminate the merger agreement. Sempra reimbursed us $5.95 million for expenses incurred in connection with the proposed merger. 3. MERGER-RELATED AND SEVERANCE COSTS In anticipation of the completion of the transaction with Kinder Morgan Delaware, during the third quarter of 1999, a number of our officers terminated their employment with us, as did certain other employees. In addition, we terminated the employment of a number of additional employees during the fourth quarter of 1999 and in early 2000 as a result of cost saving initiatives implemented following the closing of the Kinder Morgan Delaware transaction. In total, approximately 150 employees were severed. In conjunction with these terminations, we agreed to provide severance benefits and incurred certain legal and other associated costs. Also in conjunction with the Kinder Morgan Delaware transaction, we elected to discontinue certain projects, F-15 18 consolidate certain facilities and relocate certain employees. The $37.4 million pre-tax expense ($23.6 million after tax or $0.29 per diluted share) associated with these matters (included in the accompanying Consolidated Income Statement for 1999 under the caption "Merger-related and Severance Costs") was composed of the following: (i) severance and relocation, including restricted stock -- $22.7 million, (ii) facilities costs, including moving expenses -- $5.3 million, (iii) write-down/write-off of project costs -- $8.0 million and (iv) other -- $1.4 million. Of this total, approximately $9.4 million remained as an accrual at December 31, 1999, all of which was expended during the first half of 2000. The $5.8 million pre-tax expense ($3.6 million after tax or $0.06 per diluted share) included under the same caption for the year ended December 31, 1998 represents costs associated with our January 30, 1998 acquisition of MidCon Corp. For additional information on these business combinations, see Note 2. 4. CHANGE IN ACCOUNTING ESTIMATE Pursuant to a revised study of the useful lives of the underlying assets by an independent third party, in July 1999, we changed the depreciation rates associated with the gas plant acquisition adjustment recorded in conjunction with the acquisition of MidCon Corp. Relative to the amounts which would have been recorded utilizing the previous depreciation rates, this change had the effect of decreasing "Depreciation and Amortization" by approximately $19.3 million for the year ended December 31, 1999. Consequently, "Income from Continuing Operations" and "Net Income" were increased by approximately $12.1 million for the year ended December 31, 1999 ($0.15 per diluted common share). 5. INVESTMENTS AND SALES See Note 6 for information regarding sales of assets and businesses included in discontinued operations. In December 2000, we sold approximately $300 million of assets to Energy Partners effective December 31, 2000. The largest asset we sold was our wholly owned subsidiary Kinder Morgan Texas Pipeline, Inc. and certain associated entities (a major intrastate natural gas pipeline system). We also sold the Douglas and Casper gas processing facilities and associated natural gas gathering systems, our 50 percent interest in Coyote Gas Treating, LLC and our 25 percent interest in Thunder Creek Gas Services, L.L.C. As consideration for the sale, we received approximately $150 million in cash (with an additional cash payment for working capital), 0.6 million Energy Partners' common limited partner units and 2.7 million Class-B Energy Partners' common limited partner units. We recorded a pre-tax gain of $61.6 million (approximately $37.0 million after tax or $0.32 per diluted share) in conjunction with this sale. In August 2000, Kinder Morgan Power Company, one of our wholly owned subsidiaries, announced plans to build a 550-megawatt electric power plant in Jackson, Michigan. All necessary regulatory permits and approvals have been obtained, and construction on the $250 million natural gas-fired plant has begun. The plant is expected to begin producing power in June 2002. In May 2000, Kinder Morgan Power announced another 550-megawatt facility that is currently being constructed near Little Rock, Arkansas. In April 2000, Energy Partners issued 4.5 million limited partnership units in a public offering at a price of $39.75 per unit, receiving total net proceeds (after underwriting discount) of $171.3 million. We did not acquire any of these units. This transaction reduced our percentage ownership of Energy Partners from approximately 19.9% to approximately 18.6% and had the associated effects of increasing our investment in the net assets of Energy Partners by $6.1 million and reducing (i) our excess investment in Energy Partners by $81.1 million, (ii) associated accumulated deferred income taxes by $30.0 million, (iii) paid-in capital by $45.0 million and (iv) the monthly amortization of the excess investment by approximately $176 thousand. In February 2000, Energy Partners issued approximately 0.6 million common units as consideration for acquiring all the capital stock of Milwaukee Bulk Terminals, Inc. and Dakota Bulk Terminals, Inc. This transaction F-16 19 reduced our percentage ownership of Energy Partners and had the associated effects of increasing our investment in the net assets of Energy Partners by $1.1 million and reducing (i) our excess investment in Energy Partners by $11.3 million, (ii) associated accumulated deferred income taxes by $4.1 million, (iii) paid-in capital by $6.1 million and (iv) the monthly amortization of the excess investment by approximately $21 thousand; see Notes 1(P) and 2. In March 2000, we sold the 918,367 shares of Tom Brown, Inc. Common Stock we had held since early 1996 (see the discussion of the sale of Tom Brown Preferred Stock following). We recorded a pre-tax gain of $1.4 million ($0.8 million after tax or approximately $0.01 per diluted share). On December 30, 1999, we entered into an agreement with several of our wholly owned subsidiaries and Energy Partners. As a result, effective as of December 31, 1999, we sold all of our interests in the following to Energy Partners: (i) our wholly owned subsidiary, Kinder Morgan Interstate Gas Transmission LLC (formerly K N Interstate Gas Transmission Co.), (ii) our wholly owned subsidiary, Kinder Morgan Trailblazer LLC (formerly NGPL-Trailblazer, Inc.), which owns a one-third interest in Trailblazer Pipeline Company and (iii) our 49% interest in Red Cedar Gathering Company. In exchange, Energy Partners issued to us 9,810,000 common units representing limited partnership interest in Energy Partners. In addition, Energy Partners paid us $330 million in cash in early 2000. We recorded a pre-tax gain of $158.8 million (approximately $100.9 million after tax or $1.25 per diluted share) in conjunction with the sale of interests. On September 30, 1999, we sold (to an unaffiliated party) our interests in Stingray Pipeline Company, L.L.C., an offshore pipeline that gathers natural gas, and West Cameron Dehydration Company, L.L.C., which dehydrates natural gas for shippers on the Stingray Pipeline. On June 30, 1999, we sold our interests in the HIOS and UTOS offshore pipeline systems and related laterals to Leviathan Gas Pipeline Partners, L. P. These two sales yielded total cash proceeds of approximately $75.1 million, resulted in a total pretax gain of approximately $28.9 million (approximately $17.6 million after tax or $0.25 per diluted share), and substantially eliminated our investment in offshore assets. On September 3, 1999, we sold 1,000,000 shares of preferred stock of Tom Brown, Inc. for approximately $29 million in cash, realizing a gain of $2.2 million (approximately $1.3 million after tax or $0.02 per diluted share). In May 1999, we announced plans to build the Horizon Pipeline, which, through our wholly owned subsidiary Natural, we planned to own jointly with one or more other partners. An open season closed in June 1999 with service requests from shippers of more than 800 MMcf of natural gas per day, including 300 MMcf per day from Nicor Gas. In February 2000, Nicor, Inc. announced that it had signed an agreement to become an equal partner in the planned Horizon Pipeline with Natural. The Horizon Pipeline is a $75 million natural gas pipeline that will originate in Joliet, Illinois and extend 74 miles into northern Illinois, connecting the emerging supply hub at Joliet with Nicor Gas' distribution system and an existing Natural pipeline. On March 31, 1999, the TransColorado Gas Transmission Company ("TransColorado"), an enterprise we jointly own with Questar Corp., placed in service a 280-mile-long natural gas pipeline. This pipeline includes two compressor stations and extends from near Rangely, Colorado, to its southern terminus at the Blanco Hub near Aztec, New Mexico. The pipeline has a design transmission capacity of approximately 300 million cubic feet of natural gas per day. On October 14, 1998, TransColorado entered into a $200 million revolving credit agreement with a group of commercial banks. We provide a corporate guarantee for one-half of all amounts borrowed under the agreement. Beginning 24 months after the in-service date, Questar has the right, for a 12-month period, to require that we purchase Questar's ownership interest in TransColorado for $121 million. This right has been stayed; see Note 9. In September 1998, we sold some of our microwave towers and associated land and equipment to American Tower Corp., recognizing a pre-tax gain of $10.9 million ($6.7 million after tax or $0.10 per diluted share). In F-17 20 March 1998, we sold our Kansas retail natural gas distribution properties to Midwest Energy, Inc., recognizing a pre-tax gain of $8.5 million ($5.2 million after tax or $0.08 per diluted share). Concurrently with the sale, we received $27.5 million in cash in exchange for release of the purchaser from certain contractual gas purchase obligations, which amount is being amortized as an offset to gas purchases over a period of years as the associated volumes are sold. 6. DISCONTINUED OPERATIONS Prior to mid-1999, we had major business operations in the upstream (gathering and processing), midstream (natural gas pipelines) and downstream (wholesale and retail marketing) portions of the natural gas industry and, in addition, had (i) non-energy retail marketing operations in the form of a joint venture called en*able and (ii) limited international operations. During the third quarter of 1999, we adopted a plan to discontinue the direct marketing of non-energy products and services (principally under the "Simple Choice" brand). During the fourth quarter of 1999 and following our merger with Kinder Morgan Delaware, we adopted and implemented plans to discontinue the following lines of business: (i) gathering and processing natural gas, including short-haul intrastate pipelines and providing field services to natural gas producers, (ii) wholesale marketing of natural gas and natural gas liquids, and (iii) international operations. During the fourth quarter of 2000, we decided that, due to the start-up nature of these operations and the unwillingness of buyers to pay for the value created to date, it was not in the best interests of the Company to dispose of our international operations, which consist principally of a natural gas distribution system under development in Hermosillo, Mexico. Consequently, results from our international operations have been reclassified to continuing operations for all periods presented. The $3.9 million estimated after-tax loss on disposal recorded in 1999, consisting principally of a write down to estimated net realizable value including estimated costs of disposal, was reversed in 2000 and is included under the caption "Loss on Disposal of Discontinued Operations" in the accompanying Consolidated Statements of Income. The following table contains additional information concerning our international operations. INTERNATIONAL OPERATIONS
YEAR ENDED DECEMBER 31, ---------------------------- 2000 1999 1998 ------ ------ ------ (Thousands of dollars) Total Assets (at December 31) $32,347 $25,325 $12,838 Total Liabilities (at December 31) $ 3,984 $ 29 $ 779 Operating Revenues $ 5,699 $ 1,129 $ 4,249 Operating Loss $ 2,071 $ 2,523 $ 631
In accordance with the provisions of Accounting Principles Board Opinion No. 30, "Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions" ("APB 30"), our consolidated financial statements have been restated to present these businesses as discontinued operations. Accordingly, the revenues, costs and expenses, assets and liabilities and cash flows of these discontinued operations have been excluded from the respective captions in the accompanying Consolidated Statements of Income, Consolidated Balance Sheets and Consolidated Statements of Cash Flows, and have been reported in the various statements under the captions "Loss from Discontinued Operations, Net of Tax"; "Loss on Disposal of Discontinued Operations, Net of Tax"; "Net Current Assets of Discontinued Operations"; "Net Non-current Assets of Discontinued Operations"; "Net Cash Flows Provided by (Used in) Discontinued Operations" and "Net Cash Flows Provided By (Used In) Discontinued Investing Activities" for all relevant periods. In addition, certain of these Notes have been restated for all relevant periods to reflect the discontinuance of these operations. F-18 21 Summarized financial data of discontinued operations are as follows:
YEAR ENDED DECEMBER 31, --------------------------------------------- 2000 1999 1998 ----------- ----------- ----------- (In Thousands) Income Statement Data Operating Revenues: Wholesale Natural Gas and Liquids Marketing $ 580,159 $ 3,550,568 $ 2,580,459 Gathering and Processing, Including Field Services and Short-haul Intrastate Pipelines $ 436,979 $ 630,005 $ 640,623 Loss From Discontinued Operations, Net of Tax: Wholesale Marketing, Net of Tax Benefits of $9,300 and $7,869 $ (15,046) $ (14,837) Gathering and Processing, Net of Tax Benefits of $18,177 and $30,733 $ (29,404) $ (57,949) en*able/Orcom, Net of Tax Benefits of $4,150 and $2,757 $ (6,491) $ (5,198) Loss on Disposal of Discontinued Operations, Net of Tax: Wholesale Marketing, Net of Tax Benefits of $2,013 and $34,588 $ (3,013) $ (55,780) Gathering and Processing, Net of Tax Benefits of $21,617 and $169,413 $ (32,638) $ (273,202) en*able/Orcom, Net of Tax Benefits of $7,340 $ (11,479) International Operations, Net of $2,430 of Tax and $2,430 of Tax Benefits $ 3,917 $ (3,917)
With the exception of our international operations, which, as discussed above, we decided to retain, we completed the divestiture of our discontinued operations by December 31, 2000. In the fourth quarter of 2000, we recorded an incremental loss on disposal of discontinued operations of $31.7 million, representing the impact of the final disposition transactions and adjustment of previously recorded estimates. We had a remaining liability of approximately $23.7 million at December 31, 2000 associated with these discontinued operations, principally consisting of (i) indemnification obligations under the various sale agreements and (ii) retained liabilities, which were settled in cash in early 2001. Following is additional information concerning the various disposition transactions. We completed the disposition of our investment in en*able and sold our businesses involved in providing field services to natural gas producers (K N Field Services, Inc. and Compressor Pump and Engine, Inc.) and MidCon Gas Products of New Mexico Corp., a wholly owned subsidiary providing natural gas gathering and processing services, prior to the end of 1999. We received $23.3 million in cash as consideration for these sales. Effective March 1, 2000, ONEOK purchased our gathering and processing businesses in Oklahoma, Kansas and West Texas. In addition, ONEOK purchased our marketing and trading business, as well as certain storage and transmission pipelines in the Mid-continent region. As consideration, ONEOK paid us approximately $108 million plus approximately $56 million for estimated net working capital at closing (subject to post-closing adjustment). In addition, ONEOK assumed (i) the operating lease associated with the Bushton, Kansas processing plant and (ii) long-term throughput capacity commitments on Natural and Kinder Morgan Interstate. During the second quarter of 2000, we completed the sale of three natural gas gathering systems and a natural gas processing facility to WBI Holdings, Inc., the natural gas pipeline unit of MDU Resources Group, Inc. for approximately $21 million. Gathering systems included in the sale were the Bowdoin System located in north-central Montana, the Niobrara System located in northeastern Colorado and northwestern Kansas, and the Yenter System located in northeastern Colorado and western Nebraska. The natural gas processing facility included in the sale was the Yenter Plant, located northwest of Sterling, Colorado. During the fourth quarter of 2000, Wildhorse Energy Partners, LLC distributed all of its assets to the members and was dissolved. Formed in 1996, Wildhorse was owned 55 percent by us and 45 percent by Tom Brown. All the Wildhorse gathering and processing assets were distributed to Tom Brown and we received the Wolf F-19 22 Creek storage facility (which will be utilized in our natural gas distribution business) and cash. Also during the fourth quarter of 2000, our Douglas and Casper gas processing facilities and associated natural gas gathering systems, our 50 percent interest in Coyote Gas Treating, LLC and our 25 percent interest in Thunder Creek Gas Services, L.L.C. were included as part of a larger transaction with Energy Partners; see Note 5. 7. ACCOUNTS RECEIVABLE SALES FACILITY In September 1999, certain of our wholly owned subsidiaries entered into a five-year agreement to sell all of their accounts receivable, on a revolving basis, to K N Receivables Corporation, our wholly owned subsidiary. K N Receivables was formed prior to the execution of that receivables agreement for the purpose of buying and selling accounts receivable and was determined to be bankruptcy remote. Also in September 1999, K N Receivables entered into a five-year agreement with a financial institution whereby K N Receivables could sell, on a revolving basis, an undivided percentage ownership interest in certain eligible accounts receivable, as defined, up to a maximum of $150 million. This transaction was accounted for as a sale of receivables in accordance with SFAS No. 125, "Accounting for Transfer and Servicing of Financial Assets and Extinguishment of Liabilities." Accordingly, our accompanying Consolidated Balance Sheet at December 31, 1999, reflects the portion of receivables transferred to the financial institution as a reduction of Accounts Receivable. Losses from the sale of these receivables are included in "Other, Net" in the accompanying Consolidated Statements of Income during the periods in which the facility was utilized. We received compensation for servicing that was approximately equal to the amount an independent servicer would receive. Accordingly, no servicing assets or liabilities were recorded. The full amount of the allowance for possible losses was retained by K N Receivables. The fair value of this recourse liability approximated the allocated allowance for doubtful accounts given the short-term nature of the transferred receivables. We received $150 million in proceeds from the sale of receivables on September 30, 1999. The proceeds were subsequently used to retire notes payable of Kinder Morgan Delaware that were outstanding when we acquired it. Cash flows associated with this program are included with "Accounts Receivable" under "Cash Flows from Operating Activities" in the accompanying Statements of Consolidated Cash Flows. In February 2000, we reduced our participation in this receivables sale program by approximately $120 million, principally as a result of our then pending disposition of our wholesale gas marketing business. On April 25, 2000, we repaid the residual balance and terminated this agreement. 8. REGULATORY MATTERS On July 17, 2000, Natural filed its Compliance Plan, including pro forma tariff sheets, pursuant to FERC's Order Nos. 637 and 637-A. The FERC directed all interstate pipelines to file pro forma tariff sheets to comply with new regulatory requirements in the Orders regarding scheduling procedures, capacity segmentation, imbalance management services and penalty credits, or in the alternative, to explain why no changes to existing tariff provisions are necessary. Natural's filing is currently pending FERC action and any changes to its tariff provisions are not expected to take effect until after the entire Order 637 process is finished for all interstate pipelines. On May 10, 2000, Chesapeake Panhandle Limited Partnership filed a complaint with the FERC against Natural, MidCon Gas Products Corp., MidCon Gas Services Corp., K N Energy, Inc. and us. The complaint alleges that Natural collected an unlawful gathering rate from Chesapeake for the period March 1998 through December 1999. Chesapeake is seeking a refund totaling $5.2 million. We have responded and denied the allegations. On July 27, 2000, the FERC issued an order commencing a preliminary non-public investigation into the complaint. We believe that we have meritorious defenses to the claim. On January 23, 1998, Kinder Morgan Interstate filed a general rate case with the FERC, requesting a $30.2 million increase in annual revenues. As a result of the FERC's action, Kinder Morgan Interstate was allowed to F-20 23 place its rates into effect on August 1, 1998, subject to refund, and provisions for refund were recorded based on expected ultimate resolution. On November 3, 1999, Kinder Morgan Interstate filed a comprehensive Stipulation and Agreement to resolve all issues in this proceeding. The FERC approved the Stipulation and Agreement on December 22, 1999, and the settlement rates have been placed in effect. Kinder Morgan Interstate was sold to Energy Partners effective December 31, 1999; see Note 5. In November 1997, we announced a plan to give residential and small commercial customers in Nebraska a choice of natural gas suppliers. This program, the Nebraska Choice Gas program, became effective June 1, 1998. This program separates, or "unbundles," the consumer's natural gas purchases from other utility services. As of December 31, 2000, the plan had been approved by 178 of the 181 Nebraska municipalities we serve, representing approximately 91,000 customers served by us in Nebraska. 9. ENVIRONMENTAL AND LEGAL MATTERS (A) Environmental Matters On December 20, 1999, the U.S. Department of Justice filed a Complaint against Natural on behalf of the U.S. Environmental Protection Agency in the Federal District Court of Colorado, Civil Action 99-S-2419. The Complaint alleged that Natural failed to obtain all of the necessary air quality permits in 1979 when it constructed the Akron Compressor Station, which consisted of three compressor engines in Weld County, Colorado. Natural and the Environmental Protection Agency, through the Department of Justice, have settled this issue. The Environmental Protection Agency has agreed to dismiss all allegations and claims upon completion of the terms of the settlement. On December 17, 1999, the State of Colorado notified us of air quality permit compliance issues for several Kinder Morgan facilities. On September 21, 2000, we entered into a consent order with the State of Colorado to resolve the outstanding issues. In 1998, the Environmental Protection Agency published a final rule addressing transport of ground level ozone. The rule affected 22 Eastern and Midwestern states, including Illinois and Missouri, in which we operate gas compression facilities. The rule required reductions in emissions of nitrogen oxide, a precursor to ozone formation, from various emission sources, including utility and non-utility sources. The rule required that the affected states prepare and submit State Implementation Plans to the Environmental Protection Agency by September 1999, reflecting how the required emissions reductions would be achieved. Emission controls are required to be installed by May 1, 2003. The State Implementation Plans which will effectuate this rule have yet to be proposed or promulgated, and will require detailed analysis before their final economic impact can be ascertained. On March 3, 2000, the Washington D.C. Circuit Court issued a decision regarding the rule. The Circuit Court remanded certain issues back to the Environmental Protection Agency. On January 5, 2001, the Environmental Protection Agency proposed regulations concerning the remanded issues. The final regulations are expected to be promulgated later this year. While additional capital costs are likely to result from this rule, based on currently available information, we do not believe that these costs will have a material adverse effect on our business, cash flows, financial position or results of operations. On June 17, 1999, the Environmental Protection Agency published a final rule creating a standard to limit emissions of hazardous air pollutants from oil and natural gas production as well as from natural gas transmission and storage facilities. The standard requires that the affected facilities reduce emissions of hazardous air pollutants by 95 percent. This standard will require us to achieve this reduction either by process modifications or by installing new emissions control technology. The standard will affect our competitors and us in a like manner. The rule allows affected sources three years from the publication date to come into compliance. We have conducted a detailed analysis of the final rule to determine its overall effect. While F-21 24 additional capital costs are likely to result from this rule, the rule will not have a material adverse effect on our business, cash flows, financial position or results of operations. We have an established environmental reserve of approximately $19 million to address remediation issues associated with 38 projects. Based on current information and taking into account reserves established for environmental matters, we do not believe that compliance with federal, state and local environmental laws and regulations will have a material adverse effect on our business, cash flows, financial position or results of operations. In addition, the clean-up programs in which we are engaged are not expected to interrupt or diminish our operational ability to gather or transport natural gas. However, there can be no assurances that future events, such as changes in existing laws, the promulgation of new laws, or the development of new facts or conditions will not cause us to incur significant costs. (B) Litigation Matters "K N TransColorado, Inc. v. TransColorado Gas Transmission Company, et. al," Case No. 00-CV-129, District Court, County of Garfield, State of Colorado. On June 15, 2000, K N TransColorado filed suit against Questar TransColorado and several of its affiliated Questar entities, asserting claims for breach of fiduciary duties, breach of contract, constructive trust, rescission of the partnership agreement, breach of good faith and fair dealing, tortuous concealment, misrepresentation, aiding and abetting a breach of fiduciary duty, dissolution of the TransColorado partnership, and seeking a declaratory judgment, among other claims. The TransColorado partnership has been made a defendant for purposes of an accounting. The lawsuit stems from Questar's failure to support the TransColorado partnership, together with its decision to seek regulatory approval for a project that competes with the Partnership, in breach of its fiduciary duties as a partner. K N TransColorado seeks to recover damages in excess of $152 million due to Questar's breaches and, in addition, seeks punitive damages. In response to the complaint, on July 28, 2000, the Questar entities filed a counterclaim and third party claims against certain of our entities and us for claims arising out of the construction and operation of the TransColorado pipeline project. The claims allege, among other things, that the Kinder Morgan entities interfered with and delayed construction of the pipeline and made misrepresentations about marketing of capacity. The Questar entities seek to recover damages in excess of $185 million for an alleged breach of fiduciary duty and other claims. On December 15, 2000, the parties agreed to stay the exercise of a contractual provision purportedly requiring K N TransColorado to purchase Questar's interest in the pipeline and to investigate the appointment of an independent operator for the pipeline during the litigation. On January 31, 2001, the Court dismissed Questar's counterclaims for breach of duty of good faith and fair dealing and for indemnity and contribution and dismissed Questar's Third Party Complaint. Discovery has commenced. "Jack J. Grynberg v. K N Energy, Inc., Rocky Mountain Natural Gas Company, and GASCO, Inc.," Civil Action No. 92-N-2000. On October 9, 1992, Jack J. Grynberg filed suit in the United States District Court for the District of Colorado against us, Rocky Mountain Natural Gas Company and GASCO, Inc. alleging that these entities, the K N Entities, as well as K N Production Company and K N Gas Gathering, Inc., have violated federal and state antitrust laws. In essence, Grynberg asserts that the companies have engaged in an illegal exercise of monopoly power, have illegally denied him economically feasible access to essential facilities to store, transport and distribute gas, and illegally have attempted to monopolize or to enhance or maintain an existing monopoly. Grynberg also asserts certain state causes of action relating to a gas purchase contract. In February 1999, the Federal District Court granted summary judgment for the K N Entities as to some of Grynberg's antitrust and state law claims, while allowing other claims to proceed to trial. Grynberg has previously claimed damages in excess of $50 million. In addition to monetary damages, Grynberg has requested that the K N Entities be ordered to divest all interests in natural gas exploration, development and production properties, all interests in distribution and marketing operations, and all interests in natural gas storage facilities, in order to separate these interests from our natural gas gathering and transportation system in northwest Colorado. No trial date has been set. However, recent settlement conferences have occurred and the parties are continuing to provide information related to a Court ordered mediation. F-22 25 "Jack J. Grynberg, individually and as general partner for the Greater Green River Basin Drilling Program: 72-73 v. Rocky Mountain Natural Gas Company and K N Energy, Inc.," Case No. 90-CV-3686. On June 5, 1990, Jack J. Grynberg filed suit, which is presently pending in Jefferson County District Court for Colorado, against Rocky Mountain Natural Gas Company and us alleging breach of contract and fraud. In essence, Grynberg asserts claims that the named companies failed to pay Grynberg the proper price, impeded the flow of gas, mismeasured gas, delayed his development of gas reserves, and other claims arising out of a contract to purchase gas from a field in northwest Colorado. On February 13, 1997, the trial judge entered partial summary judgment for Mr. Grynberg on his contract claim that he failed to receive the proper price for his gas. This ruling followed an appellate decision that was adverse to us on the contract interpretation of the price issue, but which did not address the question of whether Grynberg could legally receive the price he claimed or whether he had illegally diverted gas from a prior purchase. Grynberg has previously claimed damages in excess of $30 million. On August 29, 1997, the trial judge stayed the summary judgment pending resolution of a proceeding at the FERC to determine if Grynberg was entitled to administrative relief from an earlier dedication of the same gas to interstate commerce. The background of that proceeding is described in the immediately following paragraph. On March 15, 1999, an Administrative Law Judge for the FERC ruled, after an evidentiary hearing, that Mr. Grynberg had illegally diverted the gas when he entered the contract with the named companies and was not entitled to relief. Grynberg filed exceptions to this ruling. In late March 2000, the FERC issued an order affirming in part and denying in part the motions for rehearing of its Initial Decision. On November 21, 2000, the FERC upheld the Administrative Law Judge's factual findings and denial of retroactive abandonment. Grynberg recently filed a Notice of Appeal of the FERC's decision to the D.C. Circuit Court of Appeals. The action in Colorado remains stayed pending final resolution of these proceedings. "Jack J. Grynberg v. Rocky Mountain Natural Gas Company," Docket No. GP91-8-008. "Rocky Mountain Natural Gas Company v. Jack J. Grynberg," Docket No. GP91-10-008. On May 8, 1991, Grynberg filed a petition for declaratory order with the FERC seeking a determination whether he was entitled to the price he seeks in the Jefferson County District Court proceeding referred to in the immediately preceding paragraph. While Grynberg initially received a favorable decision from the FERC, that decision was reversed by the Court of Appeals for the District of Columbia Circuit on June 6, 1997. This matter has been remanded to the FERC for subsequent proceedings. The matter was set for an expedited evidentiary hearing, and an Initial Decision favorable to Rocky Mountain was issued on March 15, 1999. That decision determined that Grynberg had intentionally diverted gas from an earlier dedication to interstate commerce in violation of the Natural Gas Act and denied him equitable administrative relief. On November 21, 2000, the FERC upheld the Administrative Law Judge's factual findings and denial of retroactive abandonment. Grynberg recently filed a Notice of Appeal of the FERC's decision to the D.C. Circuit Court of Appeals. Grynberg filed exceptions to this Initial Decision. In late March 2000, the FERC issued an order affirming in part and denying in part the motions for rehearing of its Initial Decision. In April 2000, we, together with the other parties, filed for rehearing. "United States of America, ex rel., Jack J. Grynberg v. K N Energy," Civil Action No. 97-D-1233, filed in the U.S. District Court, District of Colorado. This action was filed pursuant to the federal False Claim Act and involves allegations of mismeasurement of natural gas produced from federal and Indian lands. The Department of Justice has decided not to intervene in support of the action. The complaint is part of a larger series of similar complaints filed by Mr. Grynberg against 77 natural gas pipelines (approximately 330 other defendants). An earlier single action making substantially similar allegations against the pipeline industry was dismissed by Judge Hogan of the U.S. District Court for the District of Columbia on grounds of improper joinder and lack of jurisdiction. As a result, Mr. Grynberg filed individual complaints in various courts throughout the country. These cases were recently consolidated by the Judicial Panel for Multidistrict Litigation, and transferred to the District of Wyoming. Motions to Dismiss were filed on November 19, 1999. Plaintiff filed his response on January 14, 2000 and defendants filed their Reply Brief on February 14, 2000. An oral argument on the Motion to Dismiss occurred on March 17, 2000. On July 20, 2000 the United States of F-23 26 America filed a motion to dismiss those claims by Grynberg that deal with the manner in which defendants valued gas produced from federal leases. "Quinque Operating Company, et. al. v. Gas Pipelines, et. al.," Cause No. 99-1390-CM, United States District Court for the District of Kansas. This action was originally filed in Kansas state court in Stevens County, Kansas as a class action against approximately 245 pipeline companies and their affiliates, including certain Kinder Morgan entities. The plaintiffs in the case purport to represent a class of natural gas producers and fee royalty owners who allege that they have been subject to systematic gas mismeasurement by the defendants for more than 25 years. Subsequently, one of the defendants removed the action to Kansas Federal District Court. Thereafter, we filed a motion with the Judicial Panel for Multidistrict Litigation to consolidate this action for pretrial purposes with the Grynberg False Claim Act cases referred to above, because of common factual questions. On April 10, 2000, the MDL Panel ordered that this case be consolidated with the Grynberg federal False Claims Act cases. On January 12, 2001, the Federal District Court of Wyoming issued an oral ruling remanding the case back to the State Court in Stevens County, Kansas. A Motion to Reconsider the remand was filed and is currently pending. "Dirt Hogs, Inc. v. Natural Gas Pipeline Company of America, et al." There have been several related cases with Dirt Hogs, Inc. with allegations of breach of contract, false representations, improper requests for kickbacks and other improprieties. Essentially, the plaintiff claims that it should have been awarded extensive pipeline reclamation work without having to qualify or bid as a qualifying contractor. Case No. Civ-98-231-R, is a case which was dismissed in the U.S. District Court for the Western District of Oklahoma because of pleading deficiencies and is now on appeal to the 10th Circuit (Case No. 99-6-026). On April 10, 2000, the 10th Circuit upheld the dismissal of this action. Another case, arising out of the same factual allegations, was filed by Dirt Hogs in the District Court, Caddo County, Oklahoma (Case No. CJ-99-92), on March 29, 1999. By agreement of all parties, this action is currently stayed. A third related case, styled "Natural Gas Pipeline Company of America, et al. v. Dirt Hogs, Inc." (Case No. 99-360-R), resulted in a default judgment against Dirt Hogs. After initially appealing the default judgment, Dirt Hogs dismissed their appeal on September 1, 1999. "K N Energy, Inc., et al. v. James P. Rode and Patrick R. McDonald," Case No. 99CV1239, filed in the District Court, Jefferson County, Division 8, Colorado. Defendants counterclaimed and filed third party claims against several of our former officers and/or directors. Messrs. Rode and McDonald are former principal shareholders of Interenergy Corporation. We acquired Interenergy on December 19, 1997 pursuant to a Merger Agreement dated August 25, 1997. Rode and McDonald allege that K N Energy committed securities fraud, common law fraud and negligent misrepresentation as well as breach in contract. Plaintiffs are seeking an unspecified amount of compensatory damages, greater than $2 million, plus unspecified exemplary or punitive damages, attorney's fees and their costs. We filed a motion to dismiss, and on April 21, 2000, the Jefferson County District Court Judge dismissed the case against the individuals and us with prejudice. Defendants also filed a federal securities fraud action in the United States District Court for the District of Colorado on January 27, 2000 titled: "James P. Rode and Patrick R. McDonald v. K N Energy, Inc., et al.," Civil Action No. 00-N-190. This case initially raised the identical state law claims contained in the counterclaim and third party complaint in state court. Rode and McDonald filed an amended Complaint, which dropped the state-law claims. This Complaint is now the subject of a motion to dismiss filed by defendants. The case has been stayed pending the outcome of these motions. A third related class action case styled, "Adams vs. Kinder Morgan, Inc., et. al.," Civil Action No. 00-M-516, in the United States District Court for the District of Colorado was served on us on April 10, 2000. As of this date no class has been certified. We have filed a motion to dismiss this case. Oral argument on the Motions to Dismiss in the Rode/McDonald and Adams actions is scheduled for February 23, 2001. The cases remain stayed pending the resolution of these motions. We believe that we have meritorious defenses to all lawsuits and legal proceedings in which we are defendants and will vigorously defend against them. Based on our evaluation of the above matters, and after consideration F-24 27 of reserves established, we believe that the resolution of such matters will not have a material adverse effect on our business, financial position or results of operations. 10. PROPERTY, PLANT AND EQUIPMENT Investments in property, plant and equipment ("PP&E"), at cost, and accumulated depreciation and amortization ("Accumulated D&A") are as follows:
DECEMBER 31, 2000 ------------------------------------------------ PROPERTY, PLANT AND ACCUMULATED EQUIPMENT D&A NET ------------------- ----------- --------- (In Thousands) Natural Gas Pipelines $5,662,880 $262,073 $5,400,807 Retail Natural Gas Distribution 251,660 90,966 160,694 Electric Power Generation 79,696 2,608 77,088 General and Other 142,773 56,745 86,028 ---------- --------- ---------- PP&E Related to Continuing Operations $6,137,009 $412,392 $5,724,617 ========== ========= ==========
DECEMBER 31, 1999 ------------------------------------------------ PROPERTY, PLANT AND ACCUMULATED EQUIPMENT D&A NET ------------------- ----------- --------- (In Thousands) Natural Gas Pipelines $5,768,566 $240,949 $5,527,617 Retail Natural Gas Distribution 248,998 83,010 165,988 Electric Power Generation 27,873 1,915 25,958 General and Other 121,814 51,813 70,001 ---------- --------- ---------- PP&E Related to Continuing Operations $6,167,251 $377,687 $5,789,564 ========== ========= ==========
11. INCOME TAXES Components of the income tax provision applicable to continuing operations for federal and state income taxes are as follows:
YEAR ENDED DECEMBER 31, ------------------------------------------- 2000 1999 1998 -------- -------- -------- (Dollars in thousands) TAXES CURRENTLY PAYABLE: Federal $ 3,212 $ 19,340 $ 49,630 State 14,091 13,784 8,564 -------- -------- -------- Total 17,303 33,124 58,194 -------- -------- -------- TAXES DEFERRED: Federal 94,435 64,086 25,068 State 10,989 (6,477) (552) -------- -------- -------- Total 105,424 57,609 24,516 -------- -------- -------- TOTAL TAX PROVISION $122,727 $ 90,733 $ 82,710 ======== ======== ======== EFFECTIVE TAX RATE 40.0% 36.8% 37.1% ======== ======== ========
F-25 28 The difference between the statutory federal income tax rate and our effective income tax rate is summarized as follows:
YEAR ENDED DECEMBER 31, -------------------------------------- 2000 1999 1998 ------ ------ ------ FEDERAL INCOME TAX RATE 35.0% 35.0% 35.0% INCREASE (DECREASE) AS A RESULT OF: State Income Tax, Net of Federal Benefit 5.6% 1.9% 2.1% Other (0.6)% (0.1)% -- ------ ------ ------ EFFECTIVE TAX RATE 40.0% 36.8% 37.1% ====== ====== ======
Deferred tax assets and liabilities result from the following:
DECEMBER 31, ---------------------------- 2000 1999 ---------- ---------- (Dollars In Thousands) DEFERRED TAX ASSETS: Post-retirement Benefits $ 14,776 $ 28,299 Gas Supply Realignment Deferred Receipts 17,101 15,847 State Taxes 138,976 112,049 Book Accruals 39,505 29,186 Alternative Minimum Tax Credits 9,098 8,222 Net Operating Loss Carryforwards 107,033 112,080 Discontinued Operations 9,584 208,317 Capital Loss Carryforwards 42,914 -- Other 4,269 6,765 ---------- ---------- TOTAL DEFERRED TAX ASSETS 383,256 520,765 ---------- ---------- DEFERRED TAX LIABILITIES: Property, Plant and Equipment 2,009,086 2,087,109 Investments 654,263 656,781 Other 4,403 8,099 ---------- ---------- TOTAL DEFERRED TAX LIABILITIES 2,667,752 2,751,989 ---------- ---------- NET DEFERRED TAX LIABILITIES $2,284,496 $2,231,224 ========== ==========
For tax purposes we had available, at December 31, 2000, net operating loss carryforwards for regular federal income tax purposes of approximately $306 million which will expire as follows: $66 million in the year 2018, $211 million in the year 2019 and $29 million in the year 2020. We also had available, at December 31, 2000, capital loss carryforwards of $122 million which will expire in the year 2005. We believe it is more likely than not that all of the net operating loss carryforwards and capital loss carryforwards will be utilized prior to their expiration; therefore no valuation allowance is necessary. We also had available, at December 31, 2000, approximately $9 million of alternative minimum tax credit carryforwards which are available indefinitely. 12. FINANCING (A) Notes Payable At December 31, 2000, we had available a $500 million 364-day facility dated October 25, 2000, and a $400 million amended and restated five-year revolving credit agreement dated January 30, 1998. These bank facilities can be used for general corporate purposes, including backup for our commercial paper program, and include covenants that are common in such arrangements. For example, the $500 million facility requires consolidated debt to be less than 68% of consolidated capitalization. The $400 million facility requires that upon issuance of common stock to the holders of the premium equity participating security units at the maturity of the security units (November 2001), consolidated debt must be less than 67% of consolidated total F-26 29 capitalization. Both of the bank facilities require the debt of consolidated subsidiaries to be less than 10% of our consolidated debt and require the consolidated debt of each material subsidiary to be less than 65% of our consolidated total capitalization. The $400 million facility requires our consolidated net worth (inclusive of trust preferred securities) be at least $1.236 billion plus 50 percent of consolidated net income earned for each fiscal quarter beginning with the last quarter of 1998. The $500 million facility requires our consolidated net worth (inclusive of trust preferred securities) be at least $1.236 billion plus 50 percent of consolidated net income earned for each fiscal quarter beginning with the last quarter of 1999. Under the bank facilities, we are required to pay a facility fee based on the total commitment, at a rate that varies based on our senior debt rating. Facility fees paid in 2000 and 1999 were $1.6 million and $1.9 million, respectively. At December 31, 2000 and 1999, $100 million and $300 million, respectively, was outstanding under the bank facilities. Commercial paper issued by us and supported by the bank facilities are unsecured short-term notes with maturities not to exceed 270 days from the date of issue. During 2000, all commercial paper was redeemed within 52 days, with interest rates ranging from 5.60 percent to 7.50 percent. No commercial paper was outstanding at December 31, 2000. Commercial paper outstanding at December 31, 1999 was $274.4 million. The weighted-average interest rate on short-term borrowings outstanding at December 31, 1999 was 7.00 percent. Average short-term borrowings outstanding during 2000 and 1999 were $310.6 million and $620.9 million, respectively. During 2000 and 1999, the weighted-average interest rates on short-term borrowings outstanding were 6.52 percent and 5.56 percent (excluding the Substitute Note as described below), respectively. Our short-term debt of $908.2 million at December 31, 2000 consisted of (i) $100 million of borrowings under our revolving credit facilities, (ii) the $400 million of Reset Put Securities that are scheduled to be either remarketed or retired as of March 1, 2001, (iii) the $400 million of 6.45% Senior Notes, due November 2001 and (iv) $8.2 million of miscellaneous current maturities of long-term debt. We expect to retire the Reset Put Securities at March 1, 2001 utilizing a combination of cash on hand and incremental short-term borrowings, which will result in an extraordinary loss on early extinguishments of debt expected to total approximately $15 million. We expect that the $400 million of 6.45% Senior Notes will be retired at maturity with a portion of the $460 million of cash to be received from the issuance of common stock upon maturity of the Premium Equity Participating Securities, which occurs concurrently as discussed following. Apart from these items, our current assets and current liabilities are approximately equal. Given our expected cash flows from operations and our unused debt capacity, including our 5-year revolving credit facility, we do not expect any liquidity issues in the foreseeable future. Effective with the acquisition of MidCon Corp. on January 30, 1998, we entered into a $4.5 billion credit facility consisting of (i) a $1.4 billion 364-day credit facility to support the note issued to Occidental Petroleum Corporation in conjunction with the purchase of MidCon Corp., (ii) a $2.1 billion 364-day revolving facility, (iii) the $400 million facility, providing for loans and letters of credit, of which the letter of credit usage may not exceed $100 million and (iv) a 364-day $600 million revolving credit facility. The $1.4 billion and $2.1 billion facilities could be used only in conjunction with the acquisition of MidCon Corp. In addition to the working capital and acquisition components of the $4.5 billion facility, we assumed a short-term note for $1.4 billion payable to Occidental referred to as the "Substitute Note," which was initially collateralized by letters of credit issued under the $1.4 billion facility. In March 1998, we received net proceeds of approximately $2.34 billion from the public offerings of senior debt securities of varying maturities with principal totaling $2.35 billion. The net proceeds from these offerings were used to refinance borrowings under the $4.5 billion facility and to purchase U.S. government securities to replace a portion of the letters of credit that collateralized the Substitute Note. The $2.1 billion facility was repaid in its entirety and cancelled on March 10, 1998. The Substitute Note was repaid on January 4, 1999. On January 5, 1999, we cancelled the remaining letters of credit used to collateralize the Substitute Note. On January 8, 1999, the $600 million facility was replaced with a new $600 million 364-day facility, which was essentially the same as the previous agreement. On November 18, 1999, we replaced our then-existing $600 million 364-day facility with a new $550 million 364-day facility, which has subsequently been replaced with a new $500 million 364-day facility dated October 25, 2000 as discussed above. F-27 30 (B) Long-term Debt and Premium Equity Participating Security Units
DECEMBER 31, ------------------------------- 2000 1999 ----------- ----------- (In Thousands) DEBENTURES: 6.50% Series, Due 2013 $ 50,000 $ 50,000 7.85% Series, Due 2022 24,943 25,731 8.75% Series, Due 2024 75,000 75,000 7.35% Series, Due 2026 125,000 125,000 6.67% Series, Due 2027 150,000 150,000 7.25% Series, Due 2028 493,000 500,000 7.45% Series, Due 2098 150,000 150,000 SINKING FUND DEBENTURES: 9.95% Series, Due 2020 20,000 20,000 9.625% Series, Due 2021 45,000 45,000 8.35% Series, Due 2022 35,000 35,000 SENIOR NOTES: 6.45% Series, Due 2001 400,000 400,000 7.27% Series, Due 2002 10,000 15,000 6.45% Series, Due 2003 500,000 500,000 6.65% Series, Due 2005 500,000 500,000 6.80% Series, Due 2008 300,000 300,000 Reset Put Securities, 6.30%, Due 2021 400,000 400,000 Other 13,617 14,883 Unamortized Debt Discount (4,410) (5,121) Current Maturities of Long-term Debt (808,167) (7,167) ---------- ---------- TOTAL LONG-TERM DEBT $2,478,983 $3,293,326 ========== ==========
Maturities of long-term debt (in thousands) for the five years ending December 31, 2005 are $808,167, $10,417, $507,167, $7,167 and $507,167, respectively. The 2013 Debentures and the 2001, 2003 and 2005 Senior Notes are not redeemable prior to maturity. The 2022, 2028 and 2098 Debentures, the 2020 Sinking Fund Debentures and the 2002 and 2008 Senior Notes are redeemable in whole or in part, at our option at any time, at redemption prices defined in the associated prospectus supplements. The 2024, 2026 and 2027 Debentures are redeemable in whole or in part, at our option after October 15, 2002, August 1, 2006, and November 1, 2004, respectively, at redemption prices defined in the associated prospectus supplements. The 2021 and 2022 Sinking Fund Debentures are redeemable in whole or in part, at our option after August 1, 2001 and September 15, 2002, respectively, at redemption prices defined in the associated prospectus supplements. In November 1998 we sold $460 million principal amount of premium equity participating security units in an underwritten public offering. The net cash proceeds from the sale of the security units, together with additional funds we provided, were used to purchase U.S. Treasury Notes on behalf of the security unit holders. The Treasury Notes are the property of the security unit holders and are pledged to the collateral agent, for our benefit, to secure the obligation of the security unit holders to purchase our common stock. These security units obligate the holders to purchase a certain amount of our common stock, depending on the market price at November 30, 2001 (unless earlier terminated or settled at the option of the holders of the security units), and provide for the holders to receive interest at the rate of 8.25 percent per year during the three-year period. The interest is paid by the agent, which receives part of the necessary funds from the collateral agent, which holds 5.875% U.S. Treasury Notes purchased with the proceeds of the initial investment by the security unit holders. We pay the remaining 2.375 percent. We may defer the payment of all or any part of our portion of the contract fees until no later than the end of the three-year period. Any portion so deferred will accrue interest at the annual rate of 8.25 percent until paid. F-28 31 The face value of the security units is not recorded in the accompanying Consolidated Balance Sheets. The $29.4 million present value of the contract fee payable to the security unit holders has been recorded as a liability and as a reduction to paid-in capital. During the period in which the 2.375 percent contract fees are payable, accretion of the $3.4 million of discount initially recorded will increase the liability and further decrease paid-in capital. In addition, paid-in capital has been reduced for the issuance costs associated with the security units and the premium paid upon purchase of the Treasury Notes pledged to the collateral agent, which amounts total approximately $32.8 million. The $400 million of Reset Put Securities due March 1, 2021 are subject to mandatory redemption from the then-existing holders on March 1, 2001, either (i) through the exercise of a call option by Morgan Stanley & Co. International Limited or (ii) in the event Morgan Stanley does not exercise the call option, the automatic exercise of a mandatory put by First Trust National Association on behalf of the holders. The $12 million of proceeds we received from Morgan Stanley as consideration for the call option are being amortized as an adjustment to the effective interest rate on the Reset Put Securities. We currently expect that these securities will not be remarketed but, instead, will be retired utilizing a combination of cash and incremental short-term borrowings. This retirement is expected to result in an extraordinary loss, net of tax, of approximately $15 million. At December 31, 2000 and 1999, the carrying amount of our long-term debt was $3.3 billion and $3.3 billion, respectively. The estimated fair values of our long-term debt at December 31, 2000 and 1999 are shown in Note 18. (C) Capital Securities In April 1998, we sold $175 million of 7.63% Capital Trust Securities maturing on April 15, 2028, and in April 1997, we sold $100 million of 8.56% Capital Trust Securities maturing on April 15, 2027, each in an underwritten public offering. We created wholly owned business trusts, K N Capital Trust I and K N Capital Trust III, to make the sales. The transactions and balances of K N Capital Trust I and K N Capital Trust III are included in our consolidated financial statements, with the Capital Securities treated as a minority interest, shown in our Consolidated Balance Sheets under the caption "Kinder Morgan-Obligated Mandatorily Redeemable Preferred Capital Trust Securities of Subsidiary Trust Holding Solely Debentures of Kinder Morgan." Periodic payments made to the holders of these securities are classified under "Minority Interests" in the accompanying Consolidated Statements of Income. See Note 18 for the fair value of these securities. (D) Common Stock On November 17, 1999, our Board of Directors approved a reduction in the quarterly dividend from $0.20 per share to $0.05 per share. On November 9, 1998, our Board of Directors approved a three-for-two split of our common stock. The stock split was distributed on December 31, 1998, to shareholders of record at the close of business on December 15, 1998. The par value of the stock did not change. In March 1998, we received net proceeds of approximately $624.6 million from a public offering of 12.5 million shares (18.75 million shares after adjustment for the December 1998 three-for-two stock split) of our common stock. The net proceeds from this offering were used to refinance borrowings under the $4.5 billion Facility and to purchase U.S. government securities to replace a portion of the letters of credit that collateralized the Substitute Note. F-29 32 13. PREFERRED STOCK We have authorized 200,000 shares of Class A and 2,000,000 shares of Class B preferred stock, all without par value. (A) Class A $5.00 Cumulative Preferred Stock On April 13, 1999, we sent notices to holders of our Class A $5.00 Cumulative Preferred Stock of our intent to redeem these shares on May 14, 1999. Holders of 70,000 preferred shares were advised that on April 13, 1999, funds were deposited with the First National Bank of Chicago to pay the redemption price of $105 per share plus accrued but unpaid dividends. Under the terms of our Articles of Incorporation, upon deposit of funds to pay the redemption price, all rights of the preferred stockholders ceased and terminated except the right to receive the redemption price upon surrender of their stock certificates. At December 31, 2000 and 1999, we did not have any outstanding shares of Class A $5.00 Cumulative Series Preferred Stock. At December 31, 1998, we had 70,000 shares of Class A $5.00 Cumulative Series Preferred Stock outstanding. (B) Class B Preferred Stock We did not have any outstanding shares of Class B Preferred Stock at December 31, 2000, 1999 or 1998. 14. RISK MANAGEMENT We use energy financial instruments to reduce our risk of price changes in the spot and fixed price natural gas markets as discussed following. We are exposed to credit-related losses in the event of nonperformance by counterparties to these financial instruments but, given their existing credit ratings, do not expect any counterparties to fail to meet their obligations. The fair value of these risk management instruments reflects the estimated amounts that we would receive or pay to terminate the contracts at the reporting date, thereby taking into account the current unrealized gains or losses on open contracts. Market quotes are available for substantially all financial instruments we use. Energy risk management products we use include commodity futures and options contracts, fixed-price swaps and basis swaps. Pursuant to our Board of Director's approved policy, we are to engage in these activities only as a hedging mechanism against price volatility associated with pre-existing or anticipated physical gas sales, gas purchases, system use and storage in order to protect profit margins, and are prohibited from engaging in speculative trading. Commodity-related activities of the risk management group are monitored by our Risk Management Committee, which is charged with the review and enforcement of the Board of Director's risk management policy. Gains and losses on hedging positions are deferred and recognized as gas purchases expense in the periods in which the underlying physical transactions occur. Purchases or sales of commodity contracts require a dollar amount to be placed in margin accounts. In addition, we are required to post margins with certain over-the-counter swap partners. These margin requirements are determined based upon credit limits and mark-to-market positions. At December 31, 2000, we had $10.0 million in margin deposits associated with commodity contract positions and $4.0 million in margin deposits associated with over-the-counter swaps. These amounts are shown as "Restricted Deposits" in the accompanying Consolidated Balance Sheets. The differences between the current market value and the original physical contracts value, associated with hedging activities, are reflected, depending on maturity, as deferred charges or credits and other current assets or liabilities in the accompanying Consolidated Balance Sheets but, in 2001, will be included with "Other F-30 33 Comprehensive Income" as discussed following. In the event energy financial instruments are terminated prior to the period of physical delivery of the items being hedged, the gains and losses on the energy financial instruments at the time of termination remain deferred until the period of physical delivery. Given our portfolio of businesses as of December 31, 2000, our principal uses of derivative financial instruments will be to mitigate the risk associated with market movements in the price of natural gas associated with (i) the sale of in-kind fuel recoveries in excess of fuel used on Natural's pipeline system and (ii) the purchase of natural gas by Retail to serve its customers in the Choice Gas program. The "short" and "long" positions shown in the table that follows are principally associated with the activities described under (i) and (ii), respectively. Following is selected information concerning our risk management activities:
DECEMBER 31, 2000 --------------------------------------------- COMMODITY OVER-THE-COUNTER CONTRACTS SWAPS AND OPTIONS TOTAL --------- ----------------- --------- (In contracts and thousands of dollars) Deferred Net (Loss) Gain $ 14,036 $ (28,466) $ (14,430) Contract Amounts - Gross $ 65,730 $ 163,991 $ 229,721 Contract Amounts - Net $ 540 $ (93,283) $ (92,743) Credit Exposure of Loss $ 2,514 $ 2,514 Notional Volumetric Positions: Long 419 1,296 Notional Volumetric Positions: Short (500) (2,913) Net Notional Totals To Occur in 2001 (81) (1,459) Net Notional Totals To Occur in 2002 -- (158)
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (the "Statement"). The Statement establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. The Statement requires that changes in the derivatives fair value be recognized currently in earnings unless specific hedge accounting criteria are met. If the derivatives meet these criteria, the Statement allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company formally designate a derivative as a hedge and document and assess the effectiveness of derivatives associated with transactions that receive hedge accounting. The Statement, after amendment by SFAS 137 and SFAS 138, is effective for all quarters of all fiscal years beginning after June 15, 2000. The Statement cannot be applied retroactively. As discussed preceding, our principal use of derivative financial instruments is to mitigate the market price risk associated with anticipated transactions for the purchase and sale of natural gas. The Statement allows these transactions to continue to be treated as hedges for accounting purposes, although the changes in the market value of these instruments will affect comprehensive income in the period in which they occur and any ineffectiveness in the risk mitigation performance of the hedge will affect net income currently, although we do not expect the amount of such inefficiency to be material. The change in the market value of these instruments representing effective hedge operation will continue to affect net income in the period in which the associated physical transactions are consummated. Adoption of the Statement has resulted in the $14.4 million deferred net loss shown in the preceding table being reported as part of other comprehensive income, as well as subsequent changes in the market value of these derivatives prior to consummation of the transaction being hedged. F-31 34 15. EMPLOYEE BENEFITS (A) Retirement Plans We have defined benefit pension plans covering eligible full-time employees. These plans provide pension benefits that are based on the employees' compensation during the period of employment, age and years of service. These plans are tax-qualified subject to the minimum funding requirements of the "Employee Retirement Income Security Act of 1974." Our funding policy is to contribute annually the recommended contribution using the actuarial cost method and assumptions used for determining annual funding requirements. Plan assets consist primarily of pooled fixed income, equity, bond and money market funds. Plan assets included our common stock valued at $11.5 million and $5.1 million as of December 31, 2000 and 1999, respectively. Net periodic pension cost includes the following components:
YEAR ENDED DECEMBER 31, ------------------------------------------ 2000 1999 1998 -------- -------- -------- (In Thousands) Service Cost $ 7,306 $ 9,977 $ 4,859 Interest Cost 8,600 8,170 7,537 Expected Return on Assets (14,034) (13,381) (11,812) Net Amortization and Deferral (1,257) (210) (864) Recognition of Curtailment Gain -- (9) -- -------- -------- -------- Net Periodic Pension (Benefit) Cost $ 615 $ 4,547 $ (280) ======== ======== ========
The following table sets forth the reconciliation of the beginning and ending balances of the pension benefit obligation:
2000 1999 --------- --------- (In Thousands) Benefit Obligation at Beginning of Year $(118,038) $(121,076) Service Cost (7,306) (9,977) Interest Cost (8,600) (8,170) Actuarial Gain 3,922 14,602 Benefits Paid 6,915 6,421 Curtailment Gain -- 162 --------- --------- Benefit Obligation at End of Year $(123,107) $(118,038) ========= =========
F-32 35 The following table sets forth the reconciliation of the beginning and ending balances of the fair value of the plans' assets, the plans' funded status and prepaid pension cost amounts recognized under the caption "Other Current Assets" in our Consolidated Balance Sheets:
DECEMBER 31, --------------------------- 2000 1999 --------- --------- (In Thousands) Fair Value of Plan Assets at Beginning of Year $ 150,900 $ 143,983 Actual Return on Plan Assets During the Year 17,294 13,338 Benefits Paid During the Year (6,915) (6,421) --------- --------- Fair Value of Plan Assets at End of Year 161,279 150,900 Benefit Obligation at End of Year (123,107) (118,038) --------- --------- Plan Assets in Excess of Projected Benefit Obligation 38,172 32,862 Unrecognized Net Gain (33,134) (27,080) Prior Service Cost Not Yet Recognized in Net Periodic Pension Costs 88 105 Unrecognized Net Asset at Transition (696) (842) --------- --------- Prepaid Pension Cost $ 4,430 $ 5,045 ========= =========
The rate of increase in future compensation was 3.5 percent for 2000, 1999 and 1998. The expected long-term rate of return on plan assets was 9.5 percent for 2000 and 1999, and 8.5 percent for 1998. The weighted-average discount rate used in determining the actuarial present value of the projected benefit obligation was 7.75 percent for 2000 and 1999, and 6.75 percent for 1998. Effective January 1, 2001, we added a cash balance plan to our retirement plan. Certain collectively bargained employees and "grandfathered" employees will continue to accrue benefits through the defined pension benefit plan described above. All other employees will accrue benefits through a personal retirement account in the new cash balance plan. All employees converting to the cash balance plan will be credited with the current fair value of any benefits they have previously accrued through the defined benefit plan. We will then begin contributions on behalf of these employees equal to 3% of eligible compensation every pay period. In addition, we may make discretionary contributions to the plan based on our performance. Interest will be credited to the personal retirement accounts at the 30-year U.S. Treasury bond rate in effect each year. Employees will be fully vested in the plan after five years, and they may take a lump sum distribution upon termination or retirement. In 2000, we merged the Kinder Morgan Bulk Terminals Retirement Savings Plan and the Kinder Morgan Retirement Savings Plan with the Kinder Morgan Profit Sharing and Savings Plan, a defined contribution plan. The merged plan was renamed the Kinder Morgan, Inc. Savings Plan. On July 2, 2000, we began making regular contributions to the Plan. Contributions are made each pay period in an amount equal to 4% of compensation on behalf of each eligible employee. All contributions are in the form of Company stock, which is immediately convertible into other available investment vehicles at the employee's discretion. On July 25, 2000, our Board of Directors authorized an additional 6 million shares to be issued through the Plan, for a total of 6.7 million shares available. In addition to the above contributions, we may make annual discretionary contributions based on our performance. These contributions are made in the year following the year for which the contribution amount is calculated. The total amount contributed for 2000 was $3.7 million. No contribution was made to the profit sharing plan for 1999 or 1998. In January 1998, we acquired the MidCon Retirement Plan as part of our acquisition of MidCon Corp. (See Note 2.) The MidCon plan was a defined contribution plan. Contributions to the plan were based on age and earnings. Effective January 1, 1999, the MidCon plan was merged into the Profit Sharing Plan and all eligible MidCon employees joined our defined benefit pension plans. In 1999 and 1998, we contributed $0.7 million and $4.6 million, respectively, to the MidCon plan. F-33 36 (B) Other Postretirement Employee Benefits We have a defined benefit postretirement plan providing medical and life insurance benefits upon retirement for eligible employees and their eligible dependents, including former MidCon employees who met the eligibility requirements on the date of acquisition of MidCon Corp. (see Note 2). The MidCon postretirement medical and life insurance plans were "grandfathered" as of the acquisition date and no new employees have or will be added to the MidCon plans subsequent to the acquisition date. We fund the future expected postretirement benefit cost under the plan by making payments to Voluntary Employee Benefit Association trusts. Plan assets consist primarily of pooled fixed income funds. Net periodic postretirement benefit cost includes the following components:
YEAR ENDED DECEMBER 31, --------------------------------------- 2000 1999 1998 ------- ------- ------- (In Thousands) Service Cost $ 413 $ 450 $ 592 Interest Cost 7,159 6,655 6,425 Expected Return on Assets (4,790) (3,720) (2,854) Net Amortization and Deferral 992 908 919 Curtailment Gain -- -- (1,569) ------- ------- ------- Net Periodic Postretirement Benefit Cost $ 3,774 $ 4,293 $ 3,513 ======= ======= =======
The following table sets forth the reconciliation of the beginning and ending balances of the accumulated postretirement benefit obligation:
2000 1999 --------- --------- (In Thousands) Benefit Obligation at Beginning of Year $ (93,080) $(101,988) Service Cost (413) (450) Interest Cost (7,159) (6,655) Actuarial Gain (Loss) (8,191) 3,278 Benefits Paid 15,918 15,330 Retiree Contributions (2,253) (2,595) --------- --------- Benefit Obligation at End of Year $ (95,178) $ (93,080) ========= =========
F-34 37 The following table sets forth the reconciliation of the beginning and ending balances of the fair value of plan assets; the plan's funded status and the amounts included under the caption "Other" in the category "Other Liabilities and Deferred Credits" in our Consolidated Balance Sheets:
DECEMBER 31, ------------------------- 2000 1999 -------- -------- (In Thousands) Fair Value of Plan Assets at Beginning of Year $ 52,572 $ 45,364 Actual Return on Plan Assets (2,175) 4,320 Contributions by Employer 1,500 2,771 Retiree Contributions 1,726 2,246 Benefits Paid (2,467) (2,129) -------- -------- Fair Value of Plan Assets at End of Year 51,156 52,572 Benefit Obligation at End of Year (95,178) (93,080) -------- -------- Excess of Projected Benefit Obligation Over Plan Assets (44,022) (40,508) Unrecognized Net (Gain) Loss 12,779 (2,313) Unrecognized Net Obligations at Transition 11,149 12,078 -------- -------- Accrued Expense $(20,094) $(30,743) ======== ========
The weighted-average discount rate used in determining the actuarial present value of the accumulated postretirement benefit obligation was 7.75 percent for 2000 and 1999, and 6.75 percent for 1998. The expected long-term rate of return on plan assets was 9.5 percent for 2000 and 1999, and 8.5 percent for 1998. The assumed health care cost trend rate was 7 percent per year for 1999 and beyond (3 percent per year for 1999 and beyond for the MidCon plans). A one-percentage-point increase (decrease) in the assumed health care cost trend rate for each future year would have increased (decreased) the aggregate of the service and interest cost components of the 2000 net periodic postretirement benefit cost by approximately $23,332 ($22,163) and would have increased (decreased) the accumulated postretirement benefit obligation as of December 31, 2000 by approximately $205,055 ($214,589). 16. COMMON STOCK OPTION AND PURCHASE PLANS We have the following stock option plans: The 1982 Incentive Stock Option Plan, the 1982 Stock Option Plan for Non-Employee Directors, the 1986 Incentive Stock Option Plan, the 1988 Incentive Stock Option Plan, the 1992 Stock Option Plan for Non-Employee Directors, the 1994 Kinder Morgan, Inc. Long-term Incentive Plan (which also provides for the issuance of restricted stock), the American Oil and Gas Corporation Stock Incentive Plan and the Kinder Morgan, Inc. Amended and Restated 1999 Stock Option Plan. We also have an employee stock purchase plan. All per share amounts and shares outstanding or exercisable presented in this note have been restated to reflect the impact of the December 31, 1998, three-for-two common stock split as discussed in Note 12(D). On October 8, 1999, our Board of Directors approved the creation of the 1999 stock option plan, a broadly based non-qualified stock option plan. Under the plan, options may be granted to individuals who are regular full-time employees, including officers and directors who are employees. The aggregate number of shares of stock that may be issued under the plan is 5.5 million. Options under the plan vest in 25 percent increments on the anniversary of the grant over a four-year period from the date of grant. All options granted under the plan have a 10-year life, and must be granted at not less than the fair market value of Kinder Morgan, Inc. common stock at the close of trading on the date of grant. On January 17, 2001, our Board of Directors approved an additional 5 million shares for future grants to participants in the 1999 Stock Option Plan, which brings the aggregate number of shares subject to the plan to 10.5 million. The Board also approved an additional 0.5 million shares for future grants to participants in the 1992 Directors' Plan, which will be available subject to shareholder approval. F-35 38 Under all plans, except the Long-term Incentive Plan and the AOG Plan, options are granted at not less than 100 percent of the market value of the stock at the date of grant. Under the Long-term Incentive Plan options may be granted at less than 100 percent of the market value of the stock at the date of grant. Certain restricted stock awards include provisions accelerating the lapsing of restrictions in the event certain operating goals are met. Compensation expense was recorded totaling $0, $8.6 million, and $3.1 million for 2000, 1999, and 1998, respectively, relating to restricted stock grants awarded under the plans.
OPTION SHARES SHARES SUBJECT GRANTED THROUGH VESTING EXPIRATION PLAN NAME TO THE PLAN 12/31/00 PERIOD PERIOD --------- -------------- --------------- ------- --------- 1982 Plan 1,332,788 1,332,788 Immediate 10 Years 1982 Directors' Plan 186,590 186,590 3 Years 10 Years 1986 Plan 618,750 618,750 Immediate 10 Years 1988 Plan 618,750 618,750 Immediate 10 Years 1992 Directors' Plan 525,000 386,875 0 - 6 Months 10 Years Long-term Incentive Plan 5,700,000 2,754,839 0 - 5 Years 5 - 10 Years AOG Plan 775,500 775,500 3 Years 10 Years 1999 Plan 5,500,000 4,974,475 4 Years 10 Years
A summary of the status of our stock option plans at December 31, 2000, 1999 and 1998, and changes during the years then ended is presented in the table and narrative below:
2000 1999 1998 -------------------------- ------------------------ ------------------------- WTD. AVG. WTD. AVG. WTD. AVG. EXERCISE EXERCISE EXERCISE SHARES PRICE SHARES PRICE SHARES PRICE ---------- --------- --------- -------- --------- ---------- OUTSTANDING AT BEGINNING OF YEAR 7,542,898 $ 24.92 4,218,191 $ 24.38 3,220,065 $ 19.19 Granted 1,364,500 $ 30.42 4,837,656 $ 23.81 1,781,761 $ 31.40 Exercised (537,400) $ 19.26 (602,928) $ 8.00 (662,274) $ 16.46 Forfeited (2,276,179) $ 25.69 (910,021) $ 27.79 (121,361) $ 27.35 ---------- --------- --------- OUTSTANDING AT END OF YEAR 6,093,819 $ 26.05 7,542,898 $ 24.92 4,218,191 $ 24.38 ========== ======== ========= ======== ========= ======== EXERCISABLE AT END OF YEAR 2,056,771 $ 27.03 1,918,868 $ 26.54 1,794,112 $ 25.11 ========== ======== ========= ======== ========= ======== WEIGHTED-AVERAGE FAIR VALUE OF OPTIONS GRANTED $ 10.51 $ 5.83 $ 12.08 ======== ======== ========
The weighted-average fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following assumptions:
YEAR ENDED DECEMBER 31, --------------------------------------------- 2000 1999 1998 ---------- --------- ---------- RISK-FREE INTEREST RATE (%) 4.97 5.5 5.5 EXPECTED WEIGHTED-AVERAGE LIFE 4.5 years 4.0 years 4.0 years VOLATILITY 0.34 0.31 0.25 EXPECTED DIVIDEND YIELD (%) 0.38 3.2 3.5
We account for these plans under Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees." Had compensation cost for these plans been determined consistent with SFAS No. 123, "Accounting for Stock-Based Compensation" ("SFAS 123"), net income and diluted earnings per share would have been reduced to the pro forma amounts shown in the table below. Because the SFAS 123 method of accounting has not been applied to options granted prior to January 1, 1995, the resulting pro forma compensation cost may not be representative of that to be expected in future years. Additionally, the pro forma amounts include $0.5 F-36 39 million, $0.6 million and $0.6 million related to the purchase discount offered under the ESP Plan for 2000, 1999 and 1998, respectively.
YEAR ENDED DECEMBER 31, -------------------------------------------------- 2000 1999 1998 ----------- ----------- ----------- (In Thousands, Except Per Share Amounts) NET INCOME (LOSS): As Reported $ 151,981 $ (239,661) $ 62,211 =========== =========== =========== Pro Forma $ 144,526 $ (244,513) $ 58,109 =========== =========== =========== EARNINGS (LOSS) PER DILUTED SHARE: As Reported $ 1.32 $ (2.99) $ 0.96 =========== =========== =========== Pro Forma $ 1.26 $ (3.05) $ 0.90 =========== =========== ===========
The following table sets forth our December 31, 2000, common stock options outstanding, weighted-average exercise prices, weighted-average remaining contractual lives, common stock options exercisable and the exercisable weighted-average exercise price:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE ------------------------------------------------------------------------------------- ------------------------- WTD. AVG. WTD. AVG. NUMBER EXERCISE WTD. AVG. REMAINING NUMBER EXERCISE PRICE RANGE OUTSTANDING PRICE CONTRACTUAL LIFE EXERCISABLE PRICE ----------- ----------- --------- ------------------- ----------- --------- $00.00 - $23.72 166,228 $ 20.50 5.90 years 162,986 $ 20.44 $23.81 - $23.81 3,920,421 $ 23.81 8.77 years 1,018,417 $ 23.81 $24.04 - $39.38 2,007,170 $ 30.87 8.55 years 875,368 $ 32.00 ----------- ---------- 6,093,819 $ 26.05 8.61 years 2,056,771 $ 27.03 =========== ==========
Under the employee stock purchase plan, we may sell up to 2,400,000 shares of common stock to eligible employees. Employees purchase shares through voluntary payroll deductions. Prior to the 2000 plan year, shares were purchased annually at a 15 percent discount from the market value of the common stock, as defined in the plan, and issued in the month following the end of the plan year. Beginning with the 2000 plan year, shares are purchased quarterly at a 15 percent discount from the closing price of the common stock on the last trading day of each calendar quarter. Employees purchased 86,630 shares, 187,567 shares and 163,799 shares for plan years 2000, 1999 and 1998, respectively. Using the Black-Scholes model to assign value to the option inherent in the right to purchase stock under the provisions of the employee stock purchase plan, the weighted-average fair value per share of purchase rights granted in 2000, 1999 and 1998 was $6.60, $6.41 and $5.94, respectively. F-37 40 17. COMMITMENTS AND CONTINGENT LIABILITIES (A) Leases Expenses incurred under operating leases were $47.1 million in 2000, $57.8 million in 1999, and $56.9 million in 1998. Future minimum commitments under major operating leases as of December 31, 2000 are as follows:
YEAR AMOUNT - ---- ------ (In Thousands) 2001 $ 11,886 2002 8,376 2003 7,813 2004 7,563 2005 7,716 Thereafter 21,605 ---------- Total $ 64,959 ==========
(B) Guarantees of Unconsolidated Subsidiaries' Debt We have executed a guarantee of the revolving credit agreement of an unconsolidated subsidiary, TransColorado, in the amount of $100 million. As of December 31, 2000, $100 million had been borrowed with a maturity date of October 13, 2001. (C) Capital Expenditures Budget Approximately $5.5 million of our consolidated capital expenditure budget for 2001 had been committed for the purchase of plant and equipment at December 31, 2000. (D) Commitment to Sell or Purchase Assets We announced on November 30, 1999, that we entered into agreements with HS Resources, Inc. for the sale of certain assets in the Wattenberg field area of the Denver-Julesberg Basin. Under the terms of the agreements, HS Resources, Inc. commenced operating these assets. We are receiving cash payments from HS Resources, Inc. during 2000 and 2001, with the legal transfer of ownership expected to occur on or before December 15, 2001. We were committed, during a specified period, to purchase, at the option of the other party, an incremental 50% interest in a joint venture pipeline, although the ability of the other party to cause the purchase is currently stayed; see Notes 5 and 9. F-38 41 18. FAIR VALUE The following fair values of Investments, Long-term Debt, Capital Securities and Kinder Morgan Preferred Stock were estimated based on an evaluation made by an independent securities analyst. Fair values of "Energy Financial Instruments, Net" reflect the estimated amounts that we would receive or pay to terminate the contracts at the reporting date, thereby taking into account the current unrealized gains or losses on open contracts. Market quotes are available for substantially all instruments we use.
DECEMBER 31, ---------------------------------------------------------- 2000 1999 ------------------------- --------------------------- CARRYING CARRYING VALUE FAIR VALUE VALUE FAIR VALUE -------- ---------- --------- ----------- (In Millions) FINANCIAL ASSETS: Tom Brown, Inc. Common Stock (1) $ -- $ -- $ 12.3 $ 12.3 FINANCIAL LIABILITIES: Long-term Debt $3,291.6 $3,253.4 $3,305.6 $3,146.1 Capital Securities $ 275.0 $ 278.7 $ 275.0 $ 265.4 Energy Financial Instruments, Net $ 14.4 $ 14.4 $ 16.1 $ 16.1
(1) See Note 5 regarding the sale of this stock. 19. BUSINESS SEGMENT INFORMATION In accordance with the manner in which we manage our businesses, including the allocation of capital and evaluation of business unit performance, we report our operations in the following segments: (1) Natural Gas Pipeline Company of America and certain associated entities, referred to as Natural, a major interstate natural gas pipeline and storage system; (2) Retail, the regulated sale of natural gas to residential commercial and industrial customers and non-utility sales of natural gas to certain utility customers under the Choice Gas Program and (3) Power and Other, the construction and operation of natural gas fired electric generation facilities, together with various other activities not constituting separately managed or reportable business segments. In previous periods, we owned and operated other lines of business that we discontinued during 1999. In addition, our direct investment in the natural gas transmission and storage business has significantly decreased as a result of (i) the December 2000 sale of Kinder Morgan Texas Pipeline, Inc. to Energy Partners and (ii) the December 31, 1999 sale of Kinder Morgan Interstate Gas Transmission LLC to Energy Partners. The results of operations of these two businesses are included in our financial statements until their disposition, which is discussed in Note 5. The accounting policies applied in the generation of business unit information are generally the same as those described in Note 1 to the accompanying Consolidated Financial Statements, except that items below the "Operating Income" line are either not allocated to business units or are not considered by Management in its evaluation of business unit performance. An exception to this is that Power, which routinely conducts its business activities in the form of joint operations with other parties that are accounted for under the equity method of accounting, includes its equity in earnings of these investees in its operating results. These equity-method earnings are included in "Other Income and (Expenses)" in our consolidated income statement. In addition, certain items included in consolidated operating income (such as merger-related and severance costs and general and administrative expenses) are not allocated to individual business units. With adjustment for these items, we currently evaluate business unit performance primarily based on operating income in relation to the level of assets employed. Sales between business units are accounted for at market prices. For comparative purposes, prior period results and balances have been reclassified as necessary to conform to the current presentation. F-39 42 Natural's principal delivery market area encompasses the states of Illinois, Indiana, Iowa and portions of Wisconsin, Nebraska, Kansas, Missouri and Arkansas. Natural is the largest transporter of natural gas to the Chicago, Illinois area, its largest market. During 2000, approximately 50% of Natural's transportation represented deliveries to this market. Natural's storage capacity is largely located near its transportation delivery markets, effectively serving the same customer base. Natural has a number of individually significant customers, including local gas distribution companies in the greater Chicago area and major natural gas marketers and, during 2000, approximately 50% of its operating revenues were attributable to its nine largest customers. Retail's markets are represented by residential, commercial and industrial customers located in Colorado, Nebraska and Wyoming. These markets represent varied types of customers in many industries, but a significant amount of Retail's load is represented by the use of natural gas for space heating, grain drying and irrigation. The latter two groups of customers are concentrated in the agricultural industry and all markets are affected by the weather. Power's current principal market is represented by the local electric utilities in Colorado, which purchase the power output from its generation facilities. Its market will expand geographically as a result of power generation facilities planned or under construction and it is expected that future customers may include wholesale power marketers. During 2000 and 1999, we had revenues from a single customer of $740.5 million and $ 389.4 million, respectively, amounts in excess of 10 percent of consolidated operating revenues for each year. Both Natural and Kinder Morgan Texas made sales to this customer. With the transfer of Kinder Morgan Texas to Energy Partners as of December 31, 2000, sales to this customer are not expected to exceed 10% of consolidated operating revenues in the future, although certain of Natural's customers may meet this threshold. F-40 43 BUSINESS SEGMENT INFORMATION
DECEMBER 31, YEAR ENDED DECEMBER 31, 2000 2000 --------------------------------------------------------------------------- ------------ INCOME FROM REVENUES FROM DEPRECIATION CONTINUING EXTERNAL INTERSEGMENT AND CAPITAL SEGMENT OPERATIONS CUSTOMERS REVENUES AMORTIZATION EXPENDITURES ASSETS ----------- ------------- ------------ ------------- ------------ ----------- (In Thousands) Natural $ 342,887 $ 656,035 $ (18) $ 84,975 $ 38,555 $5,478,183 Kinder Morgan Interstate -- -- -- -- -- -- Retail 49,732 229,510 -- 11,776 10,730 350,042 Kinder Morgan Texas 29,318 1,747,499 -- 2,211 16,734 -- Power and Other(3) 31,293 80,693 4 9,203 71,458 2,589,880(1) Discontinued Operations -- -- -- -- 3,185 -- ---------- ---------- ---------- ---------- ---------- ---------- Consolidated 453,230 $2,713,737 $ (14) $ 108,165 $ 140,662 $8,418,105 ========== ========== ========== ========== ========== General and Administrative Expenses 58,087 Merger Related Costs -- ---------- Operating Income 395,143 Other Income and (Expenses) (88,701) ---------- Income from Continuing Operations Before Income Taxes $ 306,442 ==========
DECEMBER 31, YEAR ENDED DECEMBER 31, 1999 1999 --------------------------------------------------------------------------- ------------ INCOME FROM REVENUES FROM DEPRECIATION CONTINUING EXTERNAL INTERSEGMENT AND CAPITAL SEGMENT OPERATIONS CUSTOMERS REVENUES AMORTIZATION EXPENDITURES ASSETS ----------- ------------- ------------ ------------- ------------ ----------- (In Thousands) Natural $ 306,507 $ 625,705 $ 1,182 $ 109,346 $ 41,716 $5,469,050 Kinder Morgan Interstate 53,924 96,531 16,676 16,985 20,743 -- Retail 20,104 182,861 51 11,382 11,749 332,618 Kinder Morgan Texas 16,554 872,161 -- 2,466 4,567 255,200 Power and Other(3) 21,647 59,110 194 7,754 18,869 2,650,579(1) Discontinued Operations -- -- -- -- 28,363 718,227 ---------- ---------- ---------- ---------- ---------- ---------- Consolidated 418,736 $1,836,368 $ 18,103 $ 147,933 $ 126,007 $9,425,674 ========== ========== ========== ========== ========== General and Administrative Expenses 85,591 Merger Related Costs 37,443 ---------- Operating Income 295,702 Other Income and (Expenses) (49,311) ---------- Income from Continuing Operations Before Income Taxes $ 246,391 ==========
DECEMBER 31, YEAR ENDED DECEMBER 31, 1998 1998 --------------------------------------------------------------------------- ------------ INCOME FROM REVENUES FROM DEPRECIATION CONTINUING EXTERNAL INTERSEGMENT AND CAPITAL SEGMENT OPERATIONS CUSTOMERS REVENUES AMORTIZATION EXPENDITURES ASSETS ----------- ------------- ------------ ------------- ------------ ----------- (In Thousands) Natural $ 336,825 $ 556,662 $ 299 $ 121,008 $ 40,855 $5,421,029 Kinder Morgan Interstate 58,006 88,244 17,333 19,474 49,044 581,089 Retail 56,214 234,307 -- 11,014 17,405 362,289 Kinder Morgan Texas 2,129 739,201 -- 1,615 8,037 198,347 Power and Other(3) 16,783 41,845 5,535 2,252 5,539 1,519,510(2) Discontinued Operations -- -- -- -- 135,634 1,541,515 ---------- ---------- ---------- ---------- ---------- ---------- Consolidated 469,957 $1,660,259 $ 23,167 $ 155,363 $ 256,514 $9,623,779 ========== ========== ========== ========== ========== General and Administrative Expenses 68,502 Merger Related Costs 5,763 ---------- Operating Income 395,692 Other Income and (Expenses) (172,787) ---------- Income from Continuing Operations Before Income Taxes $ 222,905 ==========
(1) Principally the investment in Energy Partners and corporate cash and receivables (2) Principally government securities held as collateral for the Substitute Note (3) Restated, see Note 2. GEOGRAPHIC INFORMATION All but an insignificant amount of Kinder Morgan's assets and operations are located in the continental United States. F-41 44 QUARTERLY FINANCIAL INFORMATION (UNAUDITED) KINDER MORGAN, INC. AND SUBSIDIARIES QUARTERLY OPERATING RESULTS FOR 2000 AND 1999
2000 - THREE MONTHS ENDED ---------------------------------------------------------------- MARCH 31(1) JUNE 30(1) SEPTEMBER 30(1) DECEMBER 31 ----------- ---------- --------------- ----------- (In Thousands Except Per Share Amounts) Operating Revenues $ 480,481 $ 551,088 $ 750,465 $ 931,703 Gas Purchases and Other Costs of Sales 277,911 381,607 577,478 723,087 --------- --------- --------- --------- Gross Margin 202,570 169,481 172,987 208,616 Other Operating Expenses 89,881 87,819 87,517 93,294 --------- --------- --------- --------- Operating Income 112,689 81,662 85,470 115,322 Other Income and (Expenses) (35,477) (40,581) (40,624) 27,981(2) --------- --------- --------- --------- Income From Continuing Operations Before Income Taxes 77,212 41,081 44,846 143,303 Income Taxes 30,887 16,968 18,138 56,734 --------- --------- --------- --------- Income From Continuing Operations 46,325 24,113 26,708 86,569 Loss on Disposal of Discontinued Operations, Net of Tax(3) -- -- -- (31,734) --------- --------- --------- --------- Net Income $ 46,325 $ 24,113 $ 26,708 $ 54,835 ========= ========= ========= ========= Number of Shares Used in Computing Basic Earnings Per Share 113,058 114,196 114,461 114,535 Number of Shares Used in Computing Diluted Earnings Per Share 113,456 114,981 116,177 118,594 BASIC EARNINGS PER COMMON SHARE: Continuing Operations $ 0.41 $ 0.21 $ 0.23 $ 0.76 Loss on Disposal of Discontinued Operations -- -- -- (0.28) --------- --------- --------- --------- Total Basic Earnings Per Common Share $ 0.41 $ 0.21 $ 0.23 $ 0.48 ========= ========= ========= ========= DILUTED EARNINGS PER COMMON SHARE: Continuing Operations $ 0.41 $ 0.21 $ 0.23 $ 0.73 Loss on Disposal of Discontinued Operations -- -- -- (0.27) --------- --------- --------- --------- Total Diluted Earnings Per Common Share $ 0.41 $ 0.21 $ 0.23 $ 0.46 ========= ========= ========= =========
(1) Restated for a change to the equity method of accounting for an investment and reflects the reclassification of International's operating results to continuing operations. See Notes 2 and 6 of the accompanying Consolidated Financial Statements and the table presented below. (2) Includes the $62 million pre-tax gain from the contribution of certain assets to Energy Partners; see Note 5 of the accompanying Notes to Consolidated Financial Statements. (3) See Note 6 of the accompanying Notes to Consolidated Financial Statements.
2000 - THREE MONTHS ENDED ---------------------------------------------- MARCH 31 JUNE 30 SEPTEMBER 30 -------- ------- ------------ (In Thousands) Income From Continuing Operations as Previously Reported $ 46,084 $ 24,827 $ 26,628 Power Restatement: Operating Revenues (1,072) (598) (97) Other Income and (Expenses) 1,892 1,618 1,092 Income Taxes (328) (408) (398) Reclassification of International Operations (251) (1,326) (517) -------- -------- -------- Income From Continuing Operations as Restated $ 46,325 $ 24,113 $ 26,708 ======== ======== ========
F-42 45
1999 - THREE MONTHS ENDED(1) ---------------------------------------------------------------- MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 --------- --------- ------------ ----------- (In Thousands Except Per Share Amounts) Operating Revenues $ 425,696 $ 429,331 $ 495,906 $ 485,435 Gas Purchases and Other Costs of Sales 206,158 248,449 318,386 277,257 --------- --------- --------- --------- Gross Margin 219,538 180,882 177,520 208,178 Other Operating Expenses 118,593 119,292 107,361 107,727 Merger-Related and Severance Costs 2,916 (2,916) 10,962 26,481 --------- --------- --------- --------- Operating Income 98,029 64,506 59,197 73,970 Other Income and (Expenses) (58,162) (44,145) (48,729) 101,725(2) --------- --------- --------- --------- Income From Continuing Operations Before Income Taxes 39,867 20,361 10,468 175,695 Income Taxes 15,582 8,056 4,465 62,630 --------- --------- --------- --------- Income From Continuing Operations 24,285 12,305 6,003 113,065 --------- --------- --------- --------- Discontinued Operations, Net of Tax(3): Loss From Discontinued Operations (16,720) (14,500) (7,989) (11,732) Loss on Disposal of Discontinued Operations -- -- (11,479) (332,899) --------- --------- --------- --------- Total Loss From Discontinued Operations (16,720) (14,500) (19,468) (344,631) --------- --------- --------- --------- Net Income (Loss) 7,565 (2,195) (13,465) (231,566) Less-Preferred Dividends 88 41 -- -- Less-Premium Paid on Preferred Stock Redemption -- 350 -- -- --------- --------- --------- --------- Earnings (Loss) Available for Common Stock $ 7,477 $ (2,586) $ (13,465) $(231,566) ========= ========= ========= ========= Number of Shares Used in Computing Basic Earnings Per Share 69,486 70,689 70,914 110,047 Number of Shares Used in Computing Diluted Earnings Per Share 69,578 70,761 70,986 110,105 BASIC EARNINGS (LOSS) PER COMMON SHARE: Continuing Operations $ 0.35 $ 0.17 $ 0.08 $ 1.03 Discontinued Operations (0.24) (0.21) (0.11) (0.11) Loss on Disposal of Discontinued Operations -- -- (0.16) (3.02) --------- --------- --------- --------- Total Basic Earnings (Loss) Per Common Share $ 0.11 $ (0.04) $ (0.19) $ (2.10) ========= ========= ========= ========= DILUTED EARNINGS (LOSS) PER COMMON SHARE: Continuing Operations $ 0.35 $ 0.17 $ 0.08 $ 1.03 Discontinued Operations (0.24) (0.21) (0.11) (0.11) Loss on Disposal of Discontinued Operations -- -- (0.16) (3.02) --------- --------- --------- --------- Total Diluted Earnings (Loss) Per Common Share $ 0.11 $ (0.04) $ (0.19) $ (2.10) ========= ========= ========= =========
(1) Restated for a change to the equity method of accounting for an investment and reflects the reclassification of International's operating results to continuing operations. See Notes 2 and 6 of the accompanying Consolidated Financial Statements and the table presented below. (2) Includes the $158 million pre-tax gain from the contribution of certain assets to Energy Partners; see Note 5 of the accompanying Notes to Consolidated Financial Statements. (3) See Note 6 of the accompanying Notes to Consolidated Financial Statements. F-43 46
1999 - THREE MONTHS ENDED ---------------------------------------------------------------- MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 --------- --------- ------------ ----------- (In Thousands) Income From Continuing Operations as Previously Reported $ 23,908 $ 12,380 $ 5,886 $ 112,478 Power Restatement: Operating Revenues (2,058) (2,580) (1,201) (1,595) Other Income and (Expenses) 2,797 2,934 2,955 1,720 Income Taxes (296) (141) (702) (50) Reclassification of International Operations (66) (288) (935) 512 --------- --------- --------- --------- Income From Continuing Operations as Restated $ 24,285 $ 12,305 $ 6,003 $ 113,065 ========= ========= ========= =========
F-44 47 SELECTED FINANCIAL DATA FIVE-YEAR REVIEW KINDER MORGAN, INC. AND SUBSIDIARIES (In Thousands, Except Per Share Amounts)
YEAR ENDED DECEMBER 31, --------------------------------------------------------------------------------------- 2000 1999(1,3) 1998(1,4) 1997 1996 ---------- ---------- ---------- --------- --------- Operating Revenues $2,713,737 $1,836,368 $1,660,259 $ 340,685 $ 299,608 Gas Purchases and Other Costs of Sales 1,960,083 1,050,250 836,614 134,476 102,725 ---------- ---------- ---------- --------- --------- Gross Margin 753,654 786,118 823,645 206,209 196,883 Other Operating Expenses 358,511 490,416 427,953 128,059 128,895 ---------- ---------- ---------- --------- --------- OPERATING INCOME 395,143 295,702 395,692 78,150 67,988 Other Income and (Expenses) (88,701) (49,311) (172,787) (21,039) (14,798) ---------- ---------- ---------- --------- --------- Income From Continuing Operations Before Income Taxes 306,442 246,391 222,905 57,111 53,190 Income Taxes 122,727 90,733 82,710 12,777 17,304 ---------- ---------- ---------- --------- --------- INCOME FROM CONTINUING OPERATIONS 183,715 155,658 140,195 44,334 35,886 Gain (Loss) From Discontinued Operations, Net of Tax (31,734) (395,319) (77,984) 33,163 27,933 ---------- ---------- ---------- --------- --------- NET INCOME (LOSS) 151,981 (239,661) 62,211 77,497 63,819 Less-Preferred Dividends -- 129 350 350 398 Less-Premium Paid on Preferred Stock Redemption -- 350 -- -- -- ---------- ---------- ---------- --------- --------- EARNINGS (LOSS) AVAILABLE FOR COMMON STOCK $ 151,981 $ (240,140) $ 61,861 $ 77,147 $ 63,421 ========== ========== ========== ========= ========= Number of Shares Used in Computing Diluted Earnings Per Common Share 115,030 80,358 64,636 47,307 44,436 ========== ========== ========== ========== ========== DILUTED EARNINGS (LOSS) PER COMMON SHARE: Continuing Operations $ 1.60 $ 1.93 $ 2.17 $ 0.93 $ 0.80 Discontinued Operations (0.28) (4.92) (1.21) 0.70 0.63 ---------- ---------- ---------- ---------- ---------- Total Diluted Earnings (Loss) Per Common Share $ 1.32 $ (2.99) $ 0.96 $ 1.63 $ 1.43 ========== ========== ========== ========== ========== DIVIDENDS PER COMMON SHARE $ 0.20 $ 0.65 $ 0.76 $ 0.73 $ 0.70 ========== ========== ========== ========== ========== CAPITAL EXPENDITURES(2) $ 137,477 $ 97,644 $ 120,881 $ 230,814 $ 88,755 ========== ========== ========== ========== ========== TOTAL ASSETS(5) $8,418,105 $9,425,674 $9,623,779 $2,305,805 $1,629,720 ========== ========== ========== ========== ========== CAPITALIZATION(5): Common Stockholders' Equity $1,797,421 40% $1,669,846 32% $1,219,043 25% $ 606,132 48% $ 519,794 55% Preferred Stock -- -- -- -- 7,000 -- 7,000 -- 7,000 1% Preferred Capital Trust Securities 275,000 6% 275,000 5% 275,000 6% 100,000 8% -- -- Long-Term Debt 2,478,983 54% 3,293,326 63% 3,300,025 69% 553,816 44% 423,676 44% ---------- --- ---------- --- ---------- --- ---------- --- ---------- --- Total Capitalization $4,551,404 100% $5,238,172 100% $4,801,068 100% $1,266,948 100% $ 950,470 100% ========== === ========== === ========== === ========== === ========== === BOOK VALUE PER COMMON SHARE(5) $ 15.70 $ 14.82 $ 17.77 $ 12.63 $ 11.44 ========== ========== ========== ========== ==========
(1) Restated, see Note 2 of the accompanying Notes to Consolidated Financial Statements. (2) Capital Expenditures shown are for continuing operations only. (3) Reflects the acquisition of Kinder Morgan Delaware on October 7, 1999. See Note 2 of the accompanying Notes to Consolidated Financial Statements. (4) Reflects the acquisition of MidCon Corp. on January 30, 1998. See Note 2 of the accompanying Notes to Consolidated Financial Statements. (5) At December 31 of each respective year F-45 48 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS GENERAL In this report, unless the context requires otherwise, references to "we," "us," "our," or the "Company" are intended to mean Kinder Morgan, Inc. (a Kansas corporation and formerly known as K N Energy, Inc.) and its consolidated subsidiaries. The following discussion should be read in conjunction with the accompanying Consolidated Financial Statements and related Notes. Specifically, as discussed in Notes 2, 5 and 6 of the accompanying Notes to Consolidated Financial Statements, we have engaged in acquisitions (including the October 1999 acquisition of Kinder Morgan (Delaware), Inc., a Delaware corporation and the indirect owner of the general partner interest in Kinder Morgan Energy Partners, L.P., a publicly-traded master limited partnership, referred to in this report as "Energy Partners"), and divestitures (including the discontinuance of certain lines of business and the transfer of certain assets to Energy Partners), which may affect comparisons of financial position and results of operations between periods. Certain information contained in this report may include "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are subject to risks and uncertainties and are based on the beliefs and assumptions of our management, based on information currently available to our management. When words such as "believes," "expects," "anticipates," "intends," "plans," "estimates," "should" or similar expressions are used, we are making forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Our future results and stockholder values may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results and values are beyond our ability to control or predict. These statements are necessarily based upon various assumptions involving judgments with respect to the future including, among others, the ability to achieve cost savings and revenue growth, national, international, regional and local economic, competitive and regulatory conditions and developments, technological developments, capital market conditions, inflation rates, interest rates, the political and economic stability of oil producing nations, energy markets, weather conditions, business and regulatory or legal decisions, the pace of deregulation of retail natural gas and electricity, the timing and extent of changes in commodity prices for oil, natural gas, natural gas liquids, electricity and certain agricultural products, the timing and success of business development efforts, and other uncertainties, all of which are difficult to predict and many of which are beyond our control. Readers are cautioned not to put undue reliance on any forward-looking statements. For those statements, we claim the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. Business Strategy On October 7, 1999, we completed the merger of Kinder Morgan, Inc. and Kinder Morgan Delaware, the owner of the general partner interest in Energy Partners. Under the terms of the merger agreement, we issued approximately 41.5 million shares of our common stock in exchange for all of the outstanding shares of Kinder Morgan Delaware. Upon closing of the transaction, Richard D. Kinder was named Chairman of the combined company, which was renamed Kinder Morgan, Inc. In accordance with previously announced plans, we implemented and have continued to pursue our "Back to Basics" strategy. This strategy includes the following key aspects: (i) divest non-core assets and use the proceeds to reduce debt, (ii) sell certain core assets for fair market value to Energy Partners, (iii) focus on the efficiency and profitability of our remaining core assets, (iv) reduce corporate overhead costs, (v) align employee and shareholder incentives, (vi) reduce the shareholder dividend and (vii) seek accretive acquisitions and business expansions. F-46 49 During 1999, we implemented plans to dispose of our non-core businesses and as of December 31, 2000, we have effectively completed the disposition of these assets and operations, all as more fully described in Note 6 of the accompanying Notes to Consolidated Financial Statements. The cash proceeds from these dispositions were largely used to retire debt, contributing to the reduction in leverage experienced during this period. In addition to sales of non-core assets to third parties, we made significant transfers of assets to Energy Partners at the end of 1999 and the end of 2000, which, in total, represent over $1 billion of fair market value. By contributing assets to Energy Partners that are accretive to its earnings and cash flow, we can receive fair market value in the contribution transaction, while still maintaining an indirect interest in the earnings and cash flows of the assets through our limited and general partner interests in Energy Partners. As of December 31, 2000, we owned approximately 14.0 million limited partner units of Energy Partners, representing approximately 20.7% of the total units outstanding. As a result of our general and limited partner interests in Energy Partners, at the current level of distribution including incentive distributions to the general partner, we currently are entitled to receive approximately 49% of all distributions from Energy Partners. The actual level of distributions received by us in the future will vary with the level of distributable cash determined by Energy Partners' partnership agreement. By increasing our stake in Energy Partners, we expect to receive additional future cash distributions from Energy Partners through incremental general partner incentive distributions as well as increased limited partner distributions due to our ownership of additional common units received as compensation in the transfers. After the dispositions discussed above, our primary source of operating income is Natural Gas Pipeline Company of America, referred to in this report as "Natural," a major interstate natural gas pipeline system that runs from natural gas producing areas in West Texas and the Gulf of Mexico to its principal market area of Chicago, Illinois. In accordance with our strategy to increase operational focus on core assets, we have worked toward agreements to fully utilize the transportation and storage capacity of Natural with the result that Natural sold out its capacity through the year 2000-2001 winter season. Natural continues to pursue opportunities to connect its system to power generation facilities and, in addition, has announced plans to extend its system into the metropolitan east area of St. Louis anchored by a contract with Dynegy Marketing and Trade. Additional information on Natural's business is included under "Natural" in a subsequent section of this report. Our other remaining core operations consist of the retail distribution of natural gas to approximately 250,000 customers in several Western and Midwestern states and the construction and operation of electric power generation facilities. Our natural gas distribution properties are located, in part, in areas where significant growth is occurring and we expect to participate in that growth through increased natural gas demand. The nation's demand for additional electric power generation is significant and immediate. Our power generation business has a beneficial master turbine purchase agreement that it plans to utilize in constructing a number of gas-fired electric generation facilities to help meet this need. These power projects, in addition to generating income in their own right, are expected to increase Natural's throughput as described above. Even though we have made significant progress to date, we believe that opportunities remain for increasing shareholder value through cost reductions and other efficiency improvements with respect to both existing assets and future acquisitions. One measure intended to increase shareholder value is the All Employee Stock Option Plan implemented in October 1999. Through this plan, virtually all employees, with the exception of Richard D. Kinder and William V. Morgan (each of whom is currently a major shareholder), have received options to purchase shares of our common stock. By aligning employee incentives with shareholder value, we expect to increase employee productivity, retention and satisfaction. We believe these factors ultimately contribute to increased earnings and overall shareholder value. To reduce debt and provide funds for future growth, we reduced the regular quarterly common dividend from $0.20 per share to $0.05 per share in the fourth quarter of 1999 and have maintained it at that level. F-47 50 The final aspect of our strategy is seeking out accretive acquisitions and business expansions. Energy Partners has a multi-year history of making accretive acquisitions, which benefit us through our limited and general partner interests. This acquisitive strategy is expected to continue, with the population of potential acquisition candidates being driven by consolidation in the energy industry, as well as rationalization of asset portfolios by major corporations. In addition, we expect to, within strict guidelines as to rate of return and risk and timing of cash flows, expand Natural's pipeline system, acquire natural gas distribution properties that fit well with the current profile and build and acquire incremental power generation facilities. CONSOLIDATED FINANCIAL RESULTS
YEAR ENDED DECEMBER 31, --------------------------------------------------- 2000 1999 1998 ----------- ----------- ----------- (In Thousands Except Per Share Amounts) Operating Revenues $ 2,713,737 $ 1,836,368 $ 1,660,259 =========== =========== =========== Gross Margin(1) $ 753,654 $ 786,118 $ 823,645 =========== =========== =========== Operating Income: Before Merger-related and Severance Costs $ 395,143 $ 333,145 $ 401,455 Merger-related and Severance Costs -- (37,443) (5,763) ----------- ----------- ----------- Consolidated Operating Income $ 395,143 $ 295,702 $ 395,692 =========== =========== =========== Income from Continuing Operations: Before Merger-related and Severance Costs and Gains from Sales of Assets $ 146,735 $ 58,848 $ 131,416 Merger-related and Severance Costs, Net of Tax -- (23,327) (3,518) Gains from Sales of Assets, Net of Tax 36,980 120,137 12,297 ----------- ----------- ----------- Income from Continuing Operations 183,715 155,658 140,195 ----------- ----------- ----------- Discontinued Operations, Net of Tax: Loss from Discontinued Operations -- (50,941) (77,984) Loss on Disposal of Discontinued Operations (31,734) (344,378) -- ----------- ----------- ----------- (31,734) (395,319) (77,984) ----------- ----------- ----------- Net Income (Loss) $ 151,981 $ (239,661) $ 62,211 =========== =========== =========== Diluted Earnings (Loss) Per Share: From Continuing Operations Before Merger-related and Severance Costs and Gain from Sales of Assets $ 1.28 $ 0.73 $ 2.03 Merger-related and Severance Costs -- (0.29) (0.05) Gain from Sales of Assets 0.32 1.49 0.19 Loss from Discontinued Operations -- (0.63) (1.21) Loss on Disposal of Discontinued Operations (0.28) (4.29) -- ----------- ----------- ----------- Diluted Earnings (Loss) Per Share $ 1.32 $ (2.99) $ 0.96 =========== =========== =========== Number of Shares Used in Computing Diluted Earnings Per Common Share 115,030 80,358 64,636 =========== =========== ===========
(1) Gross margin equals total operating revenues less gas purchases and other costs of sales. Our results for 2000, in comparison to 1999, reflect an increase of $877.4 million in operating revenues, a decrease of $32.5 million in gross margin and an increase of $62.0 million in operating income before merger-related and severance costs. The increase in operating revenues is principally due to (i) increased natural gas sales volumes and prices on the Kinder Morgan Texas Pipeline, (ii) weather-related increases in natural gas sales and transportation volumes from Retail Natural Gas Distribution and (iii) increased storage service revenues and operational gas sales from Natural Gas Pipeline Company of America, partially offset by the fact that 2000 results do not include the operations of Kinder Morgan Interstate Gas Transmission. Kinder Morgan Interstate Gas Transmission was contributed to Energy Partners at December 31, 1999, while Kinder Morgan Texas Pipeline was contributed to Energy Partners at December 31, 2000. These transactions are described in Note 5 of the accompanying Notes to Consolidated Financial Statements. The decrease in gross margin that F-48 51 occurred from 1999 to 2000, despite the increased operating revenues, was principally due to the fact that 2000 results do not include the results of Kinder Morgan Interstate Gas Transmission. Results for 1999 and 1998 included merger-related and severance costs as further discussed in Note 3 of the accompanying Notes to Consolidated Financial Statements. The individual business unit sections that follow contain more details concerning the comparison of these results down to the level of operating income. Below the operating income line, results for 2000, 1999 and 1998 included significant gains from the sale of assets. Results for 2000 and 1999 included equity in earnings (and associated amortization of excess investment) associated with our October 1999 acquisition of Kinder Morgan Delaware. Interest expense increased significantly in 1999 due, in large part, to the January 1998 acquisition of MidCon Corp., and declined in 2000 largely due to reduced short-term borrowing levels as a result of applying cash received from asset sales. Additional information on these non-operating income and expense items is included under "Other Income and (Expenses)" following, and information concerning the acquisitions and asset sales is contained in Notes 2 and 5 of the accompanying Notes to Consolidated Financial Statements. Diluted earnings per common share from continuing operations before merger-related and severance costs and gains from sales of assets increased from $0.73 per share in 1999 to $1.28 per share in 2000. In addition to the operating and financing factors described preceding, this increase also reflects an increase of 34.7 million (43.1%) in average diluted shares outstanding, largely due to shares issued in conjunction with the acquisition of Kinder Morgan Delaware discussed above. Diluted earnings per common share increased from a loss of $2.99 per common share in 1999 to earnings of $1.32 per common share in 2000, reflecting, in addition to the factors discussed preceding, the impact of discontinued operations, including losses on disposal of discontinued operations, in each period. See "Discontinued Operations" following and Note 6 of the accompanying Notes to Consolidated Financial Statements. F-49 52 RESULTS OF OPERATIONS We manage our various businesses by, among other things, allocating capital and monitoring operating performance. This management process includes dividing the overall Company into business units so that performance can be effectively monitored and reported for a limited number of discrete businesses. Currently, we manage and report our operations in the following business units:
BUSINESS UNIT BUSINESS CONDUCTED REFERRED TO AS: - ------------- ------------------ --------------- Natural Gas Pipeline Company of Major interstate natural gas pipeline and Natural America and certain affiliates storage system Retail Natural Gas Distribution The regulated sale of natural gas to Retail residential, commercial and industrial customers and non-utility sales of natural gas to certain utility customers under the Choice Gas Program Power Generation and Other The construction and operation of natural gas Power and Other fired electric generation facilities, together with various other activities not constituting separately managed or reportable business segments
In previous periods, we owned and operated other lines of business, which we discontinued during 1999. In addition, our direct investment in the natural gas transmission and storage business has significantly decreased as a result of (i) the December 31, 1999 sale of Kinder Morgan Interstate Gas Transmission LLC, referred to in this report as "Kinder Morgan Interstate," to Energy Partners and (ii) the December 2000 sale of Kinder Morgan Texas Pipeline, Inc., referred to in this report as "Kinder Morgan Texas," to Energy Partners. The results of operations of these two businesses are included in our financial statements until their disposition, which is discussed under "General" in this portion of the Form 10-K and in Note 5 of the accompanying Notes to Consolidated Financial Statements. The accounting policies applied in the generation of business unit information are generally the same as those described in Note 1 to the accompanying Consolidated Financial Statements, except that items below the "Operating Income" line are either not allocated to business units or are not considered by Management in its evaluation of business unit performance. An exception to this is that Power, which routinely conducts its business activities in the form of joint operations with other parties that are accounted for under the equity method of accounting, includes its equity in earnings of these investees in its business unit operating results. These equity-method earnings are included in "Other Income and (Expenses)" in our consolidated income statement. In addition, certain items included in consolidated operating income (such as merger-related and severance costs and general and administrative expenses) are not allocated to individual business units. With adjustment for these items, we currently evaluate business unit performance primarily based on operating income in relation to the level of assets employed. Sales between business units are accounted for at market prices. For comparative purposes, prior period results and balances have been reclassified as necessary to conform to the current presentation. Following are operating results by individual business unit (before intersegment eliminations), including explanations of significant variances between the periods presented. F-50 53 NATURAL
YEAR ENDED DECEMBER 31, ---------------------------------------- 2000 1999 1998 -------- -------- -------- (In Thousands Except Systems Throughput) Operating Revenues $656,017 $626,888 $556,961 -------- -------- -------- Operating Costs and Expenses: Gas Purchases and Other Costs of Sales 145,431 115,481 24,273 Operations and Maintenance 62,582 72,979 59,055 Depreciation and Amortization 84,975 109,346 121,008 Taxes, Other Than Income Taxes 20,142 22,575 15,800 -------- -------- -------- 313,130 320,381 220,136 -------- -------- -------- Operating Income Before Corporate Costs $342,887 $306,507 $336,825 ======== ======== ======== Systems Throughput (Trillion Btus) 1,459.3 1,449.9 1,296.6 ======== ======== ========
Operating results for Natural are included in our consolidated results beginning with the January 30, 1998 acquisition of MidCon Corp. See Note 2 of the accompanying Notes to Consolidated Financial Statements for more information regarding this acquisition. Natural's operating income before corporate costs increased by $36.4 million (11.9%) from 1999 to 2000. Operating results for 2000 were positively affected, relative to 1999, by (i) increased operational efficiency and the associated favorable impact of increased gas prices on Natural's operational gas sales in 2000, (ii) increased storage service revenues, (iii) a reduction in amortization resulting from the July 1999 change in amortization rates (see Note 4 of the accompanying Notes to Consolidated Financial Statements), (iv) reduced 2000 operations and maintenance expenses due to successful cost control measures and to the sales of certain gathering assets and offshore laterals and (v) reduced ad valorem taxes. These positive effects were partially offset by (i) reduced 2000 revenues due to the sales of certain gathering assets and offshore laterals, (ii) decreased 2000 unit revenues largely attributable to both existing and planned competing pipeline capacity (with the attendant reduced value of transportation) in the upper Midwest, Natural's principal market area, and reduced transport revenue due to the sale of a marketing affiliate during 2000. Note 5 of the accompanying Notes to Consolidated Financial Statements contains additional information concerning asset sales. Natural's operating income before corporate costs decreased by $30.3 million (9.0%) from 1998 to 1999. Natural was negatively impacted in 1999, relative to 1998, by (i) a decrease in the margin per MMBtu of throughput from $0.41 in 1998 to $0.34 in 1999 resulting from (1) two recent mild winters, including the impact of the resultant high levels of gas in underground storage and (2) increased competitive pressures in Midwest markets due to actual or projected supply increases and (ii) increased operations and maintenance expenses and property taxes. These negative impacts were partially offset by (i) an increase in average monthly throughput volumes from 118 trillion Btus in 1998 to 126 trillion Btus in 1999 (although, in general, interstate pipelines receive the majority of their transportation revenues from demand charges, which are not affected by the level of throughput), (ii) reduced amortization expense in 1999 resulting from a change in the estimated useful life of Natural's assets (see Note 4 of the accompanying Notes to Consolidated Financial Statements) and (iii) the fact that our 1999 results included 12 months of the operations of Natural, while our 1998 results included only 11 months. F-51 54 KINDER MORGAN INTERSTATE
YEAR ENDED DECEMBER 31, ----------------------------------------- 1999 1998 -------- -------- (In Thousands Except Systems Throughput) Operating Revenues: Transportation and Storage $112,732 $105,160 Other 475 417 -------- -------- 113,207 105,577 -------- -------- Operating Costs and Expenses: Gas Purchases and Other Costs of Sales 13,954 3,763 Operations and Maintenance 23,737 20,026 Depreciation and Amortization 16,985 19,474 Taxes, Other Than Income Taxes 4,607 4,308 -------- -------- 59,283 47,571 -------- -------- Operating Income Before Corporate Costs $ 53,924 $ 58,006 ======== ======== Systems Throughput (Trillion Btus) 203.1 216.6 ======== ========
Effective December 31, 1999, we sold Kinder Morgan Interstate to Energy Partners. See Note 5 of the accompanying Notes to Consolidated Financial Statements for more information regarding this transaction. Kinder Morgan Interstate's operating income before corporate costs decreased by $4.1 million (7.0%) from 1998 to 1999. This business unit was negatively impacted in 1999, relative to 1998, by (i) the 1999 write-off of approximately $5.8 million of deferred fuel tracker costs that had accumulated since the initial implementation of FERC Order No. 636 and were deemed unrecoverable due to the settlement of the general rate case; (see Note 8 of the accompanying Notes to Consolidated Financial Statements for more information regarding Kinder Morgan Interstate's general rate case), (ii) a decrease in shipper supplied fuel requirements under the terms of Kinder Morgan Interstate's general rate case which, in conjunction with normal system fuel and loss requirements, caused Kinder Morgan Interstate to purchase additional system fuel supplies and (iii) increased operations and maintenance expenses, primarily related to the Pony Express Pipeline. These negative impacts were partially offset by (i) increased revenues in 1999 due to higher transportation rates under the terms of the general rate case and (ii) reduced depreciation expense in 1999 resulting from the assets of Kinder Morgan Interstate being classified as assets held for sale effective November 1, 1999, at which time further depreciation of these assets was suspended in accordance with the provisions of SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." F-52 55 RETAIL
YEAR ENDED DECEMBER 31, ---------------------------------------- 2000 1999 1998 -------- -------- -------- (In Thousands Except Systems Throughput) Operating Revenues: Gas Sales $171,696 $134,208 $186,527 Transportation 41,371 34,919 27,309 Other 16,442 13,785 20,470 -------- -------- -------- 229,509 182,912 234,306 -------- -------- -------- Operating Costs and Expenses: Gas Purchases and Other Costs of Sales 128,811 107,264 123,099 Operations and Maintenance 36,627 40,807 41,093 Depreciation and Amortization 11,776 11,382 11,014 Taxes, Other Than Income Taxes 2,563 3,355 2,886 -------- -------- -------- 179,777 162,808 178,092 -------- -------- -------- Operating Income Before Corporate Costs $ 49,732 $ 20,104 $ 56,214 ======== ======== ======== Systems Throughput (Trillion Btus) 72.6 56.6 61.7 ======== ======== ========
Retail's operating income before corporate costs increased by $29.6 million (147.4%) from 1999 to 2000. Operating results for 2000 were positively impacted, relative to 1999, by (i) increased system throughput in 2000, although a portion of this increase represents volumes transported for relatively low margins, (ii) increased service revenues in 2000 and (iii) reduced 2000 operating expenses. The increase in gross margins (operating revenues minus gas purchases and other costs of sales) which resulted from increased throughput volumes was principally due to increased irrigation demand in the third quarter of 2000 and increased space heating demand in the fourth quarter. Weather-related demand in Retail's service territory was affected by colder than normal weather in the fourth quarter of 2000, compared with warmer than normal weather in the fourth quarter of 1999. The reduced 2000 operating expenses resulted from (i) a reduction in advertising and marketing expenses for the Choice Gas program (unregulated sales of natural gas made to certain of Retail's utility customers), (ii) continued focus on efficient operations, (iii) reduced ad valorem and use taxes in 2000 and (iv) reduced costs for certain administrative functions due to renegotiation of a contract with a third-party service provider. Retail's operating income before corporate costs decreased by $36.1 million (64.2%) from 1998 to 1999. This business unit was negatively impacted in 1999, relative to 1998, by (i) the fact that 1998 results include three months of the operations of distribution assets in Kansas that were sold in March 1998 (see Note 5 of the accompanying Notes to Consolidated Financial Statements) and (ii) reduced margins from sales and transportation due primarily to (1) weather-related reductions in 1999 irrigation demand and (2) reduced margins related to the Nebraska Choice Gas program. F-53 56 KINDER MORGAN TEXAS
YEAR ENDED DECEMBER 31, ---------------------------------------------- 2000 1999 1998 ---------- ---------- ---------- (In Thousands Except Systems Throughput) Operating Revenues: Gas Sales $1,675,206 $ 815,557 $ 704,190 Transportation 25,468 23,971 19,192 Other 46,825 32,633 15,819 ---------- ---------- ---------- 1,747,499 872,161 739,201 ---------- ---------- ---------- Operating Costs and Expenses: Gas Purchases and Other Costs of Sales 1,666,169 804,674 680,766 Operations and Maintenance 45,401 45,778 51,067 Depreciation and Amortization 2,211 2,466 1,615 Taxes, Other Than Income Taxes 4,400 2,689 3,624 ---------- ---------- ---------- 1,718,181 855,607 737,072 ---------- ---------- ---------- Operating Income Before Corporate Costs $ 29,318 $ 16,554 $ 2,129 ========== ========== ========== Systems Throughput (Trillion Btus) 654.4 575.3 581.6 ========== ========== ==========
Operating results for Kinder Morgan Texas are included in our consolidated results beginning with the January 30, 1998 acquisition of MidCon Corp. See Note 2 of the accompanying Notes to Consolidated Financial Statements for more information regarding this acquisition. Effective December 31, 2000, we contributed Kinder Morgan Texas to Energy Partners. See Note 5 of the accompanying Notes to Consolidated Financial Statements for more information regarding this transaction. Operating revenues for Kinder Morgan Texas increased by $875.3 million (100.4%) from 1999 to 2000. The $859.6 million (105.4%) increase in natural gas sales reflected a 75% increase in the average sales price during 2000, together with a 17% increase in sales volumes. The $14.2 million increase in other revenues was principally due to a 55% increase in the average sales price of natural gas liquids during 2000. Gross margin (operating revenues minus gas purchases and other costs of sales) increased by $13.8 million (20.5%) from 1999 to 2000, as the increased operating revenues were offset approximately proportionally by the increased cost of natural gas purchased. Operating income before corporate costs increased by $12.8 million (77.1%) from 1999 to 2000 as the increase in gross margin discussed preceding was partially offset by increased ad valorem taxes. Kinder Morgan Texas' operating income before corporate costs increased by $14.4 million from 1998 to 1999. This business unit was positively impacted in 1999, relative to 1998, by (i) the fact that 1999 results include 12 months of the operations of Kinder Morgan Texas, while 1998 results include only 11 months, (ii) increased per unit margins from sales and transportation in 1999, (iii) increased 1999 margins from natural gas liquids sales due to an improved pricing environment, (iv) reduced 1999 operations and maintenance expenses and (v) reduced 1999 ad valorem taxes. These positive impacts were partially offset by (i) reduced 1999 overall systems throughput volumes and (ii) increased 1999 depreciation expense reflecting the cumulative impact of capital expenditures made in 1998 and 1999. F-54 57 POWER AND OTHER
YEAR ENDED DECEMBER 31, ------------------------------------- 2000 1999 1998 ------- ------- ------- (In Thousands) Operating Revenues $80,697 $59,305 $47,380 Equity in Earnings of Equity Investments 3,669 10,511 8,675 ------- ------- ------- 84,366 69,816 56,055 ------- ------- ------- Operating Costs and Expenses: Gas Purchases and Other Costs of Sales 19,653 12,921 19,441 Operations and Maintenance 19,680 15,648 7,232 Depreciation and Amortization 9,203 7,754 2,252 Taxes, Other Than Income Taxes 868 1,335 1,672 ------- ------- ------- 49,404 37,658 30,597 ------- ------- ------- Income Before Corporate Costs $34,962 $32,158 $25,458 ======= ======= =======
Results of power generation operations are included in Power and Other beginning with the acquisition of interests in power plants from the Denver-based Thermo Companies, which acquisition was completed in the third quarter of 1998. See Note 2 of the accompanying Notes to Consolidated Financial Statements for more information concerning this acquisition. Income before corporate costs from Power and Other increased $2.8 million (8.7%) from 1999 to 2000. Operating results for 2000 were positively impacted, relative to 1999, by profits from development of a 550-megawatt electric generating plant currently being constructed by Power near Little Rock, Arkansas. The positive impact related to development profits was partially offset by (i) a decrease in earnings from equity investments largely attributable to increased fuel (natural gas) costs related to electricity generation and (ii) increased operating expenses associated with other operations, principally our agreement with HS Resources, Inc. and certain telecommunications assets used primarily by internal business units. As we announced on November 30, 1999, we have entered into agreements with HS Resources, Inc. for the sale of certain assets in the Wattenberg field area of the Denver-Julesberg Basin. Under the terms of the agreements, HS Resources, Inc. commenced operating these assets. We are receiving payments from HS Resources, Inc. during 2000 and 2001, with the legal transfer of ownership expected to occur on or before December 15, 2001. Loss before Corporate Costs for our international activities, included in this business unit, was $1.9 million, $1.9 million and $0.4 million in 2000, 1999 and 1998, respectively. F-55 58 Income before corporate costs from Power and Other increased $6.7 million (26.3%) from 1998 to 1999. Operating results for 1999 were positively impacted, relative to 1998, by (i) 1999 results include a full year of power generation activities, while 1998 includes only partial year results and (ii) increased 1999 operating income from our agreement with HS Resources, as described above. OTHER INCOME AND (EXPENSES)
YEAR ENDED DECEMBER 31, --------------------------------------------- 2000 1999 1998 --------- --------- --------- (In Thousands) Interest Expense, Net $(243,155) $(251,920) $(205,840) --------- --------- --------- Equity in Earnings: Energy Partners - Earnings 140,913 15,733 -- Energy Partners - Amortization (28,317) (7,335) -- Power Segment(1) 3,669 10,511 8,675 Other (10,255) 14,140 22,466 --------- --------- --------- Total Equity in Earnings 106,010 33,049 31,141 --------- --------- --------- Minority Interests (24,121) (24,845) (19,483) Gains from Sales of Assets 61,684 189,778 19,552 Other, Net 10,881 4,627 1,843 --------- --------- --------- $ (88,701) $ (49,311) $(172,787) ========= ========= =========
(1) See discussion under the heading "Power and Other." The increase of $39.4 million (79.9%) in net expense under "Other Income and (Expenses)" from 1999 to 2000 is principally due to decreased gains from sales of assets and reduced other equity in earnings in 2000, partially offset by higher 2000 equity in earnings of Energy Partners and increased "Other, Net." The decrease in gains from sales of assets in 2000 reflects the fact that 1999 results include (i) a gain of $158.8 million from the sale of Kinder Morgan Interstate and interests in two equity method investments and (ii) a gain of $31.0 million from the sale of two offshore pipeline assets, while 2000 results include a gain of $61.6 million from the sale of Kinder Morgan Texas Pipeline. The equity in earnings of Energy Partners and associated amortization during 2000 and 1999 result from our October 1999 acquisition of interests in Energy Partners and, thus, 1999 includes only one quarter of earnings on this investment while 2000 reflects earnings for the full year. Energy Partners' Form 10-K for the year ended December 31, 2000 contains additional information about its results of operations. The decrease in other equity in earnings from 1999 to 2000 is principally due to the sale of various equity method investments. In addition, 2000 results reflect increased equity in losses of the TransColorado pipeline joint venture, which was placed in service March 31, 1999. The expense associated with "Minority Interests" in each period principally represents the costs associated with our two series of Capital Trust Securities. These securities are described in Note 12 of the accompanying Notes to Consolidated Financial Statements. The increase in "Other, Net" from 1999 to 2000 reflects the fact that, while each period includes miscellaneous items of income and expense, 2000 results also include (i) $4.1 million due to the recovery of note receivable proceeds in excess of its carrying value and (ii) $3.9 million due to the settlement of a regulatory matter for an amount less than that previously reserved. The decrease of $123.5 million in net expense reported under "Other Income and (Expenses)" from 1998 to 1999 is principally due to increased 1999 gains from the sale of assets, partially offset by increased interest expense. The decreased 1999 gains from the sale of assets reflects the fact that 1999 includes the gain from the sale of Kinder Morgan Gas Transmission and other assets as discussed above, while 1998 includes (i) a gain of $10.9 million from the sale of certain microwave towers and (ii) a gain of $8.5 million from the sale of Kansas natural gas distribution properties. The increase of $46.1 million (22.4%) in "Interest Expense, Net" from 1998 to 1999 is principally due the incremental debt outstanding as a result of the January 1998 acquisition of MidCon and decreased capitalized interest in 1999 due to the reduced level of capital spending (see "Net Cash Flows from Investing Activities"). F-56 59 INCOME TAXES - CONTINUING OPERATIONS
YEAR ENDED DECEMBER 31, --------------------------------------------- 2000 1999 1998 --------- --------- --------- (Dollars In Thousands) Income Tax Provision $ 122,727 $ 90,733 $ 82,710 ========= ========= ========= Effective Tax Rate 40.0% 36.8% 37.1% ========= ========= =========
The increase of $32.0 million in the income tax provision from 1999 to 2000 is composed of (i) an increase of $22.1 million due to an increase in pretax income and (ii) an increase of $9.9 million due to an increase in the effective tax rate in 2000. The increased effective tax rate for 2000 is principally due to an increased effective rate associated with state income taxes. The increase of $8.0 million in income tax expense from 1998 to 1999 reflected an increase of $8.7 million due to an increase in 1999 pre-tax income, partially offset by a decrease of $0.7 million due to a decrease in the 1999 effective tax rate. The decrease in the 1999 effective tax rate was principally due to the impact of asset sales and dispositions of certain lines of business. DISCONTINUED OPERATIONS
YEAR ENDED DECEMBER 31, ---------------------------------------------- 2000 1999 1998 ---------- --------- --------- (In Thousands) Income (Loss) from Discontinued Operations, Net of Tax $ -- $ (50,941) $ (77,984) ========== ========= ========= Loss on Disposal of Discontinued Operations, Net of Tax $ (31,734) $(344,378) $ -- ========== ========= =========
During the third quarter of 1999, we adopted and implemented a plan to discontinue the direct marketing of non-energy products and services (principally under the "Simple Choice" brand), which activities had been carried on largely through our en*able joint venture with PacifiCorp. During the fourth quarter of 1999, we adopted and implemented plans to discontinue the following lines of business: (i) gathering and processing of natural gas, including short-haul intrastate pipelines and providing field services to natural gas producers, (ii) wholesale marketing of natural gas and natural gas liquids and (iii) international operations. We recorded a loss of $344.4 million, representing the estimated loss to be recognized upon final disposal of these businesses, including estimated operating losses prior to disposal. During 2000, we completed the disposition of these businesses, with the exception of international operations (principally consisting of a natural gas distribution system under construction in Hermosillo, Mexico), which, in the fourth quarter of 2000, we decided to retain. Neither the decision to dispose of our international operations nor our subsequent decision to retain them had any material effect on our results of operations, commitments and contingencies, known trends or capital resources. In the fourth quarter of 2000, we recorded an incremental loss on disposal of discontinued operations of $31.7 million, representing the impact of the final disposition transactions and adjustment of previously recorded estimates. We had a remaining liability of approximately $23.7 million at December 31, 2000 associated with these discontinued operations, principally consisting of (i) indemnification obligations under the various sale agreements and (ii) retained liabilities, which were settled in cash in early 2001. We do not expect significant additional financial impacts associated with these matters. Note 6 of the accompanying Notes to Consolidated Financial Statements contains certain additional financial information with respect to these discontinued operations. Losses from discontinued operations, net of tax benefits of $29.7 million and $46.0 million in 1999 and 1998, respectively, decreased by $27.1 million from 1998 to 1999. Operating results were positively impacted in 1999, relative to 1998, by (i) improvement in the natural gas liquids pricing environment in 1999 and (ii) the fact that 1998 operating results included (1) $6.4 million of adjustments to write down certain natural gas due from third parties and in underground storage to their current market values, (2) $3.7 million of increased provision for uncollectible accounts receivable, (3) natural gas liquids storage inventory write-downs and (4) operating losses associated with gas processing facilities that were sold in the fourth quarter of 1998. These F-57 60 factors serving to create a favorable period to period variance were partially offset by the fact that 1998 results included $6.0 million in margin from sales of storage gas. LIQUIDITY AND CAPITAL RESOURCES The following table illustrates the sources of our invested capital. The balances at December 31, 1999 reflect the impacts associated with the acquisition of Kinder Morgan Delaware and the sale of certain assets to Energy Partners, while the balances at December 31, 2000 also reflect the impact of the sale of additional assets to Energy Partners effective as of that date. Notes 2 and 5 of the accompanying Notes to Consolidated Financial Statements contain additional information on these transactions, while Note 12 contains information concerning our outstanding debt securities, short-term borrowing facilities and financing activities.
DECEMBER 31, ------------------------------------------------ 2000 1999 1998 ---------- ---------- ---------- (Dollars In Thousands) Long-term Debt $2,478,983 $3,293,326 $3,300,025 Common Equity 1,797,421 1,669,846 1,219,043 Preferred Stock -- -- 7,000 Capital Trust Securities 275,000 275,000 275,000 ---------- ---------- ---------- Capitalization 4,551,404 5,238,172 4,801,068 Short-term Debt 908,167 581,567 1,702,013(1) ---------- ---------- ---------- Invested Capital $5,459,571 $5,819,739 $6,503,081 ========== ========== ========== Capitalization: Long-term Debt 54.5% 62.9% 68.7% Common Equity 39.5% 31.9% 25.4% Preferred Stock -- -- 0.2% Capital Trust Securities 6.0% 5.2% 5.7% Invested Capital(3): Total Debt 62.0% 66.6% 76.9%(2) Equity, Including Capital Trust Securities 38.0% 33.4% 23.1%
(1) Includes the $1,394,846 Substitute Note assumed in conjunction with the acquisition of MidCon Corp. This note was repaid on January 4, 1999. (2) If the government securities then held as collateral were offset against the related debt, the ratio of total debt to invested capital at December 31, 1998, would have been 72.3 percent. (3) As adjusted to reflect the November 2001 maturity of the Premium Equity Participating Units (see "Net Cash Flows from Financing Activities") and the associated $460 million increase in equity and decrease in debt, the ratios would be: Debt - 53.6%, Equity - 46.4%. CASH FLOWS The following discussion of cash flows should be read in conjunction with the accompanying Consolidated Statements of Cash Flows and related supplemental disclosures. All highly liquid investments purchased with an original maturity of three months or less are considered to be cash equivalents. Net Cash Flows from Operating Activities "Net Cash Flows Provided by Operating Activities" decreased from $321.2 million in 1999 to $167.1 million in 2000, a decline of $154.1 million (48%). This decline is primarily due to an increase in cash flows used for discontinued operations, which increased from a source of $94.5 million in 1999 to a use of $110.4 million in 2000, a $204.9 million increased use of cash reflecting (i) $124.7 million of cash outflow in 2000 attributable to the termination of our receivable sale program and (ii) 124.7 million of cash inflow in 1999 attributable to the receivable sale program (see "Net Cash Flows from Financing Activities" following). The decline in "Net Cash Flows Provided by Operating Activities" for discontinued operations was partially offset by an increase in cash flows provided by continuing operations, which increased from a source of $226.7 million in 1999 to a source F-58 61 of $277.5 million in 2000. This $50.8 million of increased cash flow is primarily due to (i) $121.3 million of cash distributions received in 2000 attributable to our interest in Energy Partners (see Note 2 of the accompanying Notes to Consolidated Financial Statements and the discussion following) and (ii) a decrease in cash used in 2000 to make interest payments reflecting the decreased average debt balance outstanding. Partially offsetting this increase were (i) an increase in cash used for working capital of $84.6 million and (ii) January 2000 payments associated with December 1999 gas supply purchases. "Net Cash Flows from Operating Activities" increased from $95.3 million in 1998 to $321.2 million in 1999, an increase of $225.9 million or 237 percent. This increase was principally attributable to (i) cash provided by reductions in working capital for continuing operations in 1999 and (ii) increased 1999 operating cash flows associated with discontinued operations reflecting, among other things, improved operating results and the sale of accounts receivable, partially offset by (i) reduced 1999 earnings from continuing operations before asset sales and (ii) the inclusion in 1998 results of $27.5 million of proceeds from the buyout of certain contractual gas obligations. In general, distributions from Energy Partners are declared in the month following the end of the quarter to which they apply and are paid in the month following the month of declaration to the general partner and unit holders of record as of the end of the declaration month. Therefore, the accompanying Statement of Consolidated Cash Flows for 2000 reflects the receipt of a total of $121.3 million of cash distributions from Energy Partners for the fourth quarter of 1999 and the first nine months of 2000. The cash distributions attributable to our interest for the three months and twelve months ended December 31, 2000 total $44.5 million and $149.9 million, respectively. The increase in distributions during 2000 reflects, among other factors, the December 31, 1999 transfer of certain properties from us to Energy Partners (see Note 5 of the accompanying Notes to Consolidated Financial Statements). Net Cash Flows from Investing Activities "Net Cash Flows Provided by Investing Activities" decreased from $1.0 billion in 1999 to $498.7 million in 2000, a decline of $521.5 million principally due to the sale of approximately $1.1 billion of government securities during 1999, with the proceeds utilized to repay the Substitute Note assumed in conjunction with the January 1998 acquisition of MidCon Corp. Partially offsetting this decrease was (i) $500.3 million of cash received during 2000 from the sale of certain interests and assets to Energy Partners and (ii) cash flows of discontinued investing activities increasing from a use of $46.6 million in 1999 to a source of $154.2 million in 2000, which was principally a result of the $163.9 million of proceeds received from ONEOK for the sale of gathering and processing businesses in Oklahoma, Kansas and West Texas. "Net Cash Flows from Investing Activities" increased from a net outflow of $3.5 billion in 1998 to a net inflow of $1.0 billion in 1999. This increase was principally attributable to the net impact of (i) a net cash outflow of $2.2 billion in 1998 for the purchase of MidCon Corp., (ii) net purchases of U.S. Government securities of $1.1 billion in 1998, principally to act as collateral for the Substitute Note assumed in the acquisition of MidCon Corp., (iii) net sales of U.S. government securities of $1.1 billion in 1999, which proceeds were used, together with proceeds of additional short-term borrowings, to repay the Substitute Note, (iv) additional cash used in 1999 for other acquisitions, principally the cash portion of consideration paid for the Thermo acquisition, (v) the 1999 receipt of $28.7 million of proceeds from the sale of Tom Brown, Inc. preferred stock, (vi) increased proceeds from sales of assets in 1999 and (vi) decreased net cash outflows for investing activities of discontinued operations in 1999. During the year 2000, major asset sales included (i) Kinder Morgan Texas Pipeline, Inc., the Casper and Douglas Natural Gas Gathering and Processing Systems, our 50 percent interest in Coyote Gas Treating, LLC and our 25 percent interest in Thunder Creek Gas Services, L.L.C. to Energy Partners, (ii) gathering and processing businesses in Oklahoma, Kansas and West Texas as well as our marketing and trading business to F-59 62 ONEOK, (iii) three natural gas gathering systems and a natural gas processing facility to WBI Holdings, Inc. and (iv) Wildhorse Energy Partners, LLC to Tom Brown, Inc. Total proceeds received in 2000 from asset sales were $730.6 million of which $330 million represented proceeds from the 1999 transfer of assets to Energy Partners. Major asset sales during 1999 included (i) Kinder Morgan Interstate, Kinder Morgan Trailblazer LLC and our interest in Red Cedar Gathering Company to Energy Partners, (ii) all of our major offshore assets in the Gulf of Mexico area, including our interests in Stingray Pipeline Company L.L.C. and West Cameron Dehydration Company L.L.C., and the HIOS and UTOS offshore pipeline systems and (iii) MidCon Gas Products of New Mexico Corp. Total proceeds received in 1999 from asset sales were $111.1 million. Notes 2, 5 and 6 of the accompanying Notes to Consolidated Financial Statements and "Net Cash Flows from Financing Activities" following contain more information concerning these investments and sales. Net Cash Flows from Financing Activities "Net Cash Flows Used in Financing Activities" decreased from approximately $1.3 billion in 1999 to $550.3 million in 2000, a decline of approximately $786.7 million. This decrease was principally due to the first-quarter 1999 repayment of the $1.39 billion Substitute Note as discussed preceding, partially offset by increased short-term borrowings during the same period, as well as reduced cash payments for dividends in 2000. "Net Cash Flows from Financing Activities" decreased from a net inflow of $3.4 billion in 1998 to a net outflow of $1.3 billion in 1999. This decrease was principally the result of the 1998 financings associated with the acquisition of MidCon Corp. and the repayment of the Substitute Note in 1999, in each case as described following. In addition, we retired $158.9 million of long-term debt in 1999, compared to $35.8 million in 1998. The long-term debt retired in 1999 included $148.6 million of debt assumed in conjunction with the acquisition of Kinder Morgan Delaware. Our principal sources of short-term liquidity are our revolving bank facilities. As of December 31, 2000, we had available a $500 million 364-day facility dated October 25, 2000, and a $400 million amended and restated five-year revolving credit agreement dated January 30, 1998. These bank facilities can be used for general corporate purposes, including backup for our commercial paper program. At December 31, 2000, we had $100 million of bank borrowings and commercial paper (which is backed by the bank facilities) issued and outstanding. The corresponding amount outstanding was $50 million at February 9, 2001. After inclusion of applicable letters of credit, the remaining available borrowing capacity under the bank facilities was $796.7 million and $846.7 million at December 31, 2000 and February 9, 2001, respectively. The bank facilities include covenants that are common in such arrangements. For example, the $500 million facility requires consolidated debt to be less than 68% of consolidated total capitalization. The $400 million facility requires that upon issuance of common stock to the holders of the premium equity participating security units at the maturity of the security units (November 2001), consolidated debt must be less than 67% of consolidated total capitalization. Both of the bank facilities require the debt of consolidated subsidiaries to be less than 10% of our consolidated debt and require the consolidated debt of each material subsidiary to be less than 65% of our consolidated total capitalization. The $400 million facility requires our consolidated net worth (inclusive of trust preferred securities) be at least $1.236 billion plus 50 percent of consolidated net income earned for each fiscal quarter beginning with the last quarter of 1998. The $500 million facility requires our consolidated net worth (inclusive of trust preferred securities) be at least $1.236 billion plus 50 percent of consolidated net income earned for each fiscal quarter beginning with the last quarter of 1999. Our short-term debt of $908.2 million at December 31, 2000 consisted of (i) $100 million of borrowings under our revolving credit facilities, (ii) the $400 million of Reset Put Securities that are scheduled to be either remarketed or retired as of March 1, 2001, (iii) the $400 million of 6.45% Senior Notes, due November 2001 F-60 63 and (iv) $8.2 million of miscellaneous current maturities of long-term debt. We expect to retire the Reset Put Securities at March 1, 2001 utilizing a combination of cash on hand and incremental short-term borrowings, which will result in an extraordinary loss on early extinguishments of debt expected to total approximately $15 million. We expect that the $400 million of 6.45% Senior Notes will be retired at maturity with a portion of the $460 million of cash to be received from the issuance of common stock upon maturity of the Premium Equity Participating Securities, which occurs concurrently as discussed following. Apart from these items, our current assets and current liabilities are approximately equal. Given our expected cash flows from operations and our unused debt capacity, including our 5-year revolving credit facility, we do not expect any liquidity issues in the foreseeable future. In September 1999, we established an accounts receivable sales facility that provided up to $150 million of additional liquidity. In accordance with this agreement, we received proceeds of $150 million on September 30, 1999. Cash flows associated with this facility are included with "Cash flows from Operating Activities" in the accompanying Consolidated Statements of Cash Flows. In February 2000, we reduced our participation in this receivables sales program by $124.9 million, principally as a result of our then-pending disposition of our wholesale gas marketing business. On April 25, 2000, we repaid the residual balance and terminated the agreement. In November 1998, we sold $460 million principal amount of premium equity participating securities in a public offering. The proceeds from the security units offering was used to purchase U.S. Treasury Notes on behalf of the security unit holders, which notes are the property of the security unit holders and will be held as collateral to fund the obligation of the security unit holders to purchase our common stock at the end of a three-year period. In November 2001, the maturity of these securities will result in our receipt of $460 million in cash as discussed above and, based on the market price of our common stock as of November 30, 2001, the issuance of approximately 13.4 million shares of common stock. The cash proceeds are expected to be used to retire the $400 million of 6.45% Senior Notes that mature concurrently with the premium equity participating securities and to repay a portion of short-term borrowings then outstanding. In March 1998, we issued 12.5 million shares (18.75 million shares after adjustment for the December 1998 three-for-two stock split) of common stock in an underwritten public offering, receiving net proceeds of approximately $624.6 million. Also in March 1998, we issued $2.35 billion principal amount of debt securities of varying maturities and interest rates in an underwritten public offering, receiving net proceeds of approximately $2.34 billion. The net proceeds from these two offerings were used to refinance borrowings under the MidCon Corp. acquisition financing arrangements and to purchase U.S. government securities to collateralize a portion of the Substitute Note (assumed in conjunction with the acquisition). In April 1998, we sold $175 million of 7.63% Capital Securities due April 15, 2028, in an underwritten offering, with the net proceeds of $173.1 million used to purchase U.S. government securities to further collateralize the Substitute Note. In November 1998, we completed the underwritten public offering of $400 million of 3-year senior notes concurrently with the $460 million principal amount of premium equity participating security units discussed above. The $397.4 million of net proceeds from the senior notes offering were used to retire a portion of our then-outstanding short-term borrowings. For additional information on each of these financings, including terms of the specific securities and the associated accounting treatment, see Note 12 of the accompanying Notes to Consolidated Financial Statements. On January 4, 1999, we repaid the $1.4 billion Substitute Note payable to Occidental Petroleum as part of the MidCon Corp. acquisition. The note was repaid using the proceeds of approximately $1.1 billion from the sale of U.S. government securities that had been held as collateral, with the balance of the funds provided by an increase in short-term borrowings. F-61 64 Capital Expenditures and Commitments Capital expenditures in 2000 were $137.5 million and $3.2 million for continuing operations and discontinued operations, respectively. The 2001 capital expenditure budget totals approximately $197 million. We expect that funding for the budget will be provided from internal sources and, if necessary, incremental borrowings. Approximately $5.5 million of this amount had been committed for the purchase of plant and equipment at December 31, 2000. Additional information on commitments is contained in Note 17 of the accompanying Notes to Consolidated Financial Statements. LITIGATION AND ENVIRONMENTAL Our anticipated environmental capital costs and expenses for 2001, including expected costs for remediation efforts, are approximately $7 million, compared to $5.8 million of such costs and expenses incurred in 2000. A substantial portion of our environmental costs are either recoverable through insurance and indemnification provisions or have previously recorded liabilities associated with them. Refer to Notes 9(A) and 9(B) to the accompanying Consolidated Financial Statements for additional information on our pending litigation and environmental matters. We believe we have established adequate reserves such that the resolution of pending litigation and environmental matters will not have a material adverse impact on our business, cash flows, financial position or results of operations. REGULATION See Note 8 of the accompanying Notes to Consolidated Financial Statements for information regarding regulatory matters. RISK MANAGEMENT The following discussion should be read in conjunction with Note 14 of the accompanying Notes to Consolidated Financial Statements, which contains additional information on our risk management activities. To minimize the risk of price changes in the natural gas and associated transportation markets, we use certain financial instruments for hedging purposes. These instruments include energy products traded on the New York Mercantile Exchange, the Kansas City Board of Trade and over-the-counter markets including, but not limited to, futures and options contracts and fixed-price swaps. We are exposed to credit-related losses in the event of nonperformance by counterparties to these financial instruments but, given their existing credit ratings, we do not expect any counterparties to fail to meet their obligations. Pursuant to a policy approved by our Board of Directors, we are to engage in these activities only as a hedging mechanism against price volatility associated with (i) pre-existing or anticipated physical gas sales, (ii) physical gas purchases and (iii) system use and storage in order to protect profit margins, and not to engage in speculative trading. Commodity-related activities of the risk management group are monitored by our Risk Management Committee, which is charged with the review and enforcement of the Board of Directors' risk management policy. The Risk Management Committee reviews the types of hedging instruments used, contract limits and approval levels and may review the pricing and hedging of any or all commodity transactions. All energy futures, swaps and options are recorded at fair value. The fair value of these risk management instruments reflects the estimated amounts that we would receive or pay to terminate the contracts at the reporting date, thereby taking into account the current unrealized gains or losses on open contracts. Market quotes are available for substantially all financial instruments we use. Through December 31, 2000, gains and losses on hedging positions have been deferred and recognized as gas purchases expense in the periods in which the underlying physical transactions occur. On January 1, 2001, we began accounting for derivative instruments under SFAS No. 133, F-62 65 "Accounting for Derivative Instruments and Hedging Activities," (after amendment by SFAS 137 and SFAS 138, the "Statement"). As discussed preceding, our principal use of derivative financial instruments is to mitigate the market price risk associated with anticipated transactions for the purchase and sale of natural gas. The Statement allows these transactions to continue to be treated as hedges for accounting purposes, although the changes in the market value of these instruments will affect comprehensive income in the period in which they occur and any ineffectiveness in the risk mitigation performance of the hedge will affect net income currently. The change in the market value of these instruments representing effective hedge operation will continue to affect net income in the period in which the associated physical transactions are consummated. Adoption of the Statement has resulted in $14.4 million of deferred net loss as of January 1, 2001, being reported as part of other comprehensive income in 2001, as well as subsequent changes in the market value of these derivatives prior to consummation of the transaction being hedged. We measure the risk of price changes in the natural gas and natural gas liquids markets utilizing a Value-at-Risk model. Value-at-Risk is a statistical measure of how much the marked-to-market value of a portfolio could change during a period of time, within a certain level of statistical confidence. We utilize a closed form model to evaluate risk on a daily basis. The Value-at-Risk computations utilize a confidence level of 97.7 percent for the resultant price movement and a holding period of one day chosen for the calculation. The confidence level used means that there is a 97.7 percent probability that the mark-to-market losses for a single day will not exceed the Value-at-Risk number presented. Instruments evaluated by the model include forward physical gas, storage and transportation contracts and financial products including commodity futures and options contracts, fixed price swaps, basis swaps and over-the-counter options. During 2000, Value-at-Risk reached a high of $5.4 million and a low of $1.5 million. Value-at-Risk at December 31, 2000, was $5.3 million and averaged $4.5 million for 2000. Our calculated Value-at-Risk exposure represents an estimate of the reasonably possible net losses that would be recognized on our portfolio of derivatives assuming hypothetical movements in future market rates, and is not necessarily indicative of actual results that may occur. It does not represent the maximum possible loss or any expected loss that may occur, since actual future gains and losses will differ from those estimated. Actual gains and losses may differ from estimates due to actual fluctuations in market rates, operating exposures and the timing thereof, as well as changes in our portfolio of derivatives during the year. As a result of our recent divestiture of certain lines of business, including our wholesale natural gas and liquids marketing and natural gas gathering, processing and associated businesses, we expect that our portfolio of financial instruments held for the purposes of hedging, and corresponding exposure to loss from such instruments, will be smaller in the future. Given our portfolio of businesses as of December 31, 2000, our principal uses of derivative financial instruments will be to mitigate the risk associated with market movements in the price of natural gas associated with (i) the sale of in-kind fuel recoveries in excess of fuel used on Natural's pipeline system and (ii) the purchase of natural gas by Retail to serve its customers in the Choice Gas program. From time to time, our treasury department manages interest rate exposure utilizing interest rate swaps, caps or similar derivatives within Board-established policy. None of these interest rate derivatives is leveraged. We are currently not hedging our interest rate exposure resulting from short-term borrowings. The market risk related to short-term borrowings from a one percent change in interest rates would result in a $0.5 million annual impact on pre-tax income, based on short-term borrowing levels as of February 9, 2001. F-63 66 Significant Operating Variables Our principal exposure to market variability is related to the variation in natural gas prices and basis differentials, which can affect gross margins in our Natural and Retail segments. "Basis differential" is a term that refers to the difference in natural gas prices between two locations or two points in time. These price differences can be affected by, among other things, natural gas supply and demand, available transportation capacity, storage inventories and deliverability, prices of alternative fuels and weather conditions. In recent periods, additional competitive pressures have been generated in Midwest natural gas markets due to the introduction and planned introduction of additional supplies into the Chicago market area, although incremental "take away" capacity has also been constructed. We have attempted to reduce our exposure to this form of market variability by pursuing long-term, fixed-rate type contract agreements for capacity on Natural. In addition, as discussed under "Risk Management" elsewhere in this document and in Note 14 of the accompanying Notes to Consolidated Financial Statements, we utilize a comprehensive risk management program to mitigate our exposure to changes in the market price of natural gas and associated transportation. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Information required by this item is in Item 7 under the heading "Risk Management." KINDER MORGAN, INC. AND SUBSIDIARIES SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
YEAR ENDED DECEMBER 31, 2000 ----------------------------------------------------------------------------------------- DEDUCTIONS BALANCE AT ADDITIONS WRITE-OFF OF DISCONTINUED BEGINNING OF CHARGED TO COST UNCOLLECTIBLE OPERATIONS BALANCE AT END PERIOD AND EXPENSES ACCOUNTS DEDUCTIONS OF PERIOD ------------ --------------- ------------- ------------ -------------- (In Millions) Allowance for Doubtful Accounts $ 1.7 $ 9.9 $ (9.3) $ -- $ 2.3
YEAR ENDED DECEMBER 31, 1999 ----------------------------------------------------------------------------------------- DEDUCTIONS BALANCE AT ADDITIONS WRITE-OFF OF DISCONTINUED BEGINNING OF CHARGED TO COST UNCOLLECTIBLE OPERATIONS BALANCE AT END PERIOD AND EXPENSES ACCOUNTS DEDUCTIONS OF PERIOD ------------ --------------- ------------- ------------ -------------- (In Millions) Allowance for Doubtful Accounts $ 10.8 $ 3.6 $ (0.6) $ (12.1) $ 1.7
F-64 67 SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized. KINDER MORGAN, INC. Dated: February 16, 2001 By: /s/ JOSEPH LISTENGART ------------------------------- Joseph Listengart Vice President and General Counsel 68 EXHIBIT INDEX
EXHIBIT NUMBER DESCRIPTION ------ ----------- 23.1 Consent of PricewaterhouseCoopers LLP 23.2 Consent of Arthur Andersen LLP 99.1 Form 8-K Kinder Morgan Energy Partners, L.P. dated February 16, 2001, including the consolidated financial statements of Kinder Morgan Energy Partners, L.P.
EX-23.1 2 h84343ex23-1.txt CONSENT OF PRICEWATERHOUSECOOPERS LLP 1 EXHIBIT 23.1 CONSENT OF INDEPENDENT ACCOUNTANTS We hereby consent to the incorporation by reference in the Registration Statements on (i) Form S-16, (Nos. 2-51894, 2-55664, 2-63470 and 2-75654); (ii) Form S-8, (Nos. 2-77752, 33-10747, 33-24934, 33-33018, 33-54403, 33-54443, 33-54555, 333-08059, 333-08087, 333-60839, 333-42178 and 333-53908); and (iii) Form S-3, (Nos. 2-84910, 33-26314, 33-23880, 33-42698, 33-44871, 33-45091, 33-46999, 33-54317, 33-69432, 333-04385, 333-40869, 333-44421, 333-55921, 333-68257 and 333-54896) of Kinder Morgan, Inc. of our report dated February 14, 2001 relating to the financial statements and financial statement schedule, which appears in this Current Report on Form 8-K, and of our report dated February 14, 2001 relating to the financial statements of Kinder Morgan Energy Partners, L.P., which are incorporated by reference in this Current Report on Form 8-K. PricewaterhouseCoopers LLP Houston, Texas February 16, 2001 EX-23.2 3 h84343ex23-2.txt CONSENT OF ARTHUR ANDERSEN LLP 1 EXHIBIT 23.2 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation by reference in (i) Registration Statements on Form S-16, File Nos. 2-51894, 2-55664, 2-63470 and 2-75654; (ii) Registration Statements on Form S-8, File Nos. 2-77752, 33-10747, 33-24934, 33-33018, 33-54403, 33-54443, 33-54555, 333-08059, 333-08087, 333-60839, 333-42178 and 333-53908; and (iii) Registration Statements on Form S-3, File Nos. 2-84910, 33-26314, 33-23880, 33-42698, 33-44871, 33-45091, 33-46999, 33-54317, 33-69432, 333-04385, 333-40869, 333-44421, 333-55921, 333-68257 and 333-54896 of our report dated February 2, 1999 (except with respect to the matters discussed in Note 6 to the December 31, 2000 consolidated financial statements, as to which the dates are March 16, 2000 and February 14, 2001), on the consolidated financial statements of Kinder Morgan, Inc. and subsidiaries for the year ended December 31, 1998 included in this Form 8-K. Arthur Andersen LLP Denver, Colorado February 16, 2001 EX-99.1 4 h84343ex99-1.txt FORM 8-K OF KINDER MORGAN ENERGY PARTNERS LP 1 SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ---------------------- FORM 8-K CURRENT REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Date of Report February 16, 2001 KINDER MORGAN ENERGY PARTNERS, L.P. (Exact name of registrant as specified in its charter) Delaware (State or other jurisdiction of incorporation) 1-11234 (Commission File Number) 76-0380342 (I.R.S. Employer Identification Number) 500 Dallas Street, Ste. 1000, Houston, Texas 77002 (Address of principal executive offices)(zip code) Registrant's telephone number, including area code: 713-369-9000 ---------------------- 2 Item 7. Financial Statements, Pro Forma Financial Statements and Exhibits (c) Exhibits 23.1 Consent of Independent Accountants 23.2 Consent of Independent Auditors 99.1 Financial Statements of Kinder Morgan Energy Partners, L.P. and Subsidiaries 99.2 Selected Financial Data of Kinder Morgan Energy Partners, L.P. and Subsidiaries 99.3 Management's Discussion and Analysis of Financial Condition and Results of Operations for Kinder Morgan Energy Partners, L.P. and Subsidiaries 99.4 Balance Sheet of Kinder Morgan G.P., Inc. 99.5 Financial Statements of GATX Terminals Companies 99.6 Unaudited Pro Forma Combined Financial Statements of Kinder Morgan Energy Partners, L.P. and Subsidiaries 3 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized. KINDER MORGAN ENERGY PARTNERS, L.P. (A Delaware Limited Partnership) By: KINDER MORGAN G.P., INC. as General Partner By: /s/ C. Park Shaper ------------------------------ C. Park Shaper, Vice President, Treasurer and Chief Financial Officer Date: February 16, 2001 4 EXHIBIT INDEX ------------- Exhibit No. Description ------ ----------- 23.1 Consent of Independent Accountants 23.2 Consent of Independent Auditors 99.1 Financial Statements of Kinder Morgan Energy Partners, L.P. and Subsidiaries 99.2 Selected Financial Data of Kinder Morgan Energy Partners L.P. and Subsidiaries 99.3 Management's Discussion and Analysis of Financial Condition and Results of Operations for Kinder Morgan Energy Partners, L.P. and Subsidiaries 99.4 Balance Sheet of Kinder Morgan G.P., Inc. 99.5 Financial Statements of GATX Terminals Companies 99.6 Unaudited Pro Forma Combined Financial Statements of Kinder Morgan Energy Partners, L.P. and Subsidiaries 5 EXHIBIT 23.1 CONSENT OF INDEPENDENT ACCOUNTANTS We hereby consent to the incorporation by reference in the Registration Statements on (i) Form S-3, (Nos. 333-25995, 333-66931, 333-62155, 333-33726 and 333-54616); (ii) Form S-4, (No. 333-50898); and (iii) Form S-8 (No. 333-56343) of Kinder Morgan Energy Partners, L.P. of our report dated February 14, 2001 relating to the financial statements which appears in this Current Report on Form 8-K. /s/ PricewaterhouseCoopers LLP Houston, Texas February 16, 2001 6 EXHIBIT 23.2 CONSENT OF INDEPENDENT AUDITORS We consent to the incorporation by reference in the Kinder Morgan Energy Partners, L.P. Registration Statements on Form S-3 (Nos. 333-25995, 333-66931, 333-62155, 333-33726 and 333-54616), Registration Statement on Form S-4 (No. 333-50898) and Registration Statement on Form S-8 (No. 333-56343) of our report dated January 23, 2001, with respect to the combined financial statements of the GATX Terminals Companies for the year ended December 31, 2000, which are included in the Kinder Morgan Energy Partners, L.P. Current Report on Form 8-K dated February 16, 2001 filed with the Securities and Exchange Commission. /s/ ERNST & YOUNG LLP Chicago, Illinois February 16, 2001 7 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 8 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 9 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 10 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 11 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 12 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 13 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 14 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 15 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 16 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 17 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 18 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 19 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 20 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 21 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 22 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 23 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 24 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 25 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 26 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 27 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 28 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 29 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 30 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 31 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 32 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 33 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 34 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 35 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 36 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 37 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 38 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 39 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 40 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 41 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 42 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 43 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 44 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 45 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 46 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 47 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on the ______ day of March 2001. KINDER MORGAN ENERGY PARTNERS, L.P. (A Delaware Limited Partnership) By: KINDER MORGAN G.P., INC. as General Partner By: --------------------------------- William V. Morgan, Vice Chairman and President Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities and on the dates indicated.
NAME TITLE DATE ---- ----- ---- Chairman of the Board and Chief Executive March ___, 2001 - -------------------------------------- Officer of Kinder Morgan G.P., Inc. Richard D. Kinder Director, Vice Chairman and President of March ___, 2001 - -------------------------------------- Kinder Morgan G.P., Inc. William V. Morgan Director of Kinder Morgan G.P., Inc. March ___, 2001 - -------------------------------------- Edward O. Gaylord Director of Kinder Morgan G.P., Inc. March ___, 2001 - -------------------------------------- Gary L. Hultquist Director of Kinder Morgan G.P., Inc. March ___, 2001 - -------------------------------------- Perry M. Waughtal Vice President, Treasurer and Chief Financial March ___, 2001 - -------------------------------------- Officer of Kinder Morgan G.P., Inc. (principal C. Park Shaper financial officer and principal accounting officer)
S-1 48 EXHIBIT 99.2 ITEM 6. SELECTED FINANCIAL DATA (UNAUDITED) The following table sets forth, for the periods and the dates indicated, selected historical financial and operating data for us. 1 49
YEAR ENDED DECEMBER 31, 2000(7) 1999(8) 1998(9) 1997 1996 ---------- ---------- ---------- --------- -------- (IN THOUSANDS, EXCEPT PER UNIT AND OPERATING DATA) INCOME AND CASH FLOW DATA: Revenues $ 816,442 $ 428,749 $ 322,617 $ 73,932 $ 71,250 Cost of product sold 124,641 16,241 5,860 7,154 7,874 Operating expenses 190,329 111,275 77,162 17,982 22,347 Fuel and power 43,216 31,745 22,385 5,636 4,916 Depreciation and amortization 82,630 46,469 36,557 10,067 9,908 General and administrative 60,065 35,612 39,984 8,862 9,132 ---------- ---------- ---------- --------- -------- Operating income 315,561 187,407 140,669 24,231 17,073 Earnings from equity investments 71,603 42,918 25,732 5,724 5,675 Amortization of excess cost of equity investments (8,195) (4,254) (764) -- -- Interest (expense) (97,102) (54,336) (40,856) (12,605) (12,634) Interest income and other, net 10,415 22,988 (5,992) (353) 3,129 Income tax (provision) benefit (13,934) (9,826) (1,572) 740 (1,343) ---------- ---------- ---------- --------- -------- Net income before extraordinary charge 278,348 184,897 117,217 17,737 11,900 Extraordinary charge -- (2,595) (13,611) -- -- ---------- ---------- ---------- --------- -------- Net income $ 278,348 $ 182,302 $ 103,606 $ 17,737 $ 11,900 ========== ========== ========== ========= ======== Basic Limited Partners' net income per unit before extraordinary charge(1) $ 2.68 $ 2.63 $ 2.09 $ 1.02 $ 0.90 ========== ========== ========== ========= ======== Basic Limited Partners' income per unit $ 2.68 $ 2.57 $ 1.75 $ 1.02 $ 0.90 ========== ========== ========== ========= ======== Diluted Limited Partners' net income per unit(2) $ 2.67 $ 2.57 $ 1.75 $ 1.02 $ 0.90 ========== ========== ========== ========= ======== Per unit cash distribution paid $ 3.20 $ 2.78 $ 2.39 $ 1.63 $ 1.26 ========== ========== ========== ========= ======== Additions to property, plant and equipment $ 125,523 $ 82,725 $ 38,407 $ 6,884 $ 8,575 BALANCE SHEET DATA (AT END OF PERIOD): Net property, plant and equipment $3,306,305 $2,578,313 $1,763,386 $ 244,967 $235,994 Total assets $4,625,210 $3,228,738 $2,152,272 $ 312,906 $303,603 Long-term debt $1,255,453 $ 989,101 $ 611,571 $ 146,824 $160,211 Partners' capital $2,117,067 $1,774,798 $1,360,663 $ 150,224 $118,344 OPERATING DATA: Product Pipelines - Pacific - Mainline delivery volumes (MBbls)(3) 386,611 375,663 307,997 -- -- Pacific - Other delivery volumes (MBbls)(3) 14,243 10,025 17,957 -- -- Plantation - Delivery volumes (MBbls) 226,795 214,900 -- -- -- North System/Cypress - Delivery volumes (MBbls) 51,111 50,124 44,783 46,309 46,601 Natural Gas Pipelines - Transport volumes (Bcf)(4) 449.2 424.3 -- -- -- CO2 Pipelines - Delivery volumes (Bcf)(5) 386.5 379.3 -- -- -- Bulk Terminals - Transload tonnage (Mtons)(6) 41,529 39,190 24,016 9,087 6,090
(1) Represents net income before extraordinary charge per unit adjusted for the two-for-one split of units on October 1, 1997. Basic Limited Partners' net income per unit before extraordinary charge was computed by dividing the interest of our unitholders in net income before extraordinary charge by the weighted average number of units outstanding during the period. (2) Diluted Limited Partners' net income per unit reflects the potential dilution, by application of the treasury stock method, that could occur if options to issue units were exercised, which would result in the issuance of additional units that would then share in our net income. (3) We acquired our Pacific operations on March 6, 1998. (4) KMIGT and Trailblazer assets were acquired on December 31, 1999. 1999 volumes were shown for comparative purposes only. (5) Acquired remaining 80% interest in Kinder Morgan CO2 Company, L.P., effective April 1, 2000. YTD 2000 and 1999 volume information is adjusted to include properties acquired from Devon Energy effective June 1, 2000, and to correct volumes previously reported. YTD 2000 and 1999 volume information is shown for comparative purposes only. (6) Represents the volumes of the Cora Terminal, excluding ship or pay volumes of 252 Mtons for 1996, the Grand Rivers Terminal from September 1997, Kinder Morgan Bulk Terminals from July 1, 1998 and the Pier IX and Shipyard Terminals from December 18, 1998. (7) Includes results of operations for KMIGT, 66 2/3% interest in Trailblazer Pipeline Company, 49% interest in Red Cedar, Milwaukee Bulk Terminals, Dakota Bulk Terminal, remaining 80% interest in KMCO2, Devon Energy CO2 properties, Buckeye Refining Company, LLC, 32.5% interest in Cochin Pipeline System and Delta Terminal Services since dates of acquisition. (8) Includes results of operations for 51% interest in Plantation Pipe Line Company, Product Pipelines' transmix operations and 33 1/3% interest in Trailblazer Pipeline Company since dates of acquisition. (9) Includes results of operations for Pacific operations, Kinder Morgan Bulk Terminals and 24% interest in Plantation Pipe Line Company since dates of acquisition. 2 50 EXHIBIT 99.3 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS You should read the following discussion and analysis in conjunction with our "Selected Financial Data," and our financial statements and the related notes appearing elsewhere in this prospectus. RESULTS OF OPERATIONS Kinder Morgan Energy Partners, L.P.'s financial results over the past two years reflect significant growth in revenues, operating income and net income. During this timeframe, we have consistently made strategic business acquisitions and experienced ongoing strength in all of our pipeline and terminal operations. The combination of targeted business acquisitions, higher capital spending, favorable economic conditions and management's continuing focus on controlling general and operating expenses across our entire business portfolio led the way to strong growth in all four of our business segments. In 2000, we reported record levels of revenue, operating income, net income and earnings per unit. Our net income was $278.3 million ($2.67 per diluted unit) on revenues of $816.4 million in 2000, compared to net income of $182.3 million ($2.57 per diluted unit) on revenues of $428.7 million in 1999, and net income of $103.6 million ($1.75 per diluted unit) on revenues of $322.6 million in 1998. Included in our net income for 1999 and 1998 were extraordinary charges associated with debt refinancing transactions in the amount of $2.6 million in 1999 and $13.6 million in 1998. In addition, our 1999 net income included a benefit of $10.1 million related to the sale of our 25% interest in the Mont Belvieu fractionation facility, partially offset by special non-recurring charges. Our total consolidated operating income was $315.6 million in 2000, $187.4 million in 1999 and $140.7 million in 1998. Our total consolidated net income before extraordinary charges was $278.3 million in 2000, $184.9 million in 1999 and $117.2 million in 1998. Our increase in overall net income and revenues in 2000 compared to 1999 primarily resulted from the inclusion of the Natural Gas Pipelines segment, acquired from Kinder Morgan, Inc. on December 31, 1999, and our acquisition of the remaining 80% ownership interest in Kinder Morgan CO2 Company, L.P. (formerly Shell CO2 Company, Ltd.) effective April 1, 2000. Prior to that date, we owned a 20% equity interest in Kinder Morgan CO2 Company, L.P. and reported its results under the equity method of accounting. The results of Kinder Morgan CO2 Company, L.P. are included in our CO2 Pipelines segment. Our acquisition of substantially all of our Product Pipelines' transmix operations in September 1999, and Milwaukee Bulk Terminals, Inc. and Dakota Bulk Terminal, Inc. in January 2000, also contributed to our overall increase in period-to-period revenues and net income. The inclusion of a full year of activity for our Pacific operations and Bulk Terminals segment was the largest contributing factor for the increase in total revenues and earnings in 1999 compared with 1998. We acquired our Pacific operations in March 1998, Kinder Morgan Bulk Terminals, Inc. in July 1998 and the Pier IX and Shipyard River terminals in December 1998. 1 51 PRODUCT PIPELINES Our Product Pipelines' segment revenues increased 34%, from $314.1 million in 1999 to $421.4 million in 2000, and net income increased 6%, from $209.0 million in 1999 to $221.2 million in 2000. The year-to-year increase in revenues resulted primarily from the inclusion of a full year of our transmix operations, which were mainly acquired in September 1999, and additional transmix assets acquired in October 2000. Furthermore, higher throughput volumes on both our Pacific operations and North System pipelines contributed to the increase in segment revenues. On our Pacific operations, average tariff rates remained relatively flat between 2000 and 1999, with an almost 3% increase in mainline delivery volumes resulting in a 3% increase in revenues. On our North System, revenues grew 14% in 2000 compared to 1999. The increase was due to an almost 10% increase in throughput revenue volumes, primarily due to strong refinery demand in the Midwest, as well as a 5% increase in average tariff rates. In 1998, the Product Pipeline segment earned $156.9 million on revenues of $258.7 million. The increase in revenues in 1999 over 1998 relates to the inclusion in 1999 of a full year of results from our Pacific operations, acquired in March 1998, and the inclusion of almost four months of transmix operations, which were acquired in early September 1999. With a full twelve months of activity reported in 1999, total mainline throughput volumes on our Pacific operations pipelines increased 22% in 1999 compared to 1998. The higher 1999 segment revenues were partly offset by an almost 4% decrease in average tariff rates on our Pacific pipelines. The decrease in average tariff rates was mainly due to the reduction in transportation rates, effective April 1, 1999, on our Pacific operation's East Line. Combined operating expenses for the Product Pipeline segment, which include the segment's cost of sales, fuel, power and operating and maintenance expenses, were $172.5 million in 2000, $76.5 million in 1999 and $56.3 million in 1998. The increase in expenses in each year resulted mainly from the inclusion of our transmix operations and the higher delivery volumes on our Pacific operations pipelines. Depreciation and amortization expense was $41.7 million in 2000, $38.9 million in 1999 and $32.7 million in 1998, reflecting our acquisitions, continued investments in capital additions and pipeline expansions. Segment operating income was $193.5 million in 2000, $186.1 million in 1999 and $159.2 million in 1998. Earnings from our equity investments, net of amortization of excess costs, were $29.1 million in 2000, $21.4 million in 1999 and $5.9 million in 1998. The increases in our equity earnings each year were chiefly due to our investments in Plantation Pipe Line Company. We acquired a 24% ownership interest in September 1998 and an additional 27% ownership interest in June 1999. Additionally, the Product Pipeline segment benefited from favorable changes in non-operating income/expense in 1999 compared to 1998, primarily the result of lower 1999 expense accruals made for our FERC rate case reserve (as a result of the FERC's opinion relating to an outstanding rate case dispute), 1999 insurance recoveries and favorable adjustments to employee post-retirement benefit liabilities. 2 52 NATURAL GAS PIPELINES Our Natural Gas Pipelines segment reported earnings of $112.9 million on revenues of $173.0 million in 2000. These results were produced from assets that we acquired from Kinder Morgan, Inc. on December 31, 1999. For comparative purposes, transported gas volumes on our natural gas assets increased almost 6% in 2000 compared with 1999 when these assets were owned by Kinder Morgan, Inc. The overall increase includes an almost 9% increase in volumes shipped on the Trailblazer Pipeline. Higher receipt-side pressure on the Trailblazer Pipeline during 2000 resulted in an increase in the available quantity of gas delivered to the Trailblazer Pipeline. Segment operating expenses totaled $51.2 million in 2000 and segment operating income was $97.2 million. Earnings for 2000 from the segment's 49% equity investment in Red Cedar Gathering Company, net of amortization of excess costs, were $15.0 million. Segment results for 1999 and 1998 primarily represent activity from our since divested partnership interest in the Mont Belvieu fractionation facility. Segment earnings of $16.8 million in 1999 includes $2.5 million in equity earnings from our interest in the fractionation facility and $14.1 million from our third quarter gain on the sale of that interest to Enterprise Products Partners, L.P. In 1998, the segment reported earnings of $4.9 million, including equity income of $4.6 million. This amount represents earnings from our interest in the Mont Belvieu facility for a full twelve-month period. CO2 PIPELINES Our CO2 Pipelines segment consists of Kinder Morgan CO2 Company, L.P. After our acquisition of the remaining 80% interest in Kinder Morgan CO2 Company, L.P., on April 1, 2000, we no longer accounted for our investment on an equity basis. Our 2000 results also include the segment's acquisition of significant CO2 pipeline assets and oil-producing property interests on June 1, 2000. For the year 2000, the segment reported earnings of $68.0 million on revenues of $89.2 million. CO2 Pipelines reported operating expenses of $26.8 million and operating income of $47.9 million. Equity earnings from the segment's 50% interest in the Cortez Pipeline Company, net of amortization of excess costs, were $19.3 million. Segment results from 1999 and 1998 primarily represent equity earnings from our original 20% interest in Kinder Morgan CO2 Company, L.P. Segment earnings of $15.2 million in 1999 include $14.5 million in equity earnings from our interest in Kinder Morgan CO2 Company, L.P. In 1998, our CO2 Pipelines segment reported earnings of $15.5 million, including $14.5 million in equity earnings from our Kinder Morgan CO2 Company, L.P. investment. Under the terms of the prior Kinder Morgan CO2 Company, L.P. partnership agreement, we received a priority distribution of $14.5 million per year during 1998, 1999 and the first quarter of 2000. After our acquisition of the remaining 80% ownership interest, we amended this partnership agreement, among other things, to eliminate the priority distribution and other provisions rendered irrelevant by its sole ownership. BULK TERMINALS Our Bulk Terminals segment reported its highest amount of revenues, operating income and earnings in 2000. Following our acquisition of Kinder Morgan Bulk Terminals, Inc. effective July 1, 1998, we continued to make selective acquisitions and increase capital spending in order to grow and expand our bulk terminal businesses. Our 2000 results include the operations 3 53 of Milwaukee Bulk Terminals, Inc. and Dakota Bulk Terminal, Inc., effective January 1, 2000, and Delta Terminal Services, Inc., acquired on December 4, 2000. The 1999 results include the full-year of operations for Kinder Morgan Bulk Terminals, Inc. and the Pier IX and Shipyard River terminals, acquired on December 18, 1998. The Bulk Terminals segment reported earnings of $37.6 million in 2000, $35.0 million in 1999 and $19.2 million in 1998. Segment revenues were $132.8 million in 2000, $114.6 million in 1999 and $62.9 million in 1998. In addition to our acquisitions, our Bulk Terminals segment's overall increases in year-to-year revenues were due to a 10% increase in revenues earned by the segment's Cora and Grand Rivers coal terminals in 1999 and 2000. The 16% increase in segment revenues in 2000 over 1999 reflects a 6% increase in transloaded coal volumes accompanied by a 4% increase in average coal transfer rates. The increase in 1999 was impacted by an 18% increase in transloaded coal volumes, partially offset by a 7% decrease in average transfer rates. The growth in the Bulk Terminals segment revenues over the two-year period was partially offset by lower revenue from coal marketing activities. Bulk Terminals combined operating expenses totaled $81.7 million in 2000 compared to $66.6 million in 1999 and $36.9 million in 1998. The increase in 2000 versus 1999 was the result of acquisitions made in 2000, higher operating expenses associated with the transfer of higher coal volumes and an increase in fuel costs. The increase in 1999 compared to 1998 was the result of including a full year of operations for Kinder Morgan Bulk Terminals, Inc., partially offset by higher 1998 cost of sales expenses related to purchase/sale marketing contracts. Depreciation and amortization expense was $9.6 million in 2000, $7.5 million in 1999 and $3.9 million in 1998. The increases in depreciation were primarily due to the addition of Kinder Morgan Bulk Terminals, Inc. and the Pier IX and Shipyard River terminal in 1998 and the Milwaukee and Dakota Bulk Terminals in 2000, as well as to higher property balances as a result of increased capital spending. OTHER Items not attributable to any segment include general and administrative expenses, interest income and expense and minority interest. General and administrative expenses totaled $60.1 million in 2000 compared with $35.6 million in 1999 and $40.0 million in 1998. The increase in our 2000 general and administrative expenses over the prior year was mainly due to our larger and more diverse operations. During 2000, we assimilated the operations of our Natural Gas Pipelines and CO2 Pipelines business segments. We continue to manage aggressively our infrastructure expense and to focus on its productivity and expense controls. Our total interest expense, net of interest income, was $93.3 million in 2000, $52.6 million in 1999 and $38.6 million in 1998. The increases were primarily due to debt we assumed as part of the acquisition of our Pacific operations as well as additional debt related to the financing of our 2000 and 1999 investments. Minority interest increased to $8.0 million in 2000 compared with $2.9 million in 1999 and $1.0 million in 1998. The $5.1 million increase in 2000 over 1999 primarily resulted from the inclusion of earnings attributable to the Trailblazer Pipeline Company. The $1.9 million increase in 1999 over 1998 resulted from higher earnings attributable to our Pacific operations as well as to our higher overall income. 4 54 OUTLOOK We actively pursue a strategy to increase our operating income. We will use a three-pronged strategy to accomplish this goal. - Cost Reductions. We have substantially reduced the operating expenses of those operations that we owned at the time Kinder Morgan (Delaware), Inc. acquired our general partner in February 1997. In addition, we have made substantial reductions in the operating expenses of the businesses and assets that we acquired since February 1997. We intend to continue to seek further reductions where appropriate. - Internal Growth. We intend to expand the operations of our current facilities. We have taken a number of steps that management believes will increase revenues from existing operations, including the following: - completing the expansion of our San Diego Line in June 2000. The expansion project cost approximately $18 million and consisted of the construction of 23 miles of 16-inch diameter pipe and other appurtenant facilities. The new facilities will increase capacity on our San Diego Line by approximately 25%; - entering into an agreement to provide pipeline transportation services on the North System for Aux Sable Liquid Products, L.P. in the Chicago area beginning in first quarter 2001; - constructing a multi-million dollar cement import and distribution facility at the Shipyard River terminal, which was completed in the fourth quarter 2000, as part of a 30 year cement contract with Blue Circle Cement; - announcing an expansion project on the Trailblazer Pipeline in August 2000. The project will involve the installation of two new compressor stations and the addition of horsepower at an existing compressor station; - continuing a $13 million upgrade to the coal loading facilities at the Cora and Grand Rivers coal terminals. The two terminals handled an aggregate of 17.0 million tons of coal during 2000 compared with 16.0 million tons in 1999; and - increasing earnings and cash flow, as a result of our investments, acquisitions and operating performance. STRATEGIC ACQUISITIONS. Since January 1, 2000, we have made the following acquisitions: - - Milwaukee Bulk Terminals, Inc. January 1, 2000 - - Dakota Bulk Terminal, Inc. January 1, 2000 - - Kinder Morgan CO2 Company, L.P. (80%) April 1, 2000 - - CO2 Assets June 1, 2000 - - Transmix Assets October 25, 2000 - - Cochin Pipeline System November 3, 2000 - - Delta Terminal Services, Inc. December 1, 2000 - - Kinder Morgan Texas Pipeline, L.P. December 21, 2000 - - Casper-Douglas Gas Gathering and Processing Assets December 21, 2000 - - Coyote Gas Treating, LLC (50%) December 21, 2000 - - Thunder Creek Gas Services, LLC (25%) December 21, 2000 - - CO2 Investment to be contributed to joint venture with Marathon December 28, 2000 - - Colton Transmix Processing Facility (50%) December 31, 2000
5 55 We regularly seek opportunities to make additional strategic acquisitions, to expand existing businesses and to enter into related businesses. We periodically consider potential acquisition opportunities as such opportunities are identified. No assurance can be given that we will be able to consummate any such acquisition. Our management anticipates that we will finance acquisitions temporarily by borrowings under our bank credit facilities or by issuing commercial paper, and permanently by issuing new debt securities and/or units. On January 17, 2001, we announced a quarterly distribution of $0.95 per unit for the fourth quarter of 2000. The distribution for the fourth quarter of 1999 was $0.725 per unit. LIQUIDITY AND CAPITAL RESOURCES Our primary cash requirements, in addition to normal operating expenses, are debt service, sustaining capital expenditures, expansion capital expenditures and quarterly distributions to its common unitholders. In addition to utilizing cash generated from operations, we could meet our cash requirements through borrowings under our credit facilities or issuing short-term commercial paper, long-term notes or additional units. We expect to fund: - future cash distributions and sustaining capital expenditures with existing cash and cash flows from operating activities; - expansion capital expenditures through additional borrowings or issuance of additional units; - interest payments from cash flows from operating activities; and - debt principal payments with additional borrowings as they become due or by issuance of additional units. OPERATING ACTIVITIES Net cash provided by operating activities was $301.6 million in 2000 compared to $182.9 million in 1999. Increases in our period-to-period cash flows from operations resulted from: - a $93.4 million increase in net earnings; - a $36.2 million increase in non-cash depreciation and amortization charges; - a $28.4 million increase in cash inflows relative to net changes in working capital items; - a $14.0 million increase in cash inflows relative to other non-cash operating activities; - a $13.8 million increase in distributions from equity investments; and - a $10.1 million gain on the sale of our equity interest in the Mont Belvieu fractionation facility, net of special charges, in the third quarter of 1999. Higher earnings and higher non-cash depreciation charges in 2000 compared to 1999 were primarily due to the business acquisitions and capital investments we made during 2000. Higher cash inflows from working capital items were mainly due to favorable changes in our accounts receivable-trade balances, particularly from our Pacific operations and our newly acquired CO2 businesses, and from higher collections on our Pacific operations' insurance receivables. The $14.0 million increase in other non-cash operating activities was primarily due to favorable changes in accrued gas transportation imbalances recorded by our Natural Gas Pipelines. The increase in distributions from equity investments was mainly due to distributions 6 56 we received in 2000 from our 50% ownership interest in Cortez Pipeline Company and our 49% ownership interest in Red Cedar Gathering Company. Following our acquisition of the remaining ownership interest in Kinder Morgan CO2 Company, L.P. on April 1, 2000 we accounted for our investment in Cortez Pipeline Company under the equity method of accounting. We acquired our interest in Red Cedar Gathering Company from Kinder Morgan, Inc. on December 31, 1999. The overall increase in distributions from equity investments was partially offset by the absence of distributions from our original 20% interest in Kinder Morgan CO2 Company, L.P. from April 1, 2000 through December 31, 2000 due to the fact we no longer accounted for this investment on an equity basis. Our overall increase in cash provided by operating activities was offset by: - a $52.5 million payment of accrued rate refund liabilities; and - a $24.7 million increase in undistributed earnings from equity investments, net of amortization of excess costs. The payment of the rate refunds was made under settlement agreements with shippers on our natural gas pipelines. The increase in undistributed earnings from equity investments, net of amortization of excess costs, resulted primarily from earnings generated from our investments in Cortez Pipeline Company and Red Cedar Gathering Company. Higher overall equity earnings were partly offset by the absence of earnings in 2000 from our investment in the Mont Belvieu fractionation facility, and, as was the case in distributions, the absence of earnings from our original 20% interest in Kinder Morgan CO2 Company, L.P. from April 1, 2000 through December 31, 2000 due to the fact we no longer accounted for this investment on an equity basis. INVESTING ACTIVITIES Net cash used in investing activities was $1,197.6 million in 2000 compared to $196.5 million in 1999, an increase of $1,001.1 million chiefly attributable to the $1,008.6 million of asset acquisitions we made in 2000. Our 2000 acquisition outlays included: - a $478.3 million payment to Kinder Morgan, Inc. for the Natural Gas Pipelines assets; - a $188.9 million net payment for the remaining 80% interest in Kinder Morgan CO2 Company, L.P.; - a $120.5 million payment for our 32.5% ownership interest in the Cochin Pipeline System; - a $114.3 million payment for Bulk Terminal acquisitions, including Milwaukee Bulk Terminals, Inc., Dakota Bulk Terminal, Inc. and Delta Terminal Services, Inc.; - a $53.4 million payment for our interests in the Canyon Reef Carriers CO2 pipeline and SACROC Unit; and - a $45.7 million payment for the acquisition of Buckeye Refining Company, LLC. We expended an additional $42.8 million for capital expenditures in 2000 compared to 1999. Including expansion and maintenance projects, our capital expenditures were $125.5 million in 2000 and $82.7 million in 1999. The increase was driven primarily by continued investment in our Pacific operations and in our Bulk Terminals business segment. Proceeds from the sale of investments, property, plant and equipment, net of removal costs, were lower by 7 57 $29.7 million in 2000 versus 1999. Proceeds received from sales and retirements of investments, property, plant and equipment were $13.4 million in 2000 and $43.1 million in 1999. The decrease was due to the $41.8 million we received for the sale of our interest in the Mont Belvieu fractionation facility in September 1999. The overall increase in funds used in investing activities was offset by a $82.4 million decrease in cash used for acquisitions of investments. We used $79.4 million for acquisitions of investments in 2000 compared with $161.8 million in 1999. Our 2000 investment outlays included: - $34.2 million for our 7.5% interest in the Yates field unit subsequently contributed to the CO2 joint venture with Marathon Oil Company; - $44.6 million for our 25% interest in Thunder Creek Gas Services, LLC and our 50% interest in Coyote Gas Treating, LLC. Our 1999 investment outlays consisted of: - $124.2 million for our second investment in Plantation Pipe Line Company; and - $37.6 million for our first one-third interest in Trailblazer Pipeline Company. FINANCING ACTIVITIES Net cash provided by financing activities amounted to $915.3 million in 2000, an increase of $893.3 million from the prior year was mainly the result of an additional $817.1 million we received from overall debt financing activities. The increase in borrowings was mainly due to 2000 acquisitions. We completed a private placement of $400 million in debt securities during the first quarter of 2000, resulting in a cash inflow of $397.9 million net of discounts and issuing costs. We completed a second private placement of $250 million in debt securities during the fourth quarter of 2000, resulting in a cash inflow of $246.8 million net of discounts and issuing costs. In addition, we received $171.4 million as proceeds from our issuance of units during 2000, most significantly realized from our 4,500,000-unit public offering on April 4, 2000. The overall increase in funds provided by our financing activities was partially offset by a $102.8 million increase in our distributions to partners. Distributions to all partners increased to $293.6 million in 2000 compared to $190.8 million in 1999. The increase in distributions was due to: - an increase in our per unit distributions paid; - an increase in our number of units outstanding; - Our general partner incentive distributions, which resulted from increased distributions to our unitholders; and - distributions paid by Trailblazer Pipeline Company, which were included in our consolidated results following the acquisition of our controlling 66 2/3% interest on December 31, 1999. We paid distributions of $3.20 per unit in 2000 compared to $2.775 per unit in 1999. The 15% increase in paid distributions per unit resulted from favorable operating results in 2000. We believe that future operating results will continue to support similar or higher levels of quarterly cash distributions, however, no assurance can be given that future distributions will continue at such levels. 8 58 PARTNERSHIP DISTRIBUTIONS Our partnership agreement requires that we distribute 100% of our Available Cash to our partners within 45 days following the end of each calendar quarter in accordance with their respective percentage interests. Our available cash consists generally of all of our cash receipts, including cash received by our operating partnerships, less cash disbursements and net additions to reserves (including any reserves required under debt instruments for future principal and interest payments) and amounts payable to the former general partner of Santa Fe Pacific Pipeline, L.P. in respect of our remaining 0.5% interest in Santa Fe Pacific Pipeline, L.P. Our available cash is initially distributed 98% to our limited partners and 2% to our general partner, Kinder Morgan G.P., Inc. These distribution percentages are modified to provide for incentive distributions to be paid to our general partner in the event that quarterly distributions to unitholders exceed certain specified targets. Our available cash for each quarter is distributed: - 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; - 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; - 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 - 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. The general partner's incentive distributions declared by us for 2000 were $107,764,885, while the incentive distributions paid during 2000 were $89,399,771. DEBT AND CREDIT FACILITIES Our debt and credit facilities as of December 31, 2000, consist primarily of: - a $600 million unsecured 364-day credit facility due October 25, 2001; - a $300 million unsecured five-year credit facility due September 29, 2004; - $250 million of 6.30% Senior Notes due February 1, 2009; - $200 million of 8.00% Senior Notes due March 15, 2005; - $250 million of 7.50% Senior Notes due November 1, 2010; - $200 million of Floating Rate Senior Notes due March 22, 2002; - $119 million of Series F First Mortgage Notes (our subsidiary, SFPP, is the obligor on the notes); - $20.2 million of Senior Secured Notes (Trailblazer Pipeline Company, of which we own 66 2/3%, is the obligor on the notes); - $23.7 million of tax-exempt bonds due 2024 (our subsidiary, Kinder Morgan Operating L.P. "B" is the obligor on these bonds); and - a $600 million short-term commercial paper program. 9 59 We have a $300 million unsecured five-year credit facility and a $600 million unsecured 364-day credit facility with a syndicate of financial institutions. First Union National Bank is the administrative agent under the agreements. Interest on borrowings is payable quarterly. Interest on the credit facilities accrues at our option at a floating rate equal to either: - First Union National Bank's base rate (but not less than the Federal Funds Rate, plus .5%); or - LIBOR, plus a margin, which varies depending upon the credit rating of our long-term senior unsecured debt. The LIBOR margins under the 364-day credit facility are lower than the margins under the five-year credit facility. The five-year credit facility also permits us to obtain bids for fixed rate loans from members of the lending syndicate. The credit facilities include restrictive covenants that are customary for these types of facilities, including without limitation: - requirements to maintain certain financial ratios; - restrictions on the incurrence of additional indebtedness; - restrictions on entering into mergers, consolidations and sales of assets; - restrictions on granting liens; - prohibitions on making cash distributions to holders of units more frequently than quarterly; - prohibitions on making cash distributions in excess of 100% of Available Cash for the immediately preceding calendar quarter; and - prohibitions on making any distribution to holders of units if an event of default exists or would exist upon making such distribution. As of December 31, 2000, we had outstanding borrowings under our credit facilities of $789.6 million. At December 31, 2000, the interest rate on our credit facilities was 7.115% per annum. Our borrowings at December 31, 2000 included the following: - $193 million borrowed to fund the purchase price of natural gas pipelines assets acquired in December 2000; - $175 million used to pay the outstanding balance on SFPP, L.P.'s credit facility; - $118 million borrowed to fund the purchase price of our 32.5% interest in the Cochin Pipeline system in December 2000; - $114 million borrowed to fund the purchase price of Delta Terminal Services, Inc. in December 2000; - $72 million borrowed to fund principal and interest payments on SFPP, L.P.'s Series F Notes in December 2000; - $34 million borrowed to fund the purchase price of our 7.5% interest in the Yates field unit in December 2000; and - $83.6 million borrowed to fund expansion capital projects. Our short-term debt at December 31, 2000, consisted of: - $582 million of borrowings under our unsecured 364-day credit facility due October 25, 2001; - $52.0 million of commercial paper borrowings; - $35.0 million under the SFPP 10.70% First Mortgage Notes; and - $14.6 million in other borrowings. During 2000, cash used for acquisitions and expansions exceeded $600 million. Historically, we have utilized our short-term credit facilities to fund acquisitions and expansions and then refinanced our short-term borrowings utilizing long-term credit facilities and by issuing equity or long-term debt securities. We intend to refinance our short-term debt during 2001 through a combination of long-term debt and equity. Based on prior successful short-term debt refinancings and current market conditions, we do not anticipate any liquidity problems. 10 60 We have an outstanding letter of credit issued under our five-year credit facility in the amount of $23.7 million that backs-up our tax-exempt bonds due 2024. The letter of credit reduces the amount available for borrowing under that credit facility. The $23.7 million principal amount of tax-exempt bonds due 2024 were issued by the Jackson-Union Counties Regional Port District. These bonds bear interest at a weekly floating market rate. At December 31, 2000, the interest rate was 5.00%. In addition, as of December 31, 1999, we financed $330 million through Kinder Morgan, Inc. to fund part of the acquisition of assets acquired from Kinder Morgan, Inc. on December 31, 1999. In accordance with the Closing Agreement entered into as of January 20, 2000, we paid Kinder Morgan, Inc. a per diem fee of $180.56 for each $1,000,000 financed. We paid Kinder Morgan, Inc. $200 million on January 21, 2000, and the remaining $130 million on March 23, 2000 with a portion of the proceeds from our issuance of notes on March 22, 2000. In December 1999, we established a commercial paper program providing for the issuance of up to $200 million of commercial paper, subsequently increased to $300 million in January, 2000 and then on October 25, 2000, in conjunction with our new 364-day credit facility, we increased the commercial paper program to provide for the issuance of up to $600 million of commercial paper. Borrowings under our commercial paper program reduce the borrowings allowed under our 364-day and five-year credit facilities combined. As of December 31, 2000, we had $52 million of commercial paper outstanding with an interest rate of 7.02%. At December 31, 2000, the outstanding balance under SFPP, L.P.'s Series F notes was $119.0 million. The annual interest rate on the Series F notes is 10.70%, the maturity is December 2004, and interest is payable semiannually in June and December. The Series F notes are payable in annual installments of $39.5 million in 2001, $42.5 million in 2002 and $37.0 million in 2003. The Series F notes may also be prepaid in full or in part at a price equal to par plus, in certain circumstances, a premium. The Series F notes are secured by mortgages on substantially all of the properties of SFPP, L.P. The Series F notes contain certain covenants limiting the amount of additional debt or equity that may be issued and limiting the amount of cash distributions, investments, and property dispositions. At December 31, 1999, the outstanding balance under SFPP, L.P.'s bank credit facility was $174.0 million. On August 11, 2000, we replaced the outstanding balance under SFPP, L.P.'s secured credit facility with a $175.0 million unsecured borrowing under our five-year credit facility. SFPP, L.P. executed a $175 million intercompany note in our favor to evidence this obligation. In December 1999, Trailblazer Pipeline Company entered into a 364-day revolving credit agreement with Toronto Dominion, Inc. providing for loans up to $10 million. At December 26, 2000, the outstanding balance due under Trailblazer Pipeline Company's bank credit facility was $10 million. On December 27, 2000, Trailblazer Pipeline Company paid the outstanding balance under its credit facility with a $10 million borrowing under an intercompany account payable in favor of Kinder Morgan, Inc. In January 2001, Trailblazer Pipeline Company entered into a 364-day revolving credit agreement with Credit Lyonnais New York Branch, providing for loans up to $10 million. The agreement expires December 27, 2001. The borrowings were used to pay 11 61 the account payable to Kinder Morgan, Inc. At January 31, 2001, the outstanding balance under Trailblazer Pipeline Company's revolving credit agreement was $10 million. The agreement provides for an interest rate of LIBOR plus 0.875%. At January 31, 2001 the interest rate on the credit facility debt was 6.625%. Pursuant to the terms of the revolving credit agreement with Credit Lyonnais New York Branch, Trailblazer Pipeline Company partnership distributions are restricted by certain financial covenants. From time to time we issue long-term debt securities. All of our long-term debt securities issued to date, other than those issued under our revolving credit facilities, generally have the same terms except for interest rates, maturity dates and prepayment restrictions. All of our outstanding debt securities are unsecured obligations that rank equally with all of our other senior debt obligations. Our outstanding debt securities consist of the following: - $250 million in principal amount of 6.3% senior notes due February 1, 2009. These notes were issued on January 29, 1999 at a price to the public of 99.67% per note. In the offering, we received proceeds, net of underwriting discounts and commissions, of approximately $248 million. We used the proceeds to pay the outstanding balance on our credit facility and for working capital and other partnership purposes. At December 31, 2000, the unamortized liability balance on the 6.30% senior notes was $249.3 million; - $200 million of floating rate notes due March 22, 2002 and $200 million of 8.0% notes due March 15, 2005. We used the proceeds to reduce outstanding commercial paper. At December 31, 2000, the interest rate on our floating rate notes was 7.0%. - $250 million of 7.5% notes due November 1, 2010. These notes were issued on November 8, 2000. The proceeds from this offering, net of underwriting discounts, were $246.8 million. These proceeds were used to reduce our outstanding commercial paper. At December 31, 2000, the unamortized liability balance on the 7.5% notes was $248.4 million. The fixed rate notes provide that we may redeem the notes at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date plus a make-whole premium. We may not prepay the floating rate notes prior to their maturity. On September 23, 1992, pursuant to the terms of a Note Purchase Agreement, Trailblazer Pipeline Company issued and sold an aggregate principal amount of $101 million of Senior Secured Notes to a syndicate of fifteen insurance companies. Trailblazer Pipeline Company provided security for the notes principally by an assignment of certain Trailblazer Pipeline Company transportation contracts. Effective April 29, 1997, Trailblazer Pipeline Company amended the Note Purchase Agreement. This amendment allowed Trailblazer Pipeline Company to include several additional transportation contracts as security for the notes, added a limitation on the amount of additional money that Trailblazer Pipeline Company could borrow and relieved Trailblazer Pipeline Company from its security deposit obligation. At December 31, 2000, Trailblazer Pipeline Company's outstanding balance under the Senior Secured Notes was $20.2 million. The Senior Secured Notes have a fixed annual interest rate of 8.03% and will be repaid in semiannual installments of $5.05 million from March 1, 2001 through September 1, 2002, the final maturity date. Interest is payable semiannually in March and September. Pursuant to the terms of this Note Purchase Agreement, Trailblazer Pipeline Company partnership distributions are restricted by certain financial covenants. Currently, Trailblazer Pipeline Company's proposed expansion project is pending before the FERC. If the expansion is approved, which is expected in the first quarter of 2001, we plan to refinance these notes. 12 62 CAPITAL REQUIREMENTS FOR RECENT TRANSACTIONS Milwaukee Bulk Terminals, Inc. Effective January 1, 2000, we acquired Milwaukee Bulk Terminals, Inc. for approximately $14.6 million in aggregate consideration consisting of $0.6 million and 0.3 million common units. Dakota Bulk Terminal, Inc. Effective January 1, 2000, we acquired Dakota Bulk Terminal, Inc. for approximately $9.5 million in aggregate consideration consisting of $0.2 million and 0.2 million common units. Kinder Morgan CO2 Company, L.P. On April 1, 2000, we acquired the remaining 80% ownership interest in Shell CO2 Company, Ltd. that we did not own for approximately $212.1 million before purchase price adjustments. We paid this amount with approximately $171.4 million received from our public offering of 4.5 million units on April 4, 2000 and approximately $40.7 million received from the issuance of commercial paper. CO2 Assets. On June 1, 2000, we acquired certain CO2 assets from Devon Energy Production Company, L.P. for approximately $55 million before purchase price adjustments. We borrowed the necessary funds under our commercial paper program. Transmix Operations. On November 3, 2000, we acquired Buckeye Refinery Company, LLC for $45.6 million after purchase price adjustments. We borrowed the necessary funds under our commercial paper program. Delta Terminal Services, Inc. On December 4, 2000, we acquired Delta Terminal Services, Inc. for $114.1 million. We borrowed $114 million under our credit facilities and our commercial paper program. Cochin Pipeline. On October 31, 2000, we acquired a 32.5% ownership interest in the Cochin Pipeline system for $120.5 million from NOVA Chemicals Corporation. We borrowed $118 million under our credit facilities. Colton Transmix Processing Facility. On December 31, 2000 we acquired an additional 50% ownership interest in the Colton Transmix Processing Facility from Duke Energy Merchants for $11.2 million. We borrowed the necessary funds under our commercial paper program. CO2 Joint Venture With Marathon Oil Company. On December 28, 2000, we paid $34.2 million for a 7.5% interest in the Yates field unit which was subsequently contributed to a CO2 joint venture with Marathon Oil Company. The joint venture was formed on January 1, 2001. We borrowed $34 million under our credit facilities. Natural Gas Pipelines. Effective December 31, 2000, we acquired certain assets of Kinder Morgan Inc. for approximately $349.0 million in aggregate consideration consisting of $192.7 million, 0.64 million common units and 2.7 million class B units. We borrowed $193 million under our credit facilities. 13 63 EXHIBIT 99.4 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Stockholder of Kinder Morgan G.P., Inc. In our opinion, the accompanying balance sheet presents fairly, in all material respects, the financial position of Kinder Morgan G.P., Inc. (the General Partner), a wholly-owned subsidiary of Kinder Morgan, Inc., at December 31, 2000 in conformity with accounting principles generally accepted in the United States of America. This financial statement is the responsibility of the General Partner's management; our responsibility is to express an opinion on this financial statement based on our audit. We conducted our audit of this statement 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 balance sheet is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, and evaluating the overall balance sheet presentation. We believe that our audit of the balance sheet provides a reasonable basis for our opinion. /s/ PricewaterhouseCoopers LLP Houston, Texas February 14, 2001 -1- 64 Kinder Morgan G.P., Inc. (a wholly-owned subsidiary of Kinder Morgan, Inc.) Balance Sheet At December 31, 2000 (In Thousands) ASSETS Current assets: Receivable from Kinder Morgan, Inc. $ 315 Receivable from Partnership (Note 3) 11,057 Receivable - Other 378 Prepaid expenses (Note 4) 6,295 ----------- 18,045 Investment in Partnership 1,251,287 Other non-current assets (Note 4) 8,820 ----------- Total assets $1,278,152 ----------- LIABILITIES AND STOCKHOLDER'S EQUITY Current liabilities: Accounts payable - trade $ 7,924 Accrued liabilities 9,434 Payable to Partnership (Note 3) 14,224 Accrued taxes 57,667 ----------- 89,249 Deferred taxes and other 450,805 ----------- 540,054 ----------- Commitments and contingencies (Note 6) Stockholder's equity: Common stock, $10 par value, authorized, issued and outstanding 1,000,000 shares 10,000 Additional paid-in capital 728,098 Accumulated earnings (Note 7) ----------- Total stockholder's equity 738,098 ----------- Total liabilities and stockholders' equity $1,278,152 -----------
The accompanying notes are an integral part of this financial statement. -2- 65 Kinder Morgan G.P., Inc. (a wholly-owned subsidiary of Kinder Morgan, Inc.) Notes to Balance Sheet December 31, 2000 - ------------------------------------------------------------------------------ 1. ORGANIZATION Effective February 14, 1997, Kinder Morgan, Inc. ("KMI") acquired all of the issued and outstanding stock of Enron Liquids Pipeline Company ("ELPC"), and ELPC was renamed Kinder Morgan G.P., Inc. (the "General Partner"). The General Partner owns an effective 3.3% interest in Kinder Morgan Energy Partners, L.P. (the "Partnership") as of December 31, 2000. The ownership interest consists of a 1% general partner interest in the Partnership, 862,000 common units of the Partnership and a 1.0101% general partner interest in each of the Partnership's five operating limited partnerships. The Partnership owns the remaining 98.9899%. On October 7, 1999, KMI completed a merger with K N Energy, Inc., a Kansas corporation, providing integrated energy services including the gathering, processing, transportation and storage of natural gas, marketing of natural gas and natural gas liquids and electric power generation and sales. The combined entity was renamed Kinder Morgan, Inc. and trades under the New York Stock Exchange symbol "KMI." KMI remains the sole stockholder of the General Partner. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The following significant accounting policies are followed by the General Partner in the preparation of the financial statement. USE OF ESTIMATES The preparation of the financial statement in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statement. Actual results could differ from those estimates. INVESTMENT IN PARTNERSHIP The General Partner's investment in the Partnership is accounted for under the equity method. At December 31, 2000, the General Partner's investment in the Partnership exceeded its share of the underlying equity in the net assets of the Partnership by $1,188,746,000. This excess is being amortized on a straight-line basis over 44 years. The amortization period approximates the useful lives of the Partnership's assets, which range from eight to fifty years. INCOME TAXES The General Partner accounts for income taxes under the liability method prescribed by Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes." Deferred income taxes are determined based on temporary differences between the financial reporting and tax bases of the General Partner's assets and liabilities using enacted tax rates in effect during the years in which the differences are expected to reverse. -3- 66 Kinder Morgan G.P., Inc. (a wholly-owned subsidiary of Kinder Morgan, Inc.) Notes to Balance Sheet December 31, 2000 - ------------------------------------------------------------------------------ 3. RELATED PARTY TRANSACTIONS RECEIVABLE FROM PARTNERSHIP General and administrative expenses incurred by the General Partner are all reimbursed by the Partnership as provided in the Partnership Agreement. The receivable from Partnership of $11,057,000 at December 31, 2000, primarily represents general and administrative expenses incurred by the General Partner to be reimbursed by the Partnership. PAYABLE TO PARTNERSHIP The payable to Partnership of $14,224,000 at December 31, 2000, represents amounts paid by the Partnership, on behalf of the General Partner, for certain executive employment agreements (see note 4). 4. EXECUTIVE EMPLOYMENT AGREEMENTS Certain executive officers of the General Partner entered into long-term employment agreements in April 2000. The employment agreements have a term of four years and contain provisions regarding compensation and non-competition. At December 31, 2000, unamortized costs related to these agreements totaled $11,853,000. An amount of $3,556,000 is included with Prepaid expenses and an amount of $8,297,000 is included with Other non-current assets on the accompanying balance sheet. 5. INVESTMENT IN PARTNERSHIP Summarized financial information of the Partnership at December 31, 2000 is presented below (in thousands): Current assets $ 511,261 Noncurrent assets 4,113,949 Current liabilities 1,098,956 Long-term debt and other liabilities 1,351,018 Minority interest 58,169 Partners' capital 2,117,067 6. LITIGATION, COMMITMENTS AND OTHER CONTINGENCIES LITIGATION The General Partner, in the ordinary course of business, is a defendant in various lawsuits relating to the Partnership's assets. The Partnership made certain acquisitions during the year 2000. The General Partner assumed potential and existing claims associated with those acquisitions. Although no assurance can be given, the General Partner believes, based on its experience to date, that the ultimate resolution of such items will not have a material adverse impact on the General Partner's financial position. It is expected that the Partnership will reimburse the General Partner for any liability or expenses incurred in connection with these legal proceedings. -4- 67 Kinder Morgan G.P., Inc. (a wholly-owned subsidiary of Kinder Morgan, Inc.) Notes to Balance Sheet December 31, 2000 - -------------------------------------------------------------------------------- FERC The Partnership and certain of its subsidiaries are defendants in several actions in which the plaintiffs protest pipeline transportation rates with the Federal Energy Regulatory Commission ("FERC"). These actions are currently pending. The Plaintiffs seek to recover transportation overpayments and interests and in some cases treble and punitive damages. The General Partner is not able to predict with certainty whether settlement agreements will be completed with some or all of the complainants, the final terms of any such settlement agreements that may be consummated, or the final outcome of the FERC proceedings should they be carried through to their conclusion, and it is possible that current or future proceedings could be resolved in a manner adverse to the Partnership, which could affect future cash distributions to the General Partner. ENVIRONMENTAL The Partnership is subject to environmental cleanup and enforcement actions from time to time. In particular, the federal Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA" or "Superfund" law) generally imposes joint and several liability for cleanup and enforcement costs, without regard to fault or the legality of the original conduct, on current or predecessor owners and operators of a site. The operations of the Partnership are also subject to federal, state and local laws and regulations relating to protection of the environment. Although the Partnership believes its operations are in general compliance with applicable environmental regulations, risks of additional costs and liabilities are inherent in pipeline and terminal operations, and there can be no assurance significant costs and liabilities will not be incurred by the Partnership. 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 the operations of the Partnership, could result in substantial costs and liabilities to the Partnership which could affect future cash distributions to the General Partner. The Partnership, along with several other respondents, is involved in a cleanup in connection with an acquisition made in 1998. This cleanup, ordered by the United States Environmental Protection Agency ("EPA"), related to ground water contamination in the vicinity of the Partnership's storage facilities and truck loading terminal at Sparks, Nevada. In addition, the Partnership is presently involved in several ground water hydrocarbon remediation efforts under administrative orders issued by the California Regional Water Quality Control Board and two other state agencies. Although no assurance can be given, the General Partner believes the ultimate resolutions of these matters will not have a material adverse effect on the Partnership's financial position, result of operations, or its ability to pay cash distributions to the General Partner. -5- 68 Kinder Morgan G.P., Inc. (a wholly-owned subsidiary of Kinder Morgan, Inc.) Notes to Balance Sheet December 31, 2000 - -------------------------------------------------------------------------------- OTHER The Partnership, in the ordinary course of business, is a defendant in various lawsuits relating to the Partnership's assets. Although no assurance can be given, the General Partner believes, based on its experience to date, the ultimate resolution of such items will not have a material adverse impact on the Partnership's financial position, results of operations, or its ability to pay cash distributions to the General Partner. 7. CAPITAL REPAYMENT During 2000, the General Partner distributed $97,044,000 to its sole stockholder, KMI. Included in this amount was $38,891,000 designated as a return of capital and deducted from additional paid-in capital on the accompanying balance sheet. The remaining $58,153,000 was funded from accumulated earnings. -6- 69 EXHIBIT 99.5 GATX TERMINALS COMPANIES Combined Financial Statements Year ended December 31, 2000 with Report of Independent Auditors 70 GATX TERMINALS COMPANIES Combined Financial Statements December 31, 2000 CONTENTS Report of Independent Auditors.............................................1 Combined Financial Statements: Combined Balance Sheet..............................................2 Combined Statement of Operations....................................4 Combined Statement of Changes in Parent Investment and Advances.................................5 Combined Statement of Cash Flows....................................6 Notes to Combined Financial Statements.....................................7
71 Report of Independent Auditors Board of Directors GATX Terminals Corporation We have audited the accompanying combined balance sheet of the GATX Terminals Companies (the Terminals Companies), as defined in Note 2, an indirect, wholly owned subsidiary of GATX Corporation, as of December 31, 2000, and the related combined statement of operations, changes in parent investment and advances, and cash flows for the year then ended. These financial statements are the responsibility of the Terminals Companies' management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the combined financial position of the Terminals Companies at December 31, 2000, and the combined results of its operations and cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States. /s/ ERNST & YOUNG LLP Chicago, Illinois January 23, 2001 72 GATX TERMINALS COMPANIES Combined Balance Sheet As of December 31, 2000 (In Thousands) ASSETS Current assets: Cash $ 379 Trade receivables - net of allowance for doubtful accounts of $1,054 31,323 Other current assets 1,256 ---------- Total current assets 32,958 Property, plant and equipment: Land 34,015 Terminal facilities, pipelines, and equipment 1,064,521 Construction in progress 28,980 ---------- 1,127,516 Less: Accumulated depreciation 468,212 ---------- Property, plant and equipment, net 659,304 Receivables from Excluded Companies 125,261 Other assets 36,819 ---------- Total assets $ 854,342 ==========
See notes to combined financial statements 2 73 GATX TERMINALS COMPANIES Combined Balance Sheet (Continued) As of December 31, 2000 (In Thousands) LIABILITIES, DEFERRED ITEMS, AND PARENT INVESTMENT AND ADVANCES Current liabilities: Accounts payable $ 5,792 Accrued expenses and interest payable 30,699 Current portion of long-term debt 7,273 ---------- Total current liabilities 43,764 Long-term debt 129,746 Deferred income taxes 98,353 Other long-term liabilities 66,690 ---------- Total liabilities 338,553 Parent investment and advances 515,789 ---------- Total liabilities and parent investment and advances $ 854,342 ==========
See notes to combined financial statements. 3 74 GATX TERMINALS COMPANIES Combined Statement of Operations Year ended December 31, 2000 (In Thousands) Gross income: Revenues $ 261,764 Share of affiliate's loss (2,361) Management fees 850 ------------ 260,253 Costs and expenses: Operating expenses 99,867 Provision for depreciation and amortization 39,631 Selling, general and administrative expenses 27,785 Allocated expenses from parent 5,144 Gain on sale of assets (1,819) Other income (436) Interest expense, net 51,921 Interest income from receivables from Excluded Companies (1,993) ------------ 220,100 ------------ Income before income taxes 40,153 Income tax (benefit) expense: Current (3,808) Deferred 17,835 ------------ 14,027 ------------ Net income $ 26,126 ============
See notes to combined financial statements 4 75 GATX TERMINALS COMPANIES Combined Statement of Changes in Parent Investment and Advances Year ended December 31, 2000 (In Thousands) Balance at January 1, 2000 $ 483,225 Net income 26,126 Dividends paid (17,650) Increase in advances from parent, net 24,088 ------------ Balance at December 31, 2000 $ 515,789 ============
See notes to combined financial statements. 5 76 GATX TERMINALS COMPANIES Combined Statement of Cash Flows Year ended December 31, 2000 (In Thousands) OPERATING ACTIVITIES: Net income $ 26,126 Adjustments to reconcile net income to net cash provided by operating activities: Provision for depreciation and amortization 39,631 Deferred income tax provision 17,835 Share of affiliate's loss 2,361 Gain on sale of property, plant and equipment (1,819) Net change in working capital (18,562) Other (18,613) ------------ Net cash provided by operating activities 46,959 INVESTING ACTIVITIES: Additions to property, plant, equipment and rights of way (27,910) Proceeds from sale of businesses 18,981 Proceeds from sale of property, plant and equipment 2,355 ------------ Net cash used in investing activities (6,574) FINANCING ACTIVITIES: Repayment of long-term debt (7,273) Change in advances from parent, net 24,088 Change in receivables from Excluded Companies (41,303) Dividends paid (17,650) ------------ Net cash used in financing activities (42,138) ------------ Net decrease in cash (1,753) Cash at beginning of year 2,132 ------------ Cash at end of year $ 379 ============
See notes to combined financial statements. 6 77 GATX Terminals Companies Notes to Combined Financial Statements December 31, 2000 1. DESCRIPTION OF BUSINESS GATX Terminals Corporation ("GTC") is an indirect wholly owned subsidiary of GATX Rail Corporation ("GRC"), which in turn is a wholly owned subsidiary of GATX Corporation ("GATX"), collectively referred to as "Parent". GTC is a worldwide bulk liquid storage and pipeline distributor. GTC owns and operates tank storage terminals, pipelines and related facilities. 2. BASIS OF PRESENTATION The accompanying combined financial statements include the accounts and results of operations of the domestic terminals and pipeline businesses of GTC, collectively the Terminals Companies. Historically, combined financial statements had not been prepared for the Terminals Companies. The combined statements do not include the accounts or operations relating to GTC's subsidiaries and equity method investees located outside the United States, GTC's partnership interest in GATX Product Services and GTC's Staten Island facility, collectively the Excluded Companies. The Terminal Companies own and operate tank storage terminals and pipelines and provide bulk liquid storage and pipeline distribution services within the United States. 3. SALE OF TERMINALS COMPANIES On November 30, 2000, GRC and Kinder Morgan Energy Partners, L.P. ("KMEP") entered into a Stock Purchase Agreement (the "Agreement"), whereby GTC would sell to KMEP the stock of GTC. Under the terms of the Agreement, certain assets and liabilities of GTC are excluded from the transaction. These excluded assets and liabilities (collectively the "Adjustments") are as follows: 1.) Assets and liabilities of the Excluded Companies (as defined in the Agreement the Excluded Companies consist of GTC's subsidiaries and equity method investees located outside the U.S., GTC's partnership interest in GATX Product Services and GTC's Staten Island facility). 2.) Intercompany advances from GATX and any of its affiliates, including assets and liabilities relating to income taxes. 3.) All cash balances. 4.) Accruals for pension liabilities, other post-employment benefits (other than for active hourly employees), workers compensation and long-term disability liabilities. 7 78 GATX Terminals Companies Notes to Combined Financial Statements December 31, 2000 3. SALE OF TERMINALS COMPANIES (CONTINUED) The above Adjustments have not been excluded from the accompanying combined financial statements with the exception of the Excluded Companies, whose assets and liabilities, results of operations and cash flows have been excluded. 4. SIGNIFICANT ACCOUNTING POLICIES PRINCIPLES OF COMBINATION The combined financial statements of the Terminals Companies includes the accounts of GTC and its wholly owned subsidiaries except for the Excluded Companies, as discussed in Note 2. All intercompany accounts and transactions have been eliminated in combination. PROPERTY, PLANT, EQUIPMENT AND RIGHT-OF-WAYS Property, plant, equipment and right-of-ways are stated on the basis of cost. Provisions for depreciation or amortization are computed by the straight-line method, which results in equal annual depreciation or amortization charges over the estimated useful lives of the assets. The estimated useful lives of depreciable/amortized assets are 5 to 40 years. Maintenance and repairs are expensed as incurred. IMPAIRMENT OF LONG-LIVED ASSETS The Terminals Companies evaluates the recoverability of long-lived assets held for use in accordance with Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" by measuring the carrying amount of the assets against the estimated undiscounted future cash flows associated with them. At the time such evaluations indicate that the future undiscounted cash flows of certain long-lived assets are not sufficient to recover the carrying value of such assets, the assets are adjusted to their fair value which is based on an estimate of future discounted cash flows. GOODWILL Goodwill, which represents the cost in excess of the fair value of the net assets acquired in business combinations, is being amortized on a straight-line basis over 40 years. Goodwill, net of accumulated amortization of $3,640,000, was $9,800,000 as of December 31, 2000. Amortization expense was $336,000 for 2000. 8 79 GATX Terminals Companies Notes to Combined Financial Statements December 31, 2000 4. SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) OTHER LONG-TERM LIABILITIES Other long-term liabilities include the accruals for postretirement benefits other than pensions; environmental, general liability and workers' compensation reserves; and other deferred credits. ENVIRONMENTAL LIABILITIES Environmental expenditures that relate to current or future operations are expensed or capitalized as appropriate. Environmental expenditures that relate to an existing condition caused by past operations, and which do not contribute to current or future revenue generation, are charged to environmental reserves. Reserves are recorded in accordance with accounting guidelines to cover work at identified sites when the Terminals Companies' liability for environmental clean-up is both probable and a minimum estimate of associated costs can be made; adjustments to initial estimates are recorded as necessary. At December 31, 2000, the Terminals Companies' environmental reserve, included in other long-term liabilities, was $36,515,000. These reserves reflect the Terminals Companies' best estimate of the cost to remediate its environmental conditions. Additions to the reserve were $3,017,000 in 2000. Expenditures charged to the reserve amounted to $4,221,000 in 2000. USE OF ESTIMATES The preparation of financial statements in conformity with generally accepted accounting principles requires the Terminals Companies' management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, as well as revenues and expenses during the reporting period. Actual amounts when ultimately realized could differ from those estimates. REVENUE RECOGNITION The majority of the Terminals Companies' gross income is derived from the transportation, distribution and storage of petroleum products, as well as from the storage of chemical products. Revenue is recognized at the time of service or over the lease term. Management fees received from the Excluded Companies are recognized in the period the services were performed. 9 80 GATX Terminals Companies Notes to Combined Financial Statements December 31, 2000 5. DIVESTITURES In September 2000, the Terminals Companies sold its Paulsboro terminal for $11,981,000 in cash. Also in September 2000, the Terminals Companies sold its joint venture interest in Olympic Pipeline Company for $7,000,000 in cash. 6. TRANSACTIONS WITH PARENT COMPANY AND EXCLUDED COMPANIES Advances from parent represent advances with varying maturities and with fixed and floating interest rates subject to periodic adjustment, as described in Note 9. The amount in receivables from Excluded Companies represent notes receivable from and advances to various Excluded Companies consisting primarily of non-interest bearing notes with no stated maturity dates. For the year ended December 31, 2000, the combined statement of operations include expense allocations from GATX. These allocations represent expenses the Terminals Companies would otherwise have had to incur for itself and do not include any allocation of corporate expenses of GATX with are attributable to its operations as a holding company. 7. PENSION BENEFITS The Company contributes to pension plans sponsored by GATX which cover substantially all employees. Benefits under the plans are based on years of service and/or final average salary. The funding policy for all plans is based on an actuarially determined cost method allowable under Internal Revenue Service regulations. There were no contributions or refunds made with respect to trusteed plans established by GATX in which employees of the Company and its consolidated subsidiaries participated in 2000. Costs pertaining to the GATX plans are allocated to the Terminals Companies on the basis of payroll costs with respect to normal cost and on the basis of actuarial determination for prior service cost. Charges to income with respect to said plans were $1,118,000 in 2000. Components of pension costs, accumulated plan benefit information, and net plan assets for subsidiaries of GATX have not been determined on an individual company basis. At December 31, 2000, the pension liability recorded for the Terminals Companies was $9,206,000. 10 81 GATX Terminals Companies Notes to Combined Financial Statements December 31, 2000 8. POSTRETIREMENT BENEFITS OTHER THAN PENSIONS The Terminals Companies provides health care, life insurance and other benefits for certain retired employees who meet established criteria. Most domestic employees are eligible for health care and life insurance benefits if they retire from the Terminals Companies with immediate pension benefits under the GATX pension plan. The plans are either contributory or non-contributory, depending on various factors. Net periodic postretirement cost includes the following components:
YEAR ENDED DECEMBER 31 2000 ---------------------- Current service cost $ 335,000 Interest cost on accumulated postretirement benefit obligation 1,109,000 Unrecognized net gain (176,000) ------------------ Net periodic postretirement benefit cost $ 1,268,000 ================== Discount rate 7.50% ==================
The following table reconciles the benefit obligation to the amount recognized in the Terminal Companies combined balance sheet:
AS OF DECEMBER 31 2000 ----------------- Accumulated postretirement benefit obligation: Retirees $ 11,091,000 Fully eligible active plan participants 1,158,000 Other active plan participants 3,621,000 -------------- Total accumulated postretirement benefit obligation 15,870,000 Unrecognized loss (3,681,000) -------------- Accrued postretirement benefit liability $ 12,189,000 ==============
The accrued postretirement benefit liability was determined using an assumed discount rate of 7.50% for 2000. For measurement purposes, blended rates ranging from 5% increasing to 6% over the next year and remaining at that level thereafter, were used for the increase in the per capita cost of covered health care benefits. The health care cost trend rate assumption has a significant effect on the amount of the obligation and periodic cost reported. An increase in the assumed health care cost trend rates by 1% would increase the accumulated postretirement benefit obligation by $740,000 and would increase aggregate service and interest cost components of net periodic postretirement benefit cost by $60,000 per year. 11 82 GATX Terminals Companies Notes to Combined Financial Statements December 31, 2000 9. LONG-TERM DEBT AND ADVANCES FROM PARENT Long-term debt, including current maturities, consisted of the following:
AS OF INTEREST DECEMBER 31, RATE MATURITY 2000 -------- -------- ------------ Industrial revenue bonds 6.625%- 7.30% 2019-2024 $ 87,930,000 Term notes 7.84%- 10.07% 2001-2008 49,089,000 ------------ $137,019,000 ============
The industrial revenue bonds (IRBs) were issued by municipal authorities for the construction of terminal facilities. The Company has pledged collateral to cover the IRB's principal and interest payments. This collateral consists of several tanks at various Company locations. The Company is required to make payments sufficient to pay the interest and principal requirements under the indentures of trust covering the bond issues. Advances from parent consisted of the following:
AS OF DECEMBER 31, 2000 ---------------- Advances from GRC, 6.51% to 10.35% fixed rates maturing through May 1, 2009 $381,500,000 Advance from GRC, LIBOR plus 0.5% maturing at October 30, 2003 (7.26% at 2000) 50,000,000 Advance from GATX, interest rate adjusted monthly in accordance with actual short-term borrowing rates (6.53% in 2000) 30,447,000 Advance from GRC, LIBOR plus 0.45% maturing on October 1, 2001 (7.21% at 2000) 25,000,000 Advance from GRC, LIBOR plus 0.75% maturing on October 1, 2001 (7.40% at 2000) 25,000,000 ------------ $511,947,000 ============
Interest expense related to advances from parent was $41,769,000 in 2000. 12 83 GATX Terminals Companies Notes to Combined Financial Statements December 31, 2000 9. LONG-TERM DEBT AND ADVANCES FROM PARENT (CONTINUED) Aggregate maturities of long-term debt and advances from Parent for the years 2001 through 2005 are as follows:
ADVANCES YEAR LONG-TERM DEBT FROM PARENT ---- -------------- ----------- 2001 7,273,000 $108,500,000 2002 7,273,000 115,000,000 2003 7,273,000 80,500,000 2004 7,270,000 80,000,000 2005 5,000,000 7,500,000
Advances from Parent have been included with parent investment and advances on the combined balance sheet due to GATX's intent and ability to refinance such amounts. Interest costs capitalized as part of the cost of construction in progress was $173,000 in 2000. Total interest payments were $51,804,000 in 2000. 10. FAIR VALUE OF FINANCIAL INSTRUMENTS The following table presents the carrying amount and estimated fair value of the Terminals Companies' financial instruments that are recorded on the balance sheet. Generally accepted accounting principles define the fair value of a financial instrument as the amount at which the instrument could be exchanged in a current transaction between willing parties. Fair value was estimated by performing a discounted cash flow analysis using the term of the notes and market rates based on the Terminals Companies' current incremental borrowing rates for similar types of borrowing arrangements. Trade receivables, trade payables and short-term debt are carried at cost, which approximates fair value because of the short maturity of those instruments. Carrying value of notes receivable from Excluded Companies approximates fair value as notes are primarily non-interest bearing and have no stated maturity. 13 84 GATX Terminals Companies Notes to Combined Financial Statements December 31, 2000 10. FAIR VALUE OF FINANCIAL INSTRUMENTS (CONTINUED)
AS OF DECEMBER 31, 2000 ------------------------------- Carrying Fair Amount Value -------------- -------------- Fixed rate parent advances $ 381,500,000 $ 382,674,000 Variable rate parent advances 130,447,000 130,447,000 Fixed rate long-term debt 137,019,000 141,181,000
11. INCOME TAXES The Terminals Companies have been included in the consolidated U.S. federal income tax return of GATX. The provision for income taxes of the Terminals Companies have been prepared as if a separate U.S. federal income tax return had been prepared for such operations on a stand-alone basis. Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of the Terminals Companies deferred tax liabilities and assets were:
AT DECEMBER 31, 2000 -------------------- Deferred tax liabilities: Book/tax basis differences due to depreciation $ 120,416,000 State income tax 13,573,000 Investment tax credit 3,246,000 Other 20,349,000 -------------- Total deferred tax liabilities 157,584,000 Deferred tax assets: Alternative minimum tax credit 42,139,000 Environmental 12,780,000 Postretirement benefits other than pensions 4,312,000 -------------- Total deferred tax assets 59,231,000 -------------- Net deferred tax liabilities $ 98,353,000 ==============
14 85 GATX Terminals Companies Notes to Combined Financial Statements December 31, 2000 11. INCOME TAXES (CONTINUED) The provision for income taxes consists of the following:
YEAR ENDED DECEMBER 31, 2000 ----------------- Current: Federal $ (4,871,000) State and local 1,063,000 -------------- (3,808,000) Deferred: Federal 17,247,000 State and local 588,000 -------------- 17,835,000 Income tax expense $ 14,027,000 ============== Income taxes paid $ 6,383,000 ==============
The reasons for the difference between the Terminals Companies effective tax rate and the federal statutory income tax rate were:
YEAR ENDED DECEMBER 31, 2000 ----------------- Federal statutory income tax rate 35.0% Add (deduct) effect of: State income taxes, net of federal benefit 2.7 Investment tax credits (2.6) Other (0.2) ---------- Effective income tax rate 34.9% ==========
15 86 GATX Terminals Companies Notes to Combined Financial Statements December 31, 2000 12. LEASES Future minimum lease receipts, by year and in the aggregate, for services provided from noncancelable operating leases by year consisted of the following at December 31, 2000: 2001 $ 129,824,000 2002 77,791,000 2003 63,406,000 2004 58,714,000 2005 44,753,000 Years thereafter 212,433,000 -------------- Total minimum lease receipts $ 586,921,000 ==============
Future minimum payments, by year and in the aggregate, under noncancelable operating leases for land and terminal facilities expiring through the year 2022, consisted of the following at December 31, 2000: 2001 $ 1,954,000 2002 1,958,000 2003 1,782,000 2004 1,787,000 2005 1,679,000 Years thereafter 8,602,000 -------------- Total minimum lease payments $17,762,000 ==============
Total rent expense amounted to $4,060,000 in 2000. 13. OTHER ASSETS At December 31, 2000, other assets consisted of the following: Right of ways, net $ 20,831,000 Goodwill 9,800,000 Investment in real estate 3,192,000 Other 2,996,000 ------------ Total other assets $ 36,819,000 ============
16 87 GATX Terminals Companies Notes to Combined Financial Statements December 31, 2000 14. COMMITMENTS, CONTINGENCIES AND CONCENTRATIONS OF CREDIT RISK The Terminals Companies' revenues are generated from the handling or transportation of products for the chemical and petroleum industries. Customer credit is extended based on an evaluation of the customer's financial condition, and generally, collateral is not required. Credit losses are provided for in the financial statements and consistently have been within management's expectations. At December 31, 2000, the Terminals Companies had commitments of $14,631,000 to upgrade and repair terminal and pipeline facilities. The Terminals Companies is engaged in various matters of litigation and has a number of unresolved claims pending including proceedings under governmental laws and regulations related to environmental matters. Although, the ultimate liability with respect to such litigation and claims can not be determined at this time, it is the opinion of management that damages, if any, required to be paid by the company in the discharge of such liability are not likely to be material to the Terminals Companies financial position or results of operations. 17 88 EXHIBIT 99.6 KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS The unaudited pro forma combined financial statements of Kinder Morgan Energy Partners, L.P. and Subsidiaries (KMP) have been derived from the historical balance sheets and income statements of KMP and GATX Terminals Companies as of December 31, 2000 and for the year then ended. The unaudited pro forma combined financial statements have been prepared to give effect to the pending acquisition of the United States terminals and pipeline operations of GATX Terminals Companies for $983.8 million in cash plus assumed liabilities using the purchase method of accounting. This amount is subject to a working capital and debt adjustment based on a closing balance sheet to be provided on consummation of the acquisition. The acquisition is expected to be consummated in the first quarter of 2001. The unaudited pro forma combined financial statements have been prepared assuming the acquisition had been consummated on January 1, 2000. The purchase price allocated in the unaudited pro forma combined financial statements is based on management's preliminary estimate of the fair market values of assets to be acquired and liabilities to be assumed and is subject to adjustment. The unaudited pro forma combined financial statements include assumptions and adjustments as described in the accompanying notes and should be read in conjunction with the historical financial statements and related notes of KMP and GATX Terminals Companies incorporated herein. The unaudited pro forma combined financial statements may not be indicative of the results that would have occurred if the acquisition had been consummated on the date indicated or which will be obtained in the future. -1- 89 Kinder Morgan Energy Partners, L.P. and Subsidiaries Unaudited Pro Forma Combined Statement of Income
Year Ended December 31, 2000 -------------------------------- GATX Terminals KMP Companies Pro Forma Pro Forma Historical Historical Adjustments Combined ------------- ------------- ------------- ------------- Revenues $ 816,442 $ 262,614 $ (2,574)(f) $ 1,075,632 (850)(g) Costs and Expenses Cost of products sold 124,641 -- -- 124,641 Operations and maintenance 164,379 99,867 (1,121)(h) 263,125 Fuel and power 43,216 -- -- 43,216 Depreciation and amortization 82,630 39,631 (12,678)(i) 109,583 General and administrative 60,065 32,929 (1,266)(j) 91,728 Taxes, other than income taxes 25,950 -- -- 25,950 ------------- ------------- ------------- ------------- 500,881 172,427 (15,065) 658,243 Operating Income 315,561 90,187 11,641 417,389 Other Income (Expense) Earnings from equity investments 71,603 (2,361) 2,361(k) 71,603 Amortization of excess cost of investments (8,195) -- -- (8,195) Interest, net (93,284) (49,928) 41,769(l) (175,506) (72,070)(m) (1,993)(n) Other, net 14,584 -- -- 14,584 Gain on sale of assets -- 2,255 (2,255)(o) -- Minority Interest (7,987) -- (198)(p) (8,185) ------------- ------------- ------------- ------------- Income Before Income Taxes 292,282 40,153 (20,745) 311,690 Income Tax Benefit (Expense) (13,934) (14,027) 14,027(q) (13,934) ------------- ------------- ------------- ------------- Net Income $ 278,348 $ 26,126 $ (6,718) $ 297,756 ============= ============= ============= ============= General partner's interest in net income $ 109,470 12,612(r) $ 122,082 Limited partners' interest in net income 168,878 6,796(r) 175,674 ------------- ------------- ------------- Net income $ 278,348 19,408 $ 297,756 ============= ============= ============= Basic limited partners' net income per unit $ 2.68 $ 2.78 ============= ============= Number of Units used in Computation 63,106 63,106 ============= ============= Diluted limited partners' net income per unit $ 2.67 $ 2.78 ============= ============= Number of units used in computation 63,150 63,150 ============= =============
The accompanying notes are an integral part of these unaudited pro forma condensed financial statements. -2- 90 Kinder Morgan Energy Partners, L.P. and Subsidiaries Unaudited Pro Forma Combined Balance Sheet
As of December 31, 2000 --------------------------------- GATX Terminals KMP Companies Pro Forma Pro Forma Historical Historical Adjustments Combined --------------- --------------- --------------- --------------- ASSETS Current Assets Cash and cash equivalents $ 59,319 $ 379 $ (379)(a) $ 59,319 Accounts and notes receivable Trade 345,065 31,323 (130)(a) 376,258 Related parties 3,384 -- -- 3,384 Inventories Products 24,137 -- -- 24,137 Materials and supplies 4,972 -- -- 4,972 Gas imbalances 26,878 -- -- 26,878 Gas in underground storage 27,481 -- -- 27,481 Other current assets 20,025 1,256 (1)(a) 21,280 --------------- --------------- --------------- --------------- 511,261 32,958 (510) 543,709 --------------- --------------- --------------- --------------- Property, Plant and Equipment, net 3,306,305 659,304 468,209 (b) 4,433,818 Investments 417,045 -- -- 417,045 Notes receivable 9,101 -- -- 9,101 Receivables from excluded companies -- 125,261 (125,261)(a) -- Intangibles, net 345,305 9,800 (9,800)(c) 358,922 13,617 (c) Deferred charges and other assets 36,193 27,019 (1,498)(a) 61,714 --------------- --------------- --------------- --------------- TOTAL ASSETS $ 4,625,210 $ 854,342 $ 344,757 $ 5,824,309 =============== =============== =============== =============== LIABILITIES AND PARTNERS' CAPITAL Current Liabilities Accounts payable Trade $ 293,268 $ 5,792 $ (3,559)(a) 295,501 Related parties 8,255 -- -- 8,255 Current portion of long-term debt 648,949 7,273 983,754 (d) 1,639,976 Accrued rate refunds 1,100 -- -- 1,100 Gas imbalances 48,834 -- -- 48,834 Deferred revenue 43,978 -- -- 43,978 Accrued other liabilities 54,572 30,699 680 (a) 85,951 --------------- --------------- --------------- --------------- 1,098,956 43,764 980,875 2,123,595 --------------- --------------- --------------- --------------- Long-term Liabilities and Deferred Credits Long-term debt 1,255,453 129,746 -- 1,385,199 Deferred revenue 1,503 -- -- 1,503 Deferred income taxes -- 98,353 (98,353)(a) -- Other 94,062 66,690 (21,976)(a) 138,776 --------------- --------------- --------------- --------------- 1,351,018 294,789 (120,329) 1,525,478 --------------- --------------- --------------- --------------- Minority interest 58,169 -- -- 58,169 --------------- --------------- --------------- --------------- Parent investment and advances -- 515,789 (515,789)(e) -- Partners' Capital Common Units 1,957,357 -- -- 1,957,357 Class B Units 125,961 -- -- 125,961 General Partner 33,749 -- -- 33,749 --------------- --------------- --------------- --------------- 2,117,067 515,789 (515,789) 2,117,067 --------------- --------------- --------------- --------------- TOTAL LIABILITIES AND PARTNERS' CAPITAL $ 4,625,210 $ 854,342 $ 344,757 $ 5,824,309 =============== =============== =============== ===============
The accompanying notes are an integral part of these unaudited pro forma condensed financial statements. -3- 91 NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS BASIS OF PRESENTATION The following described pro forma adjustments give recognition to the pending acquisition of the U.S. terminals and pipeline operations of GATX Terminals Companies for $983.8 million in cash plus assumed liabilities. a) Reflects the elimination of excluded assets and liabilities of GATX Terminals Companies which are not acquired or assumed in this pending acquisition pursuant to the Stock Purchase Agreement. Excluded assets generally consist of cash balances, capitalized financing costs, receivables from foreign subsidiaries and income tax refunds. Excluded liabilities generally consist of cash deficits, income taxes payable and retired employee benefit accruals. b) Reflects the preliminary allocation of the purchase price in excess of the net assets to be acquired to estimated fair value of property, plant and equipment and goodwill utilizing the purchase method of accounting for the acquisition as of December 31, 2000. The purchase price allocation is subject to revision. The purchase price in excess of net assets to be acquired and the preliminary allocation is: Purchase price $ 983,754 GATX Terminals Companies net assets of $515,789, less excluded net assets of $4,064 511,725 ---------- Excess of purchase price over net assets to be acquired $ 472,029 ========== Preliminary allocation: Property, plant and equipment $ 468,212 Goodwill 3,817 ---------- $ 472,029 ==========
c) To eliminate GATX historical goodwill and include fair value of goodwill reflected by preliminary allocation of the purchase price. d) Reflects borrowing of the purchase amount at an assumed rate of approximately 7.3% on a loan facility to be arranged by KMP's investment advisors. KMP has obtained a commitment letter for a floating rate credit facility with a consortium of banks. A .125% change in the assumed rate would increase or decrease interest expense by approximately $1.2 million. e) Reflects elimination of GATX Terminals Companies parent investment and advances. f) To eliminate operating revenue of GATX terminal sold in September 2000. g) To eliminate management fees earned from excluded foreign and domestic joint ventures. h) To eliminate operating expenses of GATX terminal sold in September 2000. i) To adjust depreciation expense for the preliminary allocation of purchase price using an estimated remaining useful life of 40 years. The actual range of useful lives may vary from this estimate. j) To eliminate costs attributable solely to excluded foreign operations. k) To eliminate loss from GATX equity investee sold in September 2000. -4- 92 l) To eliminate interest expense incurred on debt with affiliated companies. Such debt is an excluded liability and is classified within parent investment and advances on the historical balance sheet of GATX Terminals Companies as of December 31, 2000. m) To record interest expense on the purchase amount borrowed by KMP at an assumed rate of approximately 7.3%. n) To eliminate GATX interest income earned on receivables from excluded companies. o) To eliminate gain on GATX assets sold during 2000. p) To adjust minority interest expense for an allocation of increased net income attributable to this acquisition. q) To eliminate GATX corporate income tax. r) Gives effect to the allocation of pro forma net income to the general partner and the limited partners pursuant to sharing ratios provided in the KMP partnership agreement. Amounts are calculated giving consideration to cash available for distribution based on the pro forma combined financial statements. The general partner's interest in net income includes incentive distributions the general partner would have received based on total distributions. -5- -----END PRIVACY-ENHANCED MESSAGE-----