UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2004
or
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from _____to_____
Delaware |
76-0669886 |
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(State or other jurisdiction of incorporation or organization) |
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(I.R.S. Employer Identification No.) |
500 Dallas Street, Suite 1000, Houston, Texas 77002 |
(Address of principal executive offices, including zip code) |
Registrant's telephone number, including area code (713) 369-9000
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Name of each exchange |
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Shares Representing Limited Liability Company Interests |
New York Stock Exchange |
None |
(Title of class) |
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
xIndicate by check mark whether the registrant is an accelerated filer
(as defined in Exchange Act Rule 12b-2):
Yes
The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant was $1,390,062,824 as of June 30, 2004.
The number of shares outstanding for each of the registrant's classes of common equity, as of February 3, 2005 was approximately two voting shares and 54,157,639 listed shares.
KINDER MORGAN MANAGEMENT, LLC AND SUBSIDIARY
CONTENTS
Kinder Morgan Energy Partners, L.P. Annual Report on Form 10-K for the year ended December 31, 2004 | Annex A |
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Note: Individual financial statements of the parent company are omitted pursuant to the provisions of Accounting Series Release No. 302.
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Items 1 and 2. Business and Properties.
In this report, unless the context requires otherwise, references to "we," "us," "our," or the "Company" are intended to mean Kinder Morgan Management, LLC and its consolidated subsidiary. Our shares representing limited liability company interests are traded on the New York Stock Exchange under the symbol "KMR". Our executive offices are located at 500 Dallas Street, Suite 1000, Houston, Texas 77002 and our telephone number is (713) 369-9000.
We are a publicly traded Delaware limited liability company that was formed on February 14, 2001. We are a limited partner in Kinder Morgan Energy Partners, L.P., and manage and control its business and affairs pursuant to a delegation of control agreement. Pursuant to this delegation of control agreement among Kinder Morgan G.P., Inc., Kinder Morgan Energy Partners, L.P., Kinder Morgan Energy Partners, L.P.'s operating partnerships and us:
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Kinder Morgan G.P., Inc., as general partner of Kinder Morgan Energy Partners, L.P., delegated to us, to the fullest extent permitted under Delaware law and the Kinder Morgan Energy Partners, L.P. partnership agreement, and we assumed, all of Kinder Morgan G.P., Inc.'s power and authority to manage and control the business and affairs of Kinder Morgan Energy Partners, L.P. and Kinder Morgan Energy Partners, L.P.'s operating partnerships; and |
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We have agreed that we will not take any of the following actions without the approval of Kinder Morgan G.P., Inc.: |
-- |
amend or propose an amendment to the Kinder Morgan Energy Partners, L.P. partnership agreement, |
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-- |
change the amount of the distribution made on the Kinder Morgan Energy Partners, L.P. common units, |
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-- |
allow a merger or consolidation involving Kinder Morgan Energy Partners, L.P., |
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allow a sale or exchange of all or substantially all of the assets of Kinder Morgan Energy Partners, L.P., |
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dissolve or liquidate Kinder Morgan Energy Partners, L.P., |
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take any action requiring unitholder approval, |
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call any meetings of the Kinder Morgan Energy Partners, L.P. common unitholders, |
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take any action that, under the terms of the partnership agreement of Kinder Morgan Energy Partners, L.P., must or should receive a special approval of the conflicts and audit committee of Kinder Morgan G.P., Inc., |
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take any action that, under the terms of the partnership agreement of Kinder Morgan Energy Partners, L.P., cannot be taken by the general partner without the approval of all outstanding units, |
3
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settle or compromise any claim or action directly against or otherwise relating to indemnification of our or the general partner's (and respective affiliates) officers, directors, managers or members or relating to our structure or securities, |
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-- |
settle or compromise any claim or action relating to the i-units, which are a separate class of Kinder Morgan Energy Partners, L.P.'s limited partnership interests, our shares or any offering of our shares, |
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-- |
settle or compromise any claim or action involving tax matters, |
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allow Kinder Morgan Energy Partners, L.P. to incur indebtedness if the aggregate amount of its indebtedness then exceeds 50% of the market value of the then outstanding units of Kinder Morgan Energy Partners, L.P., or |
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allow Kinder Morgan Energy Partners, L.P. to issue units in one transaction, or in a series of related transactions, having a market value in excess of 20% of the market value of then outstanding units of Kinder Morgan Energy Partners, L.P. |
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Kinder Morgan G.P., Inc.: |
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is not relieved of any responsibilities or obligations to Kinder Morgan Energy Partners, L.P. or its unitholders as a result of such delegation, |
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owns, or one of its affiliates owns, all of our voting shares, and | |
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will not withdraw as general partner of Kinder Morgan Energy Partners, L.P. or transfer to a non-affiliate all of its interest as general partner, unless approved by both the holders of a majority of each of the i-units and the holders of a majority of all units voting as a single class, excluding common units and Class B units held by Kinder Morgan G.P., Inc. and its affiliates and excluding the number of i-units corresponding to the number of our shares owned by Kinder Morgan G.P., Inc. and its affiliates. |
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Kinder Morgan Energy Partners, L.P. has agreed to: |
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recognize the delegation of rights and powers to us, | |
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indemnify and protect us and our officers and directors to the same extent as it does with respect to Kinder Morgan G.P., Inc. as general partner, and |
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reimburse our expenses to the same extent as it does with respect to Kinder Morgan G.P., Inc. as general partner. |
These agreements will continue until either Kinder Morgan G.P., Inc. has withdrawn or been removed as the general partner of Kinder Morgan Energy Partners, L.P. or all of our shares are owned by Kinder Morgan, Inc. and its affiliates. The partnership agreement of Kinder Morgan Energy Partners, L.P. reflects these agreements. These agreements also apply to the operating partnerships of Kinder Morgan Energy Partners, L.P. and their partnership agreements.
Kinder Morgan G.P., Inc. remains the only general partner of Kinder Morgan Energy Partners, L.P. and all of its operating partnerships. Kinder Morgan G.P., Inc. will retain all of its general partner interests and shares in the profits, losses and distributions from all of these partnerships.
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The withdrawal or removal of Kinder Morgan G.P., Inc. as general partner of Kinder Morgan Energy Partners, L.P. will simultaneously result in the termination of our power and authority to manage and control the business and affairs of Kinder Morgan Energy Partners, L.P. Similarly, if Kinder Morgan G.P., Inc.'s power and authority as general partner are modified in the partnership agreement of Kinder Morgan Energy Partners, L.P., then the power and authority delegated to us will be modified on the same basis. The delegation of control agreement can be amended by all parties to the agreement, but on any amendment that would reduce the time for any notice to which owners of our shares are entitled or would have a material adverse effect on our shares, as determined by our board of directors in its discretion, the approval of the owners of a majority of the shares, excluding shares owned by Kinder Morgan, Inc. and its affiliates, is required.
Through our ownership of i-units, we are a limited partner in Kinder Morgan Energy Partners, L.P. We do not expect to have any cash flow attributable to our ownership of the i-units, but we expect that we will receive quarterly distributions of additional i-units from Kinder Morgan Energy Partners, L.P. The number of additional i-units we receive will be based on the amount of cash to be distributed by Kinder Morgan Energy Partners, L.P. to an owner of a common unit. The amount of cash distributed by Kinder Morgan Energy Partners, L.P. to its owners of common units is dependent on the operations of Kinder Morgan Energy Partners, L.P. and its operating limited partnerships and subsidiaries, and will be determined in accordance with its partnership agreement.
We have elected to be treated as a corporation for federal income tax purposes. Because we are treated as a corporation for federal income tax purposes, an owner of our shares will not report on its federal income tax return any of our items of income, gain, loss and deduction relating to an investment in us.
We are subject to federal income tax on our taxable income; however, the i-units owned by us generally are not entitled to allocations of income, gain, loss or deduction of Kinder Morgan Energy Partners, L.P. until such time as there is a liquidation of Kinder Morgan Energy Partners, L.P. Therefore, we do not anticipate that we will have material amounts of taxable income resulting from our ownership of the i-units unless we enter into a sale or exchange of the i-units or Kinder Morgan Energy Partners, L.P. is liquidated.
We have no properties. Our assets consist of a small amount of working capital and the i-units that we own.
We have no employees. For more information, see Note 4 of the accompanying Notes to Consolidated Financial Statements and Kinder Morgan Energy Partners, L.P.'s report on Form 10-K for the year ended December 31, 2004.
We make available free of charge on or through our Internet website, at http://www.kindermorgan.com, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission.
Item 3. Legal Proceedings.
We are not a party to any litigation.
Item 4. Submission of Matters to a Vote of Security Holders.
There were no matters submitted to a vote of our shareholders during the fourth quarter of 2004.
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Item 5. Market for Registrant's Common
Equity, Related Stockholder Matters and Issuer Purchases
of
Equity Securities.
Our shares are listed for trading on the New York Stock Exchange under the symbol "KMR." The per share high and low sale prices of our shares, as reported on the New York Stock Exchange, by quarter for the last two years are provided below.
Market Price Per Share |
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2004 |
2003 |
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Low |
High |
Low |
High |
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Quarter Ended: | |||||||
March 31 | $39.72 |
$44.50 |
$30.00 |
$34.09 |
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June 30 | $34.25 |
$42.86 |
$32.01 |
$37.55 |
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September 30 | $36.25 |
$41.52 |
$36.26 |
$38.57 |
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December 31 | $39.28 |
$42.39 |
$37.45 |
$43.65 |
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There were approximately 18,000 holders of our listed shares as of February 3, 2005, which includes individual participants in security position listings.
Under the terms of our limited liability company agreement, except in connection with our liquidation, we do not pay distributions on our shares in cash but we make distributions on our shares in additional shares or fractions of shares. At the same time Kinder Morgan Energy Partners, L.P. makes a distribution on its common units and i-units, we distribute on each of our shares that fraction of a share determined by dividing the amount of the cash distribution to be made by Kinder Morgan Energy Partners, L.P. on each common unit by the average market price of a share determined for the ten-trading day period ending on the trading day immediately prior to the ex-dividend date for our shares.
Share Distributions |
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Shares Distributed Per Outstanding Share |
Equivalent Distribution Value Per Share1 |
Total Number of Additional Shares Distributed |
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Quarter Ended: | 2004 |
2003 |
2004 |
2003 |
2004 |
2003 |
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March 31 | 0.017412 |
0.018488 |
$ 0.69 |
$ 0.64 |
872,958 |
859,933 |
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June 30 | 0.018039 |
0.017138 |
$ 0.71 |
$ 0.65 |
920,140 |
811,878 |
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September 30 | 0.017892 |
0.016844 |
$ 0.73 |
$ 0.66 |
929,105 |
811,625 |
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December 31 | 0.017651 |
0.015885 |
$ 0.74 |
$ 0.68 |
955,936 |
778,309 |
______________ | |
1 |
This is the cash distribution paid or payable to each common unit of Kinder Morgan Energy Partners, L.P. for the quarter indicated and is used to calculate our distribution of shares as discussed above. Because of this calculation, the market value of the shares distributed on the date of distribution may be less or more than the cash distribution per common unit of Kinder Morgan Energy Partners, L.P. |
There were no sales of unregistered equity securities during the periods covered by this report. We did not repurchase any shares during the fourth quarter of 2004.
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Item 6. Selected Financial Data.
KINDER MORGAN MANAGEMENT, LLC AND SUBSIDIARY
Year Ended December 31, |
February 14, 2001 (Inception) Through |
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2004 |
2003 |
2002 |
2001 |
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(In thousands except per share amounts) |
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Equity in Earnings of Kinder Morgan Energy Partners, L.P. |
$ 113,482 |
$ 94,775 |
$ 72,199 |
$ 28,354 |
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Provision for Income Taxes | 38,360 |
36,014 |
26,865 |
11,342 |
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Net Income | $ 75,122 |
$ 58,761 |
$ 45,334 |
$ 17,012 |
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Earnings Per Share, Basic and Diluted | $ 1.47 |
$ 1.24 |
$ 1.23 |
$ 0.78 |
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Number of Shares Used in Computing | |||||||
Basic and Diluted Earnings Per Share | 51,181 |
47,372 |
36,790 |
21,756 |
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Equivalent Distribution Value Per Share1 | $ 2.870 |
$ 2.630 |
$ 2.435 |
$ 1.625 |
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Total Number of Additional Shares Distributed | 3,678 |
3,262 |
2,944 |
1,340 |
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Total Assets at End of Period | $1,639,348 |
$1,506,286 |
$1,439,190 |
$1,034,824 |
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1 | This is the amount of cash distributions payable to each common unit of Kinder Morgan Energy Partners, L.P. for each period shown. Under the terms of our limited liability company agreement, except in connection with our liquidation, we do not pay distributions on our shares in cash but we make distributions on our shares in additional shares or fractions of shares. At the same time Kinder Morgan Energy Partners, L.P. makes a distribution on its common units and i-units, we distribute on each of our shares that fraction of a share determined by dividing the amount of the cash distribution to be made by Kinder Morgan Energy Partners, L.P. on each common unit by the average market price of a share determined for a ten-trading day period ending on the trading day immediately prior to the ex-dividend date for our shares. Because of this calculation, the market value of the shares distributed on the date of distribution may be less or more than the cash distribution per common unit of Kinder Morgan Energy Partners, L.P. |
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
General
We are a publicly traded Delaware limited liability company, formed on February 14, 2001, that has elected to be treated as a corporation for federal income tax purposes. Our voting shares are owned by Kinder Morgan, G.P., Inc., an indirect wholly owned subsidiary of Kinder Morgan, Inc. and the general partner of Kinder Morgan Energy Partners, L.P. Kinder Morgan, Inc. is one of the largest energy storage and transportation companies in the United States, operating, either for itself or on behalf of Kinder Morgan Energy Partners, L.P., over 35,000 miles of natural gas and refined petroleum products pipelines and approximately 135 terminals. Kinder Morgan Energy Partners, L.P. is one of the largest publicly traded pipeline limited partnerships in the United States in terms of market capitalization and the owner and operator of the largest independent refined petroleum products pipeline system in the United States in terms of volumes delivered. Kinder Morgan Energy Partners, L.P. owns and/or operates a diverse group of assets used in the transportation, storage and processing of energy products, including refined petroleum products pipeline systems with more than 10,000 miles of products pipeline and 60 associated terminals. Kinder Morgan Energy Partners, L.P. owns approximately 14,000 miles of natural gas transportation pipelines, plus natural gas gathering and storage facilities. Kinder Morgan Energy Partners, L.P. also owns or operates approximately 75 liquid and bulk terminal facilities and more than 55 rail transloading facilities located throughout the United States, handling approximately 68 million tons of coal, petroleum coke and other dry-bulk materials annually and having a liquids storage capacity of approximately 37 million barrels for refined petroleum products, chemicals and other liquid products. In addition, Kinder Morgan Energy Partners, L.P. owns Kinder Morgan CO2 Company, L.P., which transports, markets and produces carbon dioxide for use in enhanced oil recovery operations and owns
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interests in and/or operates six oil fields in West Texas, all of which are using or have used carbon dioxide injection operations. Kinder Morgan CO2 Company, L.P. also owns and operates the Wink Pipeline, a crude oil pipeline in West Texas.
We are a limited partner in Kinder Morgan Energy Partners, L.P., and manage and control its business and affairs pursuant to a delegation of control agreement. Our success is dependent upon our operation and management of Kinder Morgan Energy Partners, L.P. and its resulting performance. Therefore, we have attached as Annex A hereto Kinder Morgan Energy Partners, L.P.'s 2004 Annual Report on Form 10-K. The following discussion should be read in conjunction with the accompanying financial statements and related notes.
Business
Kinder Morgan G.P., Inc. has delegated to us, to the fullest extent permitted under Delaware law and Kinder Morgan Energy Partners, L.P.'s limited partnership agreement, all of its rights and powers to manage and control the business and affairs of Kinder Morgan Energy Partners, L.P. subject to Kinder Morgan G.P., Inc.'s right to approve specified actions.
Results of Operations
Our results of operations consist of the offsetting expenses and revenues associated with our managing and controlling the business and affairs of Kinder Morgan Energy Partners, L.P. and our equity in the earnings of Kinder Morgan Energy Partners, L.P. attributable to the i-units we own. At December 31, 2004, through our ownership of i-units, we owned approximately 26.2% of all of Kinder Morgan Energy Partners, L.P.'s outstanding limited partner interests. We use the equity method of accounting for our investment in Kinder Morgan Energy Partners, L.P. and, therefore, we record earnings equal to approximately 26.2% of Kinder Morgan Energy Partners, L.P.'s limited partners' net income. Our percentage ownership in Kinder Morgan Energy Partners, L.P. will change over time upon the distribution of additional i-units to us or upon issuances of additional common units or other equity securities by Kinder Morgan Energy Partners, L.P.
For the years ended December 31, 2004, 2003 and 2002, Kinder Morgan Energy Partners, L.P. reported limited partners' net income of $436.5 million, $370.8 million and $337.6 million, respectively. Our net income for the corresponding periods was $75.1 million, $58.8 million and $45.3 million, respectively. The reported segment earnings contribution by business segment for Kinder Morgan Energy Partners, L.P. is set forth below. This information should be read in conjunction with Kinder Morgan Energy Partners, L.P.'s 2004 Annual Report on Form 10-K, which is attached hereto as Annex A.
Kinder Morgan Energy Partners, L.P.
Year Ended December 31, |
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2004 |
2003 |
2002 |
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(In thousands) |
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Segment Earnings Contribution: | |||||
Product Pipelines | $ 370,321 |
$ 370,974 |
$ 343,935 |
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Natural Gas Pipelines | 364,872 |
319,288 |
276,766 |
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CO2 | 234,258 |
140,755 |
100,983 |
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Terminals | 238,848 |
203,701 |
194,917 |
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Total Segment Earnings | 1,208,299 |
1,034,718 |
916,601 |
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Interest and Corporate Administrative Expenses1 | (376,721) |
(337,381) |
(308,224) |
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Net Income | $ 831,578 |
$ 697,337 |
$ 608,377 |
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========= |
1 | Includes interest and debt expense, general and administrative expenses, minority interest expense and other insignificant items. |
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Our earnings, as reported in the accompanying Consolidated Statements of Income, represent equity in earnings of Kinder Morgan Energy Partners, L.P. attributable to the i-units that we own, reduced by a deferred income tax provision. The deferred income tax provision is calculated based on the book/tax basis difference created by our recognition, under accounting principles generally accepted in the United States of America, of our share of the earnings of Kinder Morgan Energy Partners, L.P. Our earnings per share (both basic and diluted) is our net income divided by our weighted-average number of outstanding shares during the periods presented. There are no securities outstanding that may be converted into or exercised for shares.
Income Taxes
We are a limited liability company that has elected to be treated as a corporation for federal income tax purposes. Deferred income tax assets and liabilities are recognized for temporary differences between the basis of our 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. Currently, our only such temporary difference results from recognition of the increased investment associated with recording our equity in the earnings of Kinder Morgan Energy Partners, L.P. The effective tax rate used in computing our income tax provision was 33.8% for 2004, 38% for 2003 and 37.2% for 2002. The effective tax rate for 2004 and 2002 was reduced by 2.5% and 0.8%, respectively, due to a reduction in the state tax rate on our cumulative deferred tax liability.
We are a party to a tax indemnification agreement with Kinder Morgan, Inc. Pursuant to this tax indemnification agreement, Kinder Morgan, Inc. agreed to indemnify us for any tax liability attributable to our formation or our management and control of the business and affairs of Kinder Morgan Energy Partners, L.P., and for any taxes arising out of a transaction involving the i-units we own to the extent the transaction does not generate sufficient cash to pay our taxes with respect to such transaction.
Liquidity and Capital Resources
Our authorized capital structure consists of two classes of interests: (1) our listed shares and (2) our voting shares, collectively referred to in this document as our "shares." Additional classes of interests may be approved by our board and holders of a majority of our shares, excluding shares held by Kinder Morgan, Inc. and its affiliates. Our only off-balance sheet arrangement is our equity investment in Kinder Morgan Energy Partners, L.P.
The number of our shares outstanding will at all times equal the number of i-units of Kinder Morgan Energy Partners, L.P. we own. Under the terms of our limited liability company agreement, except in connection with our liquidation, we do not pay distributions on our shares in cash but we make distributions on our shares in additional shares or fractions of shares. At the same time Kinder Morgan Energy Partners, L.P. makes a distribution on its common units and i-units, we distribute on each of our shares that fraction of a share determined by dividing the amount of the cash distribution to be made by Kinder Morgan Energy Partners, L.P. on each common unit by the average market price of a share determined for a ten-trading day period ending on the trading day immediately prior to the ex-dividend date for our shares.
On February 14, 2005, we paid a share distribution of 0.017651 shares per outstanding share (955,936 total shares) to shareholders of record as of January 31, 2005, based on the $0.74 per common unit distribution declared by Kinder Morgan Energy Partners, L.P. This distribution is paid in the form of additional shares or fractions thereof based on the average market price of a share determined for a ten-trading day period ending on the trading day immediately prior to the ex-dividend date for our shares.
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We expect that our expenditures associated with managing and controlling the business and affairs of Kinder Morgan Energy Partners, L.P. and the reimbursement for these expenditures received by us from Kinder Morgan Energy Partners, L.P. will continue to be equal. As stated above, the distributions we expect to receive on the i-units we own will be in the form of additional i-units. Therefore, we expect neither to generate nor to require significant amounts of cash in ongoing operations. We currently have no debt and have no plans to incur any debt. Any cash received from the sale of additional shares will immediately be used to purchase additional i-units. Accordingly, we do not anticipate any other sources or needs for additional liquidity.
Recent Accounting Pronouncements
Refer to Note 6 of the accompanying Consolidated Financial Statements for information regarding recent accounting pronouncements.
Risk Factors of our Business
Our success is dependent upon our operation and management of Kinder Morgan Energy Partners, L.P. and its resulting performance. We are a limited partner in Kinder Morgan Energy Partners, L.P. In the event that Kinder Morgan Energy Partners, L.P. decreases its cash distributions to its common unitholders, distributions of i-units on the i-units that we own will decrease correspondingly, and distributions of additional shares to owners of our shares will decrease as well. The risk factors that affect Kinder Morgan Energy Partners, L.P. also affect us; see "Risk Factors" for Kinder Morgan Energy Partners, L.P. included in Annex A.
The value of the quarterly per-share distribution of an additional fractional share may be less than the cash distribution on a common unit of Kinder Morgan Energy Partners, L.P. The fraction of a Kinder Morgan Management, LLC share to be issued in distributions per share outstanding will be based on the average closing price of the shares for the ten consecutive trading days preceding the ex-dividend date. Because the market price of our shares may vary substantially over time, the market value of our shares on the date a shareholder receives a distribution of additional shares may vary substantially from the cash the shareholder would have received had the shareholder owned common units instead of shares.
Kinder Morgan Energy Partners, L.P. could be treated as a corporation for United States federal income tax purposes. The treatment of Kinder Morgan Energy Partners, L.P. as a corporation would substantially reduce the cash distributions on the common units and the value of i-units that Kinder Morgan Energy Partners, L.P. will distribute quarterly to us and the value of our shares that we will distribute quarterly to our shareholders. The anticipated benefit of an investment in our shares depends largely on the treatment of Kinder Morgan Energy Partners, L.P. as a partnership for United States federal income tax purposes. Kinder Morgan Energy Partners, L.P. has not requested, and does not plan to request, a ruling from the Internal Revenue Service on this or any other matter affecting Kinder Morgan Energy Partners, L.P. Current law requires Kinder Morgan Energy Partners, L.P. to derive at least 90% of its annual gross income from specific activities to continue to be treated as a partnership for United States federal income tax purposes. Kinder Morgan Energy Partners, L.P. may not find it possible, regardless of its efforts, to meet this income requirement or may inadvertently fail to meet this income requirement. Current law may change so as to cause Kinder Morgan Energy Partners, L.P. to be treated as a corporation for United States federal income tax purposes without regard to its sources of income or otherwise subject Kinder Morgan Energy Partners, L.P. to entity-level taxation.
If Kinder Morgan Energy Partners, L.P. were to be treated as a corporation for United States federal income tax purposes, it would pay United States federal income tax on its income at the corporate tax
10
rate, which is currently a maximum of 35%, and would pay state income taxes at varying rates. Distributions to us of additional i-units would generally be taxed as a corporate distribution. Because a tax would be imposed upon Kinder Morgan Energy Partners, L.P. as a corporation, the cash available for distribution to a common unitholder would be substantially reduced, which would reduce the values of i-units distributed quarterly to us and our shares distributed quarterly to our shareholders. Treatment of Kinder Morgan Energy Partners, L.P. as a corporation would cause a substantial reduction in the value of our shares.
As an owner of i-units, we may not receive value equivalent to the common unit value for our i-unit interest in Kinder Morgan Energy Partners, L.P. if Kinder Morgan Energy Partners, L.P. is liquidated. As a result, a shareholder may receive less per share in our liquidation than is received by an owner of a common unit in a liquidation of Kinder Morgan Energy Partners, L.P. If Kinder Morgan Energy Partners, L.P. is liquidated and Kinder Morgan, Inc. does not satisfy its obligation to purchase your shares, which is triggered by a liquidation, then the value of your shares will depend on the after-tax amount of the liquidating distribution received by us as the owner of i-units. The terms of the i-units provide that no allocations of income, gain, loss or deduction will be made in respect of the i-units until such time as there is a liquidation of Kinder Morgan Energy Partners, L.P. If there is a liquidation of Kinder Morgan Energy Partners, L.P., it is intended that we will receive allocations of income and gain in an amount necessary for the capital account attributable to each i-unit to be equal to that of a common unit. As a result, we will likely realize taxable income upon the liquidation of Kinder Morgan Energy Partners, L.P. However, there may not be sufficient amounts of income and gain to cause the capital account attributable to each i-unit to be equal to that of a common unit. If they are not equal, we, and therefore our shareholders, will receive less value than would be received by an owner of common units.
Further, the tax indemnity provided to us by Kinder Morgan, Inc. only indemnifies us for our tax liabilities to the extent we have not received sufficient cash in the transaction generating the tax liability to pay the associated tax. Prior to any liquidation of Kinder Morgan Energy Partners, L.P., we do not expect to receive cash in a taxable transaction. If a liquidation of Kinder Morgan Energy Partners, L.P. occurs, however, we likely would receive cash which would need to be used at least in part to pay taxes. As a result, our residual value and the value of our shares likely will be less than the value of the common units upon the liquidation of Kinder Morgan Energy Partners, L.P.
Our management and control of the business and affairs of Kinder Morgan Energy Partners, L.P. and its operating partnerships could result in our being liable for obligations to third parties who transact business with Kinder Morgan Energy Partners, L.P. and its operating partnerships and to whom we held ourselves out as a general partner. We could also be responsible for environmental costs and liabilities associated with Kinder Morgan Energy Partners, L.P.'s assets in the event that it is not able to perform all of its obligations under environmental laws. Kinder Morgan Energy Partners, L.P. may not be able to reimburse or indemnify us as a result of its insolvency or bankruptcy. The primary adverse impact of that insolvency or bankruptcy on us would be the decline in or elimination of the value of our i-units, which are our only significant assets. Assuming under these circumstances that we have some residual value in our i-units, a direct claim by creditors of Kinder Morgan Energy Partners, L.P. against us could further reduce our net asset value and cause us also to declare bankruptcy. Another risk with respect to third party claims will occur, however, under the circumstances when Kinder Morgan Energy Partners, L.P. is financially able to pay us, but for some other reason does not reimburse or indemnify us. For example, to the extent that Kinder Morgan Energy Partners, L.P. fails to satisfy any environmental liabilities for which it is responsible, we could be held liable under environmental laws. For additional information, see the following risk factor.
11
If we are not fully indemnified by Kinder Morgan Energy Partners, L.P. for all the liabilities we incur in performing our obligations under the delegation of control agreement, we could face material difficulties in paying those liabilities, and the net value of our assets could be adversely affected. Under the delegation of control agreement, we have been delegated management and control of the business and affairs of Kinder Morgan Energy Partners, L.P. and its operating partnerships. There are circumstances under which we may not be indemnified by Kinder Morgan Energy Partners, L.P. or Kinder Morgan G.P., Inc. for liabilities we incur in managing and controlling the business and affairs of Kinder Morgan Energy Partners, L.P. These circumstances include:
|
if we act in bad faith; and |
|
if we breach laws like the federal securities laws, where indemnification may not be allowed. |
If in the future we cease to manage and control the business and affairs of Kinder Morgan Energy Partners, L.P., we may be deemed to be an investment company for purposes of the Investment Company Act of 1940. In that event, we would either have to register as an investment company under the Investment Company Act, obtain exemptive relief from the Securities and Exchange Commission, or modify our organizational structure or our contract rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with our affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage, and require us to add directors who are independent of us or our affiliates.
The interests of Kinder Morgan, Inc. may differ from our interests, the interests of our shareholders and the interests of unitholders of Kinder Morgan Energy Partners, L.P. Kinder Morgan, Inc. owns all of the stock of the general partner of Kinder Morgan Energy Partners, L.P. and elects all of its directors. The general partner of Kinder Morgan Energy Partners, L.P. owns all of our voting shares and elects all of our directors. Furthermore, some of our directors and officers are also directors and officers of Kinder Morgan, Inc. and the general partner of Kinder Morgan Energy Partners, L.P. and have fiduciary duties to manage the businesses of Kinder Morgan, Inc. and Kinder Morgan Energy Partners, L.P. in a manner that may not be in the best interest of our shareholders. Kinder Morgan, Inc. has a number of interests that differ from the interests of our shareholders and the interests of the unitholders. As a result, there is a risk that important business decisions will not be made in the best interest of our shareholders.
Our limited liability company agreement restricts or eliminates a number of the fiduciary duties that would otherwise be owed by our board of directors to our shareholders, and the partnership agreement of Kinder Morgan Energy Partners, L.P. restricts or eliminates a number of the fiduciary duties that would otherwise be owed by the general partner to the unitholders. Modifications of state law standards of fiduciary duties may significantly limit the ability of our shareholders and the unitholders to successfully challenge the actions of our board of directors and the general partner, respectively, in the event of a breach of their fiduciary duties. These state law standards include the duties of care and loyalty. The duty of loyalty, in the absence of a provision in the limited liability company agreement or the limited partnership agreement to the contrary, would generally prohibit our board of directors or the general partner from taking any action or engaging in any transaction as to which it has a conflict of interest. Our limited liability company and the limited partnership agreement of Kinder Morgan Energy Partners, L.P. contain provisions that prohibit our shareholders and the limited partners, respectively, from advancing claims that otherwise might raise issues as to compliance with fiduciary duties or applicable law. For example, the limited partnership agreement of Kinder Morgan Energy Partners, L.P. provides that the general partner may take into account the interests of parties other than Kinder Morgan Energy Partners, L.P. in resolving conflicts of interest. Further, it provides that in the absence of bad faith by the general partner, the resolution of a conflict by the general
12
partner will not be a breach of any duty. The provisions relating to the general partner apply equally to us as its delegate. Our limited liability company agreement provides that none of our directors or officers will be liable to us or any other person for any acts or omissions if they acted in good faith.
Information Regarding Forward-looking Statements
This filing includes forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as "anticipate," "believe," "intend," "plan," "projection," "forecast," "strategy," "position," "continue," "estimate," "expect," "may," or the negative of those terms or other variations of them or comparable terminology. In particular, statements, express or implied, concerning future actions, conditions or events, future operating results or the ability to generate sales, income or cash flow or to make distributions are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of our operations and those of Kinder Morgan Energy Partners, L.P. may differ materially from those expressed in these forward-looking statements. Please see "Information Regarding Forward-Looking Statements" for Kinder Morgan Energy Partners, L.P. included in Annex A. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from those in the forward-looking statements include:
| price trends
and overall demand for natural gas liquids, refined petroleum products, oil, carbon
dioxide, natural gas, coal and other bulk materials and chemicals in the United States; |
| economic
activity, weather, alternative energy sources, conservation and technological advances
that may affect price trends and demand; |
| changes in
Kinder Morgan Energy Partners, L.P.'s tariff rates implemented by the Federal Energy
Regulatory Commission or the California Public Utilities Commission; |
| Kinder Morgan
Energy Partners, L.P.'s ability to acquire new businesses and assets and integrate those
operations into its existing operations, as well as its ability to make expansions to its
facilities; |
| difficulties
or delays experienced by railroads, barges, trucks, ships or pipelines in delivering
products to or from Kinder Morgan Energy Partners, L.P.'s terminals or pipelines; |
| Kinder Morgan
Energy Partners, L.P.'s ability to successfully identify and close acquisitions and make
cost-saving changes in operations; |
| shut-downs or
cutbacks at major refineries, petrochemical or chemical plants, ports, utilities, military
bases or other businesses that use Kinder Morgan Energy Partners, L.P.'s services or
provide services or products to Kinder Morgan Energy Partners, L.P.; |
| changes in
laws or regulations, third-party relations and approvals, decisions of courts, regulators
and governmental bodies that may adversely affect Kinder Morgan Energy Partners, L.P.'s
business or its ability to compete; |
| our ability to offer and sell equity securities and Kinder Morgan Energy Partners, L.P.'s ability to offer and sell equity securities and debt securities or obtain debt financing in sufficient amounts to implement that portion of Kinder Morgan Energy Partners, L.P.'s business plan that contemplates growth through acquisitions of operating businesses and assets and expansions of its facilities; |
13
| Kinder Morgan Energy Partners,
L.P.'s indebtedness could make it vulnerable to general adverse economic and industry
conditions, limit its ability to borrow additional funds and/or place it at competitive
disadvantages compared to its competitors that have less debt or have other adverse
consequences; |
| interruptions of electric
power supply to Kinder Morgan Energy Partners, L.P.'s facilities due to natural disasters,
power shortages, strikes, riots, terrorism, war or other causes; |
| our ability to obtain
insurance coverage without a significant level of self-retention of risk; |
| acts of nature, sabotage,
terrorism or other similar acts causing damage greater than Kinder Morgan Energy Partners,
L.P.'s insurance coverage limits; |
| capital markets conditions; |
| the political and economic
stability of the oil producing nations of the world; |
| national, international,
regional and local economic, competitive and regulatory conditions and developments; |
| the ability of Kinder Morgan
Energy Partners, L.P. to achieve cost savings and revenue growth; |
| inflation; |
| interest rates; |
| the pace of deregulation of
retail natural gas and electricity; |
| foreign exchange fluctuations; |
| the timing and extent of
changes in commodity prices for oil, natural gas, electricity and certain agricultural
products; |
| the extent of Kinder Morgan
Energy Partners, L.P.'s success in discovering, developing and producing oil and gas
reserves, including the risks inherent in exploration and development drilling, well
completion and other development activities; |
| engineering and mechanical or
technological difficulties that Kinder Morgan Energy Partners, L.P. may experience with
operational equipment, in well completions and workovers, and in drilling new wells; |
| the uncertainty inherent in
estimating future oil and natural gas production or reserves that Kinder Morgan Energy
Partners, L.P. may experience; |
| the timing and success of
Kinder Morgan Energy Partners, L.P.'s business development efforts; and |
| unfavorable results of litigation involving Kinder Morgan Energy Partners, L.P. and the fruition of contingencies referred to in Kinder Morgan Energy Partners, L.P.'s Annual Report on Form 10-K for the year ended December 31, 2004. |
You should not put undue reliance on any forward-looking statements. See Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations - Risk Factors of our Business" for a more detailed description of these and other factors that may affect the forward-looking statements. When considering forward-looking statements, one should keep in mind the risk factors described in "Risk Factors of our Business" above. The risk factors could cause our actual results to differ materially from those contained in any forward-looking statement. We disclaim any obligation to
14
update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
The nature of our business and operations is such that no activities or transactions of the type requiring discussion under this item are conducted or entered into.
15
Item 8. Financial Statements and Supplementary Data.
INDEX
16
Report of Independent Registered Public Accounting Firm
To the Board of Directors
and Stockholders of Kinder Morgan Management, LLC
We have completed an integrated audit of Kinder Morgan Management, LLC's 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004 and audits of its 2003 and 2002 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.
Consolidated financial statements
In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Kinder Morgan Management, LLC and its subsidiary at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. 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 the standards of the Public Company Accounting Oversight Board (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 of financial statements 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.
Internal control over financial reporting
Also, in our opinion, management's assessment, included in Management's Report on Internal Control Over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2004 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control - Integrated Framework issued by the COSO. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management's assessment and on the effectiveness of the Company's internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for
17
external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
PricewaterhouseCoopers LLP
Houston, Texas
March 4, 2005
18
CONSOLIDATED STATEMENTS OF INCOME
Kinder Morgan Management, LLC and Subsidiary
Year Ended December 31, |
|||||
2004 |
2003 |
2002 |
|||
(In thousands except per share amounts) |
|||||
Equity in Earnings of Kinder Morgan Energy Partners, L.P. | $ 113,482 |
$ 94,775 |
$ 72,199 |
||
Provision for Income Taxes | 38,360 |
36,014 |
26,865 |
||
Net Income | $ 75,122 |
$ 58,761 |
$ 45,334 |
||
========== |
========== |
========== |
|||
Earnings Per Share, Basic and Diluted | $ 1.47 |
$ 1.24 |
$ 1.23 |
||
========== |
========== |
========== |
|||
Number of Shares Used in Computing Basic and Diluted Earnings Per Share |
51,181 |
47,372 |
36,790 |
||
========== |
========== |
========== |
|||
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Year Ended December 31, |
|||||
2004 |
2003 |
2002 |
|||
(In thousands except per share amounts) |
|||||
Net Income | $ 75,122 |
$ 58,761 |
$ 45,334 |
||
Equity in Other Comprehensive Loss of Equity | |||||
Method Investee (Net of Tax Benefits of $28,798, $11,828 and $3,179) | (50,497) |
(19,297) |
(5,187) |
||
Total Comprehensive Income | $ 24,625 |
$ 39,464 |
$ 40,147 |
||
========== |
========== |
========== |
|||
The accompanying notes are an integral part of these statements.
19
CONSOLIDATED BALANCE SHEETS
Kinder Morgan Management, LLC and Subsidiary
December 31, |
|||
2004 |
2003 |
||
(In thousands) |
|||
ASSETS |
|||
Current Assets: | |||
Accounts Receivable - Related Party | $ 24,857 |
$ 14,661 |
|
Prepayments and Other | 884 |
1,657 |
|
25,741 |
16,318 |
||
Investment in Kinder Morgan Energy Partners, L.P. | 1,613,607 |
1,489,968 |
|
Total Assets | $1,639,348 |
$1,506,286 |
|
========== |
========== |
||
LIABILITIES AND SHAREHOLDERS' EQUITY |
|||
Current Liabilities: | |||
Accounts Payable | $ 1,252 |
$ 2,742 |
|
Accrued Expenses and Other | 24,413 |
13,500 |
|
25,665 |
16,242 |
||
Deferred Income Taxes | 82,601 |
64,459 |
|
Shareholders' Equity: | |||
Voting Shares - Unlimited Authorized; 2 Voting Shares Issued and Outstanding | 100 |
100 |
|
Listed Shares - Unlimited Authorized; 54,157,639 and 48,996,463 Listed Shares | |||
Issued and Outstanding, Respectively | 1,778,090 |
1,559,485 |
|
Retained Deficit | (172,127) |
(109,516) |
|
Accumulated Other Comprehensive Loss | (74,981) |
(24,484) |
|
Total Shareholders' Equity | 1,531,082 |
1,425,585 |
|
Total Liabilities and Shareholders' Equity | $1,639,348 |
$1,506,286 |
|
========== |
========== |
||
The accompanying notes are an integral part of these statements.
20
CONSOLIDATED STATEMENTS OF SHAREHOLDERS'
EQUITY
Kinder Morgan Management, LLC and Subsidiary
Year Ended December 31, |
|||||||||||
2004 |
2003 |
2002 |
|||||||||
Shares |
Amount |
Shares |
Amount |
Shares |
Amount |
||||||
(Dollars in thousands) |
|||||||||||
Voting Shares: | |||||||||||
Beginning Balance | 2 |
$ 100 |
2 |
$ 100 |
2 |
$ 100 |
|||||
Ending Balance | 2 |
100 |
2 |
100 |
2 |
100 |
|||||
Listed Shares: | |||||||||||
Beginning Balance | 48,996,463 |
1,559,485 |
45,654,046 |
1,440,255 |
30,636,361 |
1,024,317 |
|||||
Secondary Public Offering of Listed Shares | - |
- |
- |
- |
12,478,900 |
343,170 |
|||||
Listed Shares Issued | 1,660,664 |
67,603 |
- |
- |
- |
- |
|||||
Share Dividends | 3,500,512 |
137,733 |
3,342,417 |
117,972 |
2,538,785 |
80,133 |
|||||
Underwriting Discount and Offering Expenses | - |
- |
- |
- |
- |
(14,611) |
|||||
Other Issuance Costs | - |
(1,777) |
- |
- |
- |
(44) |
|||||
Revaluation of Kinder Morgan Energy | |||||||||||
Partners, L.P. Investment (Note 3) | - |
15,046 |
- |
1,258 |
- |
7,290 |
|||||
Ending Balance | 54,157,639 |
1,778,090 |
48,996,463 |
1,559,485 |
45,654,046 |
1,440,255 |
|||||
Retained Deficit: | |||||||||||
Beginning Balance | (109,516) |
(50,305) |
(15,506) |
||||||||
Net Income | 75,122 |
58,761 |
45,334 |
||||||||
Share Dividends | (137,733) |
(117,972) |
(80,133) |
||||||||
Ending Balance | (172,127) |
(109,516) |
(50,305) |
||||||||
Accumulated Other Comprehensive Loss (Net of Tax Benefits): |
|||||||||||
Beginning Balance | (24,484) |
(5,187) |
- |
||||||||
Equity in Other
Comprehensive Loss of Equity Method Investees (Net of Tax Benefits of $28,798, $11,828 and $3,179) |
(50,497) |
(19,297) |
(5,187) |
||||||||
Ending Balance |
|
(74,981) |
|
(24,484) |
|
(5,187) |
|||||
Total Shareholders' Equity | 54,157,641 |
$1,531,082 |
48,996,465 |
$1,425,585 |
45,654,048 |
$1,384,863 |
|||||
========== |
========== |
========== |
========== |
========== |
========== |
||||||
The accompanying notes are an integral part of these statements.
21
CONSOLIDATED STATEMENTS OF CASH FLOWS
Kinder Morgan Management, LLC and Subsidiary
Increase (Decrease) in Cash and Cash Equivalents
Year Ended December 31, |
|||||
2004 |
2003 |
2002 |
|||
(In thousands) |
|||||
Cash Flows From Operating Activities: | |||||
Net Income | $ 75,122 |
$ 58,761 |
$ 45,334 |
||
Adjustments to Reconcile Net Income to Net Cash Flows from | |||||
Operating Activities: | |||||
Deferred Income Taxes | 38,360 |
36,014 |
26,865 |
||
Equity in Earnings of Kinder Morgan Energy Partners, L.P. | (113,482) |
(94,775) |
(72,199) |
||
Increase in Accounts Receivable | (10,196) |
(260) |
(8,250) |
||
Decrease in Other Current Assets | 773 |
3,318 |
3,513 |
||
(Decrease) Increase in Accounts Payable | (1,490) |
(677) |
3,259 |
||
(Decrease) Increase in Other Current Liabilities | 10,913 |
(2,381) |
1,478 |
||
Net Cash Flows Provided by Operating Activities | - |
- |
- |
||
Cash Flows From Investing Activities: | |||||
Purchase of i-units of Kinder Morgan Energy Partners, L.P. | (67,528) |
- |
(328,559) |
||
Net Cash Flows Used in Investing Activities | (67,528) |
- |
(328,559) |
||
Cash Flows From Financing Activities: | |||||
Shares Issued | 67,603 |
- |
343,170 |
||
Share Issuance Costs | (75) |
- |
(14,611) |
||
Net Cash Flows Provided by Financing Activities | 67,528 |
- |
328,559 |
||
Net Increase in Cash and Cash Equivalents | - |
- |
- |
||
Cash and Cash Equivalents at Beginning of Period | - |
- |
- |
||
Cash and Cash Equivalents at End of Period | $ - |
$ - |
$ - |
||
========= |
========= |
========= |
|||
The accompanying notes are an integral part of these statements.
22
KINDER MORGAN MANAGEMENT, LLC AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. General
Kinder Morgan Management, LLC is a publicly traded Delaware limited liability company that was formed on February 14, 2001. Kinder Morgan G.P., Inc., an indirect wholly owned subsidiary of Kinder Morgan, Inc., (a midstream energy company traded on the New York Stock Exchange under the symbol "KMI"), owns all of our voting shares. References to "we," "our" or "the Company" are intended to mean Kinder Morgan Management, LLC and its consolidated subsidiary.
2. Significant Accounting Policies
(A) Basis of Presentation
Our consolidated financial statements include the accounts of Kinder Morgan Management, LLC and its wholly owned subsidiary, Kinder Morgan Services LLC. All material intercompany transactions and balances have been eliminated.
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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.
(B) Accounting for Investment in Kinder Morgan Energy Partners, L.P.
We use the equity method of accounting for our investment in Kinder Morgan Energy Partners, L.P., which investment is further described in Notes 3 and 4. Kinder Morgan Energy Partners, L.P. is a publicly traded limited partnership and is traded on the New York Stock Exchange under the symbol "KMP." We record, in the period in which it is earned, our share of the earnings of Kinder Morgan Energy Partners, L.P. attributable to the i-units we own. We receive distributions from Kinder Morgan Energy Partners, L.P. in the form of additional i-units, which increase the number of i-units we own. We issue additional shares (or fractions thereof) of the Company to our existing shareholders in an amount equal to the additional i-units received from Kinder Morgan Energy Partners, L.P. At December 31, 2004, through our ownership of i-units, we owned approximately 26.2% of all of Kinder Morgan Energy Partners, L.P.'s outstanding limited partner interests.
We adjust the carrying value of our 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 costs for reacquisitions) and our underlying book basis are recorded directly to paid-in capital rather than being recognized as gains or losses. See Note 3 for a discussion of several such transactions.
(C) Accounting for Share Distributions
Our board of directors declares and we make additional share distributions at the same times that Kinder Morgan Energy Partners, L.P. declares and makes distributions on the i-units to us, so that the number of i-units we own and the number of our shares outstanding remain equal. We account for the share distributions we make by charging retained earnings and crediting outstanding shares with amounts that equal the number of shares distributed multiplied by the closing price of the shares on the date the distribution is payable. As a result, we expect that our retained earnings will always be in a deficit
23
position because (i) distributions per unit for Kinder Morgan Energy Partners, L.P. (which serve to reduce our retained earnings) are based on earnings plus depreciation, depletion and amortization minus sustaining capital expenditures, which amount generally exceeds the earnings per unit (which serve to increase our retained earnings) and (ii) the impact on our retained earnings attributable to our equity in the earnings of Kinder Morgan Energy Partners, L.P. is recorded after a provision for income taxes.
(D) Earnings Per Share
Both basic and diluted earnings per share are computed based on the weighted-average number of shares outstanding during each period, adjusted for share splits. There are no securities outstanding that may be converted into or exercised for shares.
(E) Income Taxes
We are a limited liability company that has elected to be treated as a corporation for federal income tax purposes. Deferred income tax assets and liabilities are recognized for temporary differences between the basis of our assets and liabilities for financial reporting and tax purposes. We include changes in tax legislation in the relevant computations in the period in which such changes are effective.
Our long-term deferred income tax liability of $82.6 million and $64.5 million at December 31, 2004 and 2003, respectively, results from recognition of the increased investment associated with recording our equity in the earnings of Kinder Morgan Energy Partners, L.P. The effective tax rate utilized in computing our income tax provision was 33.8% for 2004, 38% for 2003 and 37.2% for 2002. The effective tax rate includes the 35% federal statutory rate, a provision for state income taxes and a reduction of 2.5% in 2004 and 0.8% in 2002 due to a reduction in the state tax rate on our cumulative deferred tax liability.
We entered into a tax indemnification agreement with Kinder Morgan, Inc. Pursuant to this tax indemnification agreement, Kinder Morgan, Inc. agreed to indemnify us for any tax liability attributable to our formation or our management and control of the business and affairs of Kinder Morgan Energy Partners, L.P. and for any taxes arising out of a transaction involving the i-units we own to the extent the transaction does not generate sufficient cash to pay our taxes with respect to such transaction.
(F) Cash Flow Information
We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. No cash payments for interest or income taxes were made during the periods presented.
3. Capitalization
Our authorized capital structure consists of two classes of interests: (1) our listed shares and (2) our voting shares, collectively referred to in this document as our "shares." Prior to the May 2001 initial public offering of our shares, our issued capitalization consisted of $100,000 contributed by Kinder Morgan, G.P., Inc. for two voting shares. At December 31, 2004, Kinder Morgan, Inc. owned approximately 15.1 million, or approximately 27.9% of our outstanding shares.
In February 2004, Kinder Morgan Energy Partners, L.P. issued 5.3 million common units in a public offering at a price of $46.80 per common unit, receiving total net proceeds (after underwriting discount) of $237.8 million. We did not acquire any of these common units. On March 25, 2004, we closed the issuance and sale of 360,664 of our listed shares in a limited registered offering. None of the shares from our offering were purchased by Kinder Morgan, Inc. We used the net proceeds of approximately $14.9
24
million from the offering to buy additional i-units from Kinder Morgan Energy Partners, L.P. In November 2004, Kinder Morgan Energy Partners, L.P. issued 5.5 million common units in a public offering at a price of $46.00 per common unit. An additional 0.6 million common units were issued by Kinder Morgan Energy Partners, L.P. in December 2004 in order to meet the underwriters' over-allotment option. Kinder Morgan Energy Partners, L.P. received total net proceeds (after underwriting discount) from these offerings of $268.3 million. We did not acquire any of these common units. Also in November 2004, we closed the issuance and sale of 1.3 million of our listed shares in a limited registered offering. None of the shares from our offering were purchased by Kinder Morgan, Inc. We used the net proceeds of approximately $52.6 million from the offering to buy additional i-units from Kinder Morgan Energy Partners, L.P. These issuances, collectively, changed our percentage ownership of Kinder Morgan Energy Partners, L.P. and had the associated effects of increasing our (i) investment in the net assets of Kinder Morgan Energy Partners, L.P. by $23.6 million, (ii) associated accumulated deferred income taxes by $8.6 million and (iii) paid-in capital by $15.0 million. See Note 1(B).
In June 2003, Kinder Morgan Energy Partners, L.P. issued 4.6 million common units in a public offering at a price of $39.35 per common unit, receiving total net proceeds (after underwriting discount) of $173.3 million. We did not acquire any of these common units. This issuance of common units by Kinder Morgan Energy Partners, L.P. changed our percentage ownership of Kinder Morgan Energy Partners, L.P. and had the associated effects of increasing our (i) investment in the net assets of Kinder Morgan Energy Partners by $6.4 million, (ii) associated accumulated deferred income taxes by $2.4 million and (iii) paid-in capital by $4.0 million. See Note 1(B).
On February 14, 2005, we paid a share distribution of 0.017651 shares per outstanding share (955,936 total shares) to shareholders of record as of January 31, 2005, based on the $0.74 per common unit distribution declared by Kinder Morgan Energy Partners, L.P. This distribution is paid in the form of additional shares or fractions thereof based on the average market price of a share determined for a ten-trading day period ending on the trading day immediately prior to the ex-dividend date for our shares.
4. Business Activities and Related Party Transactions
At no time after our formation and prior to our initial public offering did we have any operations or own any interest in Kinder Morgan Energy Partners, L.P. Upon the closing of our initial public offering in May 2001, we became a limited partner in Kinder Morgan Energy Partners, L.P. and, pursuant to a delegation of control agreement, we assumed the management and control of its business and affairs. Under the delegation of control agreement, Kinder Morgan G.P., Inc. delegated to us, to the fullest extent permitted under Delaware law and the Kinder Morgan Energy Partners, L.P. partnership agreement, all of Kinder Morgan G.P., Inc.'s power and authority to manage and control the business and affairs of Kinder Morgan Energy Partners, L.P., subject to Kinder Morgan G.P., Inc.'s right to approve certain transactions. Kinder Morgan Energy Partners, L.P. will either pay directly or reimburse us for all expenses we incur in performing under the delegation of control agreement and will be obligated to indemnify us against claims and liabilities provided that we have acted in good faith and in a manner we believed to be in, or not opposed to, the best interests of Kinder Morgan Energy Partners, L.P. and the indemnity is not prohibited by law. Kinder Morgan Energy Partners, L.P. consented to the terms of the delegation of control agreement including Kinder Morgan Energy Partners, L.P.'s indemnity and reimbursement obligations. We do not receive a fee for our service under the delegation of control agreement, nor do we receive any margin or profit on the expense reimbursement. We incurred approximately $132.2 million, $111.4 million and $106.9 million of expenses during the years ended December 31, 2004, 2003 and 2002, respectively, on behalf of Kinder Morgan Energy Partners, L.P. The expense reimbursements received from Kinder Morgan Energy Partners, L.P. are accounted for as a reduction to the expense incurred. The net monthly balance payable or receivable from these activities is settled in cash in the following month.
25
Kinder Morgan Services LLC is our wholly owned subsidiary and provides centralized payroll and employee benefits services to us, Kinder Morgan G.P., Inc., Kinder Morgan Energy Partners, L.P. and Kinder Morgan Energy Partners, L.P.'s operating partnerships and subsidiaries (collectively, the "Group"). Employees of KMGP Services Company, Inc., a subsidiary of Kinder Morgan G.P., Inc., are assigned to work for one or more members of the Group. When they do so, they remain under our ultimate management and control. The direct costs of all compensation, benefits expenses, employer taxes and other employer expenses for these employees are allocated and charged by Kinder Morgan Services LLC to the appropriate members of the Group, and the members of the Group reimburse Kinder Morgan Services LLC for their allocated shares of these direct costs. There is no profit or margin charged by Kinder Morgan Services LLC to the members of the Group. The administrative support necessary to implement these payroll and benefits services is provided by the human resource department of Kinder Morgan, Inc., and the related administrative costs are allocated to members of the Group in accordance with expense allocation procedures. The effect of these arrangements is that each member of the Group bears the direct compensation and employee benefits costs of its assigned or partially assigned employees, as the case may be, while also bearing its allocable share of administrative costs. Pursuant to its limited partnership agreement, Kinder Morgan Energy Partners, L.P. reimburses Kinder Morgan Services LLC for its share of these administrative costs, and such reimbursements are accounted for as described above.
5. Summarized Financial Information for Kinder Morgan Energy Partners, L.P.
Following is summarized financial information for Kinder Morgan Energy Partners, L.P., a publicly traded limited partnership in which we own a significant interest. Additional information on Kinder Morgan Energy Partners, L.P.'s results of operations and financial position are contained in its 2004 Annual Report on Form 10-K, which is attached to this report as Annex A.
Summarized Income Statement Information
Year Ended December 31, |
|||||
2004 |
2003 |
2002 |
|||
(In thousands) |
|||||
Operating Revenues | $ 7,932,861 |
$ 6,624,322 |
$ 4,237,057 |
||
Operating Expenses | 6,958,865 |
5,817,633 |
3,512,759 |
||
Operating Income | $ 973,996 |
$ 806,689 |
$ 724,298 |
||
=========== |
=========== |
=========== |
|||
Income Before Cumulative Effect of a Change in Accounting Principle |
$ 831,578 |
$ 693,872 |
$ 608,377 |
||
=========== |
=========== |
=========== |
|||
Net Income | $ 831,578 |
$ 697,337 |
$ 608,377 |
||
=========== |
=========== |
=========== |
Summarized Balance Sheet Information
As of December 31, |
|||
2004 |
2003 |
||
(In thousands) |
|||
Current Assets | $ 853,171 |
$ 705,522 |
|
============ |
============ |
||
Noncurrent Assets | $ 9,699,771 |
$ 8,433,660 |
|
============ |
============ |
||
Current Liabilities | $ 1,180,855 |
$ 804,379 |
|
============ |
============ |
||
Noncurrent Liabilities | $ 5,429,921 |
$ 4,783,812 |
|
============ |
============ |
||
Minority Interest | $ 45,646 |
$ 40,064 |
============ |
============ |
26
6. Recent Accounting Pronouncements
In January 2004, the FASB issued FASB Staff Position ("FSP") FAS 106-1, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the "Act"). This FSP permits a sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to postpone accounting for the effects of the Act. Regardless of whether a company elects that deferral, the FSP requires certain disclosures pending further consideration of the underlying accounting issues. In May 2004, the FASB issued FSP FAS 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003, which superseded FSP FAS 106-1 effective July 1, 2004. FSP FAS 106-2 provides transitional guidance for accounting for the effects of the Act on the accumulated projected benefit obligation and periodic postretirement health care benefit expense. We have no employees.
In December 2004, the FASB issued SFAS No. 123R (revised 2004), Share-Based Payment. This Statement amends SFAS No. 123, Accounting for Stock-Based Compensation, and requires companies to expense the value of employee stock options and similar awards. Significant provisions of SFAS No. 123R include the following:
| share-based payment awards result in a cost that will be measured at fair value on the awards' grant date, based on the estimated number of awards that are expected to vest. Compensation cost for awards that vest would not be reversed if the awards expire without being exercised; |
| when measuring fair value, companies can choose an option-pricing model that appropriately reflects their specific circumstances and the economics of their transactions; |
| companies will recognize compensation cost for share-based payment awards as they vest, including the related tax effects. Upon settlement of share-based payment awards, the tax effects will be recognized in the income statement or additional paid-in capital; and |
| public companies are allowed to select from three alternative transition methods - each having different reporting implications. |
In October 2004, the FASB decided to delay by six months the effective date for public companies to implement SFAS No. 123R (revised 2004). The new Statement is now effective for public companies for interim and annual periods beginning after June 15, 2005. Public companies with calendar year-ends will be required to adopt SFAS No. 123R in the third quarter of 2005. We currently have no share-based compensation plans.
We do not expect these pronouncements to have a significant impact on our financial statements, except for any impacts that may result from changes in our equity in earnings of Kinder Morgan Energy Partners, L.P. as a result of its adoption of these pronouncements.
27
KINDER MORGAN MANAGEMENT, LLC AND SUBSIDIARY
SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarterly Operating Results for 2004 and 2003
2004-Three Months Ended |
|||||||
March 31 |
June 30 |
September 30 |
December 31 |
||||
(In thousands except per share amounts) |
|||||||
Equity in Earnings of Kinder Morgan | |||||||
Energy Partners, L.P. | $ 25,653 |
$ 25,662 |
$ 30,591 |
$ 31,576 |
|||
Provision for Income Taxes | 9,748 |
9,752 |
11,624 |
7,236 |
|||
Net Income | $ 15,905 |
$ 15,910 |
$ 18,967 |
$ 24,340 |
|||
========= |
========= |
========= |
========= |
||||
Earnings Per Share, Basic and Diluted | $ 0.32 |
$ 0.31 |
$ 0.37 |
$ 0.46 |
|||
========= |
========= |
========= |
========= |
||||
Number of Shares Used in Computing Basic and Diluted Earnings Per Share |
49,435 |
50,596 |
51,498 |
53,168 |
|||
========= |
========= |
========= |
========= |
2003-Three Months Ended |
|||||||
March 31 |
June 30 |
September 30 |
December 31 |
||||
(In thousands except per share amounts) |
|||||||
Equity in Earnings of Kinder Morgan | |||||||
Energy Partners, L.P. | $ 23,817 |
$ 22,686 |
$ 23,263 |
$ 25,009 |
|||
Provision for Income Taxes | 9,050 |
8,621 |
8,840 |
9,503 |
|||
Net Income | $ 14,767 |
$ 14,065 |
$ 14,423 |
$ 15,506 |
|||
========= |
========= |
========= |
========= |
||||
Earnings Per Share, Basic and Diluted | $ 0.32 |
$ 0.30 |
$ 0.30 |
$ 0.32 |
|||
========= |
========= |
========= |
========= |
||||
Number of Shares Used in Computing Basic and Diluted Earnings Per Share |
46,093 |
46,957 |
47,797 |
48,608 |
|||
========= |
========= |
========= |
========= |
Supplemental Information on Oil and Gas Producing Activities (Unaudited)
We do not directly have oil and gas producing activities, however, our equity method investee, Kinder Morgan Energy Partners, L.P., does have significant oil and gas producing activities. The Supplementary Information on Oil and Gas Producing Activities that follows is presented as required by SFAS No. 69, Disclosures about Oil and Gas Producing Activities, and represents our proportionate interest in the oil and gas producing activities of Kinder Morgan Energy Partners, L.P. Our proportionate share of Kinder Morgan Energy Partners, L.P.'s capitalized costs, costs incurred and results of operations from oil and gas producing activities consisted of the following:
December 31, |
|||||
2004 |
2003 |
2002 |
|||
(In thousands) |
|||||
Net Capitalized Costs | $ 245,006 |
$ 194,101 |
$ 68,9901 |
||
Costs Incurred for the Year Ended | 75,294 |
150,5391 |
32,6041 |
||
Results of Operations for the Year Ended | 21,054 |
10,4731 |
6,1791 |
1 | Includes amounts relating to Kinder Morgan Energy Partners, L.P.'s previous 15% ownership interest in MKM Partners, L.P., which Kinder Morgan Energy Partners, L.P. accounted for under the equity method. MKM Partners, L.P. was dissolved on June 30, 2003. |
Estimates of proved reserves are subject to change, either positively or negatively, as additional information becomes available and contractual and economic conditions change. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known
28
reservoirs under existing economic and operating conditions, that is, prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. Proved developed reserves are the quantities of crude oil, natural gas liquids and natural gas expected to be recovered through existing investments in wells and field infrastructure under current operating conditions. Proved undeveloped reserves require additional investments in wells and related infrastructure in order to recover the production.
The standardized measure of discounted cash flows is based on assumptions including year-end market pricing, future development and production costs and projections of future abandonment costs. A discount factor of 10% is applied annually to the future net cash flows.
The table below represents our proportionate share of Kinder Morgan Energy Partners, L.P.'s (i) estimate of proved crude oil, natural gas liquids and natural gas reserves and (ii) standardized measure of discounted cash flows.
December 31, |
|||||||
2004 |
2003 |
20021 |
20011 |
||||
Proved Developed and Undeveloped Reserves: | |||||||
Crude Oil (MBbls) | 31,723 |
29,619 |
18,838 |
3,063 |
|||
Natural Gas Liquids (MBbls) | 5,191 |
4,131 |
4,008 |
348 |
|||
Natural Gas (MMcf)2 | 408 |
836 |
4,592 |
1,246 |
|||
Standardized Measure of Discounted Cash
Flows for the Year Ended |
$524,304 |
$357,589 |
$140,834 |
1 |
Includes amounts relating to Kinder Morgan Energy Partners, L.P.'s previous 15% ownership interest in MKM Partners, L.P., which Kinder Morgan Energy Partners, L.P. accounted for under the equity method. MKM Partners, L.P. was dissolved on June 30, 2003. |
2 |
Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees fahrenheit. |
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A. Controls and Procedures.
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
As of December 31, 2004, our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective in all material respects to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required.
29
Management's Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our evaluation under the framework in Internal Control - Integrated Framework issued by the COSO, our management concluded that our internal control over financial reporting was effective as of December 31, 2004.
Our management's assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.
Changes in Internal Control over Financial Reporting
There has been no change in our internal control over financial reporting during the fourth quarter of 2004 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information.
None
30
Item 10. Directors and Executive Officers of the Registrant.
Set forth below is certain information concerning our directors and executive officers. All directors are elected annually by, and may be removed by, Kinder Morgan G.P., Inc. as the sole holder of our voting shares. All officers serve at the discretion of our board of directors. In addition to the individuals named below, Kinder Morgan, Inc. was one of our directors until its resignation in January 2003.
Name | Age |
Position |
Richard D. Kinder | 60 |
Director, Chairman, Chief Executive Officer and President |
C. Park Shaper | 36 |
Director, Executive Vice President and Chief Financial Officer |
Edward O. Gaylord | 73 |
Director |
Gary L. Hultquist | 61 |
Director |
Perry M. Waughtal | 69 |
Director |
Thomas A. Bannigan | 51 |
Vice President (President, Products Pipelines) |
Richard T. Bradley | 49 |
Vice President (President, CO2) |
David D. Kinder | 30 |
Vice President, Corporate Development |
Joseph Listengart | 36 |
Vice President, General Counsel and Secretary |
Deborah A. Macdonald | 53 |
Vice President (President, Natural Gas Pipelines) |
Jeffrey R. Armstrong | 36 |
Vice President (President, Terminals) |
James E. Street | 48 |
Vice President, Human Resources and Administration |
Richard D. Kinder is Director, Chairman, Chief Executive Officer and President of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. Mr. Kinder was elected President of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. in July 2004. Mr. Kinder has served as Director, Chairman and Chief Executive Officer of Kinder Morgan Management, LLC since its formation in February 2001. He was elected Director, Chairman and Chief Executive Officer of Kinder Morgan, Inc. in October 1999. He was elected Director, Chairman and Chief Executive Officer of Kinder Morgan G.P., Inc. in February 1997. Mr. Kinder is the uncle of David Kinder, Vice President, Corporate Development of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc.
C. Park Shaper is Director, Executive Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. and Executive Vice President and Chief Financial Officer of Kinder Morgan, Inc. Mr. Shaper was elected Executive Vice President of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. in July 2004, and was elected Director of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. in January 2003. He was elected Vice President, Treasurer and Chief Financial Officer of Kinder Morgan Management, LLC upon its formation in February 2001, and served as Treasurer of Kinder Morgan Management, LLC from February 2001 to January 2004. He has served as Treasurer of Kinder Morgan, Inc. from April 2000 to January 2004 and Vice President and Chief Financial Officer of Kinder Morgan, Inc. since January 2000. Mr. Shaper was elected Vice President, Treasurer and Chief Financial Officer of Kinder Morgan G.P., Inc. in January 2000, and served as Treasurer of Kinder Morgan G.P., Inc. from January 2000 to January 2004. He received a Masters in Business Administration degree from the J.L. Kellogg Graduate School of Management at Northwestern University. Mr. Shaper also has a Bachelor of Science degree in Industrial Engineering and a Bachelor of Arts degree in Quantitative Economics from Stanford University.
Edward O. Gaylord is a Director of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. Mr. Gaylord was elected Director of Kinder Morgan Management, LLC upon its formation in February
31
2001. Mr. Gaylord was elected Director of Kinder Morgan G.P., Inc. in February 1997. Since 1989, Mr. Gaylord has been the Chairman of the Board of Directors of Jacintoport Terminal Company, a liquid bulk storage terminal on the Houston, Texas ship channel.
Gary L. Hultquist is a Director of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. Mr. Hultquist was elected Director of Kinder Morgan Management, LLC upon its formation in February 2001. He was elected Director of Kinder Morgan G.P., Inc. in October 1999. Since 1995, Mr. Hultquist has been the Managing Director of Hultquist Capital, LLC, a San Francisco-based strategic and merger advisory firm.
Perry M. Waughtal is a Director of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. Mr. Waughtal was elected Director of Kinder Morgan Management, LLC upon its formation in February 2001. Mr. Waughtal was elected Director of Kinder Morgan G.P., Inc. in April 2000. Since 1994, Mr. Waughtal has been the Chairman of Songy Partners Limited, an Atlanta, Georgia based real estate investment company. Mr. Waughtal is also a director of HealthTronics, Inc.
Thomas A. Bannigan is Vice President (President, Products Pipelines) of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. and President and Chief Executive Officer of Plantation Pipe Line Company. Mr. Bannigan was elected Vice President (President, Products Pipelines) of Kinder Morgan Management, LLC upon its formation in February 2001. He was elected Vice President (President, Products Pipelines) of Kinder Morgan G.P., Inc. in October 1999. Mr. Bannigan has served as President and Chief Executive Officer of Plantation Pipe Line Company since May 1998. Mr. Bannigan received his Juris Doctor, cum laude, from Loyola University in 1980 and received a Bachelors degree from the State University of New York in Buffalo.
Richard T. Bradley is Vice President (President, CO2) of Kinder Morgan Management, LLC and of Kinder Morgan G.P., Inc. and President of Kinder Morgan CO2 Company, L.P. Mr. Bradley was elected Vice President (President, CO2) of Kinder Morgan Management, LLC upon its formation in February 2001 and Vice President (President, CO2) of Kinder Morgan G.P., Inc. in April 2001. Mr. Bradley has been President of Kinder Morgan CO2 Company, L.P. (formerly known as Shell CO2 Company, Ltd.) since March 1998. Mr. Bradley received a Bachelor of Science in Petroleum Engineering from the University of Missouri at Rolla.
David D. Kinder is Vice President, Corporate Development of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. Mr. Kinder was elected Vice President, Corporate Development of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. in October 2002. He served as manager of corporate development for Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. from January 2000 to October 2002. Mr. Kinder graduated cum laude with a Bachelors degree in Finance from Texas Christian University in 1996. Mr. Kinder is the nephew of Richard D. Kinder.
Joseph Listengart is Vice President, General Counsel and Secretary of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. Mr. Listengart was elected Vice President, General Counsel and Secretary of Kinder Morgan Management, LLC upon its formation in February 2001. He was elected Vice President and General Counsel of Kinder Morgan G.P., Inc. and Vice President, General Counsel and Secretary of Kinder Morgan, Inc. in October 1999. Mr. Listengart was elected Kinder Morgan G.P., Inc.'s Secretary in November 1998 and has been an employee of Kinder Morgan G.P., Inc. since March 1998. Mr. Listengart received his Masters in Business Administration from Boston University in January 1995, his Juris Doctor, magna cum laude, from Boston University in May 1994, and his Bachelor of Arts degree in Economics from Stanford University in June 1990.
32
Deborah A. Macdonald is Vice President (President, Natural Gas Pipelines) of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. She was elected Vice President (President, Natural Gas Pipelines) of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. in June 2002. Ms. Macdonald served as President of Natural Gas Pipeline Company of America from October 1999 to March 2003. Ms. Macdonald received her Juris Doctor, summa cum laude, from Creighton University in May 1980 and received a Bachelors degree, magna cum laude, from Creighton University in December 1972.
Jeffrey R. Armstrong is Vice President (President, Terminals) of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. Mr. Armstrong became Vice President (President, Terminals) in July 2003. He served as President, Kinder Morgan Liquids Terminals LLC from March 1, 2001, when the company was formed via the acquisition of GATX Terminals, through July 2003. From 1994 to 2001, Mr. Armstrong worked for GATX Terminals, where he was General Manager of their East Coast operations. He received his bachelor's degree from the United States Merchant Marine Academy and an MBA from the University of Notre Dame.
James E. Street is Vice President, Human Resources and Administration of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. Mr. Street was elected Vice President, Human Resources and Administration of Kinder Morgan Management, LLC upon its formation in February 2001. He was elected Vice President, Human Resources and Administration of Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. in August 1999. Mr. Street received a Masters of Business Administration degree from the University of Nebraska at Omaha and a Bachelor of Science degree from the University of Nebraska at Kearney.
Corporate Governance
Pursuant to a delegation of control agreement among Kinder Morgan Energy Partners, L.P., its general partner, us and others, we manage and control the business and affairs of Kinder Morgan Energy Partners, L.P., except that we cannot take certain specified actions without the approval of Kinder Morgan Energy Partners, L.P.'s general partner. The limited partnership agreement of Kinder Morgan Energy Partners, L.P. provides for a general partner of the Partnership rather than a board of directors. Through the operation of Kinder Morgan Energy Partners, L.P.'s limited partnership agreement and the delegation of control agreement, our board of directors performs the functions of and is the equivalent of a board of directors of Kinder Morgan Energy Partners, L.P. Similarly, the standing committees of our board function as standing committees of the board of Kinder Morgan Energy Partners, L.P. Our board of directors is comprised of the same persons who comprise Kinder Morgan Energy Partners, L.P.'s general partner's board of directors. References in this report to the board mean our board acting as the delegate of and as the board of directors of Kinder Morgan Energy Partners, L.P.'s general partner, and references to committees mean committees of the board acting as the delegate of and as the committees of the board of directors of Kinder Morgan Energy Partners, L.P.'s general partner.
The board has adopted governance guidelines for the board and charters for the audit committee, nominating and governance committee and compensation committee. The governance guidelines and the rules of the New York Stock Exchange require that a majority of the directors be independent, as described in those guidelines and rules respectively. To assist in making determinations of independence, the board has determined that the following categories of relationships are not material relationships that would cause the affected director not to be independent:
|
If the director was an employee, or had an immediate family member who was an executive officer, of us or Kinder Morgan Energy Partners, L.P. or any of its affiliates, but the employment relationship ended more than three years prior to the date of determination (or, in the case of employment of a director as an interim chairman, interim chief executive |
33
officer or interim executive officer, such employment relationship ended by the date of determination); | |
|
If during any twelve month period within the three years prior to the determination the director received no more than, and has no immediate family member that received more than, $100,000 in direct compensation from Kinder Morgan Energy Partners, L.P. or its affiliates, other than (i) director and committee fees and pension or other forms of deferred compensation for prior service (provided such compensation is not contingent in any way on continued service), (ii) compensation received by a director for former service as an interim chairman, interim chief executive officer or interim executive officer, and (iii) compensation received by an immediate family member for service as an employee (other than an executive officer); |
|
If the director is at the date of determination a current employee, or has an immediate family member that is at the date of determination a current executive officer, of another company that has made payments to, or received payments from, Kinder Morgan Energy Partners, L.P. and its affiliates for property or services in an amount which, in each of the three fiscal years prior to the date of determination, was less than the greater of $1.0 million or 2% of such other company's annual consolidated gross revenues. Contributions to tax-exempt organizations are not considered payments for purposes of this determination; |
| If the director is also a director, but is not an employee or executive officer, of Kinder Morgan Energy Partners, L.P.'s general partner or another affiliate or affiliates of us or Kinder Morgan Energy Partners, L.P., so long as such director is otherwise independent; and |
| If the director beneficially owns less than 10% of each class of voting securities of us, Kinder Morgan, Inc., Kinder Morgan Energy Partners, L.P. or its general partner. |
The board has affirmatively determined that Messrs. Gaylord, Hultquist and Waughtal, who constitute a majority of the directors, are independent as described in our governance guidelines and the New York Stock Exchange rules. Each of them meets the standards above and has no other relationship with us. In conjunction with regular quarterly and special board meetings, these three non-management directors also meet in executive session without members of management. In December 2004, Mr. Gaylord was elected for a one year term to serve as lead director to develop the agendas for and moderate these executive sessions of independent directors.
We have a separately designated standing audit committee established in accordance with Section 3(a)(58)(A) of the Securities Exchange Act of 1934 comprised of Messrs. Gaylord, Hultquist and Waughtal. Mr. Waughtal is the chairman of the audit committee and has been determined by the board to be an "audit committee financial expert." The governance guidelines and our audit committee charter, as well as the rules of the New York Stock Exchange and the Securities and Exchange Commission, require that members of the audit committee satisfy independence requirements in addition to those above. The board has determined that all of the members of the audit committee are independent as described under the relevant standards.
We have not, nor has Kinder Morgan Energy Partners, L.P. nor its general partner made, within the preceding three years, contributions to any tax-exempt organization in which any of our or Kinder Morgan Energy Partners, L.P.'s independent directors serves as an executive officer that in any single fiscal year exceeded the greater of $1 million or 2% of such tax-exempt organization's consolidated gross revenues.
On September 3, 2004, our chief executive officer certified to the New York Stock Exchange, as required by Section 303A.12(a) of the New York Stock Exchange Listed Company Manual, that as of
34
September 3, 2004, he was not aware of any violation by us of the New York Stock Exchange's Corporate Governance listing standards. We have also filed as an exhibit to this report the Sarbanes-Oxley Act Section 302 certifications regarding the quality of our public disclosure.
We make available free of charge within the "Investors" information section of our internet website, at www.kindermorgan.com, and in print to any shareholder who requests, the governance guidelines, the charters of the audit committee, compensation committee and nominating and governance committee, and our code of business conduct and ethics (which applies to senior financial officers and the chief executive officer, among others). Requests for copies may be directed to Investor Relations, Kinder Morgan Management, LLC, 500 Dallas Street, Suite 1000, Houston, Texas 77002, or telephone (713) 369-9490. We intend to disclose any amendments to our code of business conduct and ethics that would otherwise be disclosed on Form 8-K and any waiver from a provision of that code granted to our executive officers or directors that would otherwise be disclosed on Form 8-K on our internet website within five business days following such amendment or waiver. The information contained on or connected to our internet website is not incorporated by reference into this Form 10-K and should not be considered part of this or any other report that we file with or furnish to the Securities and Exchange Commission.
You may contact our lead director, the chairpersons of any of the board's committees, the independent directors as a group or the full board by mail to Kinder Morgan Management, LLC, 500 Dallas Street, Suite 1000, Houston, Texas 77002, Attention: General Counsel, or by e-mail within the "Contact Us" section of our internet website, at www.kindermorgan.com. Your communication should specify the intended recipient.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16 of the Securities Exchange Act of 1934 requires our directors and officers, and persons who own more than 10% of a registered class of our equity securities, to file initial reports of ownership and reports of changes in ownership with the Securities and Exchange Commission. Such persons are required by Securities and Exchange Commission regulation to furnish us with copies of all Section 16(a) forms they file.
Based solely on our review of the copies of such forms furnished to us and written representations from our executive officers and directors, we believe that all Section 16(a) filing requirements were met during 2004.
35
Item 11. Executive Compensation.
All of our individual executive officers and directors serve in the same capacities for Kinder Morgan G.P., Inc. Certain of those executive officers, including all of the named officers below, also serve as executive officers of Kinder Morgan, Inc. All information in this report with respect to compensation of executive officers describes the total compensation received by those persons in all capacities for Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc., Kinder Morgan, Inc. and their respective affiliates.
Summary Compensation Table
Annual Compensation |
Long-term |
|||||||||||||
Name and Principal Position |
Year |
Salary |
Bonus1 |
Restricted |
Kinder Morgan, Inc. Shares Underlying |
All Other |
||||||||
Richard D. Kinder |
2004 |
$ 1 |
$ - |
$ - |
- |
$ - |
||||||||
Director, Chairman, | 2003 |
1 |
- |
- |
- |
- |
||||||||
CEO and President |
2002 |
1 |
- |
- |
- |
- |
||||||||
|
||||||||||||||
C. Park Shaper |
2004 |
200,000 |
975,000 |
- |
- |
8,378 |
||||||||
Director, Executive Vice |
2003 |
200,000 |
875,000 |
5,918,000 |
- |
8,378 |
||||||||
President and CFO |
2002 |
200,000 |
950,000 |
- |
100,0004 |
8,336 |
||||||||
|
||||||||||||||
Deborah A. Macdonald |
2004 |
200,000 |
975,000 |
- |
- |
8,966 |
||||||||
(President, Natural | 2003 |
200,000 |
875,000 |
5,380,000 |
- |
8,966 |
||||||||
Gas Pipelines) |
2002 |
200,000 |
950,000 |
- |
50,0005 |
8,966 |
||||||||
|
||||||||||||||
Joseph Listengart |
2004 |
200,000 |
875,000 |
- |
- |
8,378 |
||||||||
Vice President, General |
2003 |
200,000 |
825,000 |
3,766,000 |
- |
8,378 |
||||||||
Counsel and Secretary | 2002 |
200,000 |
950,000 |
- |
- |
8,336 |
||||||||
|
||||||||||||||
Richard T. Bradley, Vice |
2004 |
200,000 |
560,000 |
- |
- |
8,630 |
||||||||
President, (President CO 2) |
2003 |
200,000 |
525,000 |
2,152,000 |
- |
8,606 |
||||||||
2002 |
200,000 |
500,000 |
- |
- |
8,606 |
___________ | |
1 | Amounts earned in year shown and paid the following year. |
2 | Represent shares of restricted Kinder Morgan, Inc. stock awarded in 2003. The awards were issued under a shareholder approved plan. For the 2003 awards, value computed as the number of shares awarded times the closing price on date of grant ($53.80 at July 16, 2003). Twenty-five percent of the shares in each grant vest on the third anniversary after the date of grant and the remaining seventy-five percent of the shares in each grant vest on the fifth anniversary after the date of grant. To vest, Kinder Morgan Energy Partners, L.P. and/or Kinder Morgan, Inc. must also achieve one of the following performance hurdles during the vesting period: (i) Kinder Morgan, Inc. must earn $3.70 per share in any fiscal year; (ii) Kinder Morgan Energy Partners, L.P. must distribute $2.72 over four consecutive quarters; (iii) fund at least one year's annual incentive program; or (iv) Kinder Morgan, Inc.'s stock price must average over $60.00 per share during any consecutive 30-day period. All of these hurdles have been met. The 2003 awards were long-term equity compensation for our current senior management through July 2008, and neither Kinder Morgan Energy Partners, L.P. nor Kinder Morgan, Inc. intend to make further restricted stock awards or other long-term equity grants to them before that date. The holders of the restricted stock awards are eligible to vote and to receive dividends declared on such shares. |
3 | Amounts represent value of contributions to the Kinder Morgan Savings Plan (a 401(k) plan), value of group-term life insurance exceeding $50,000 and taxable parking subsidy. |
4 | The 100,000 options to purchase Kinder Morgan, Inc. shares were granted on January 16, 2002 with an exercise price of $56.99 per share and vest at the rate of twenty-five percent on each of the first four anniversaries after the date of grant. |
5 | The 50,000 options to purchase Kinder Morgan, Inc. shares were granted on January 16, 2002 with an exercise price of $56.99 per share and vest at the rate of twenty-five percent on each of the first four anniversaries after the date of grant. |
Kinder Morgan Savings Plan. The Kinder Morgan Savings Plan is a defined contribution 401(k) plan. The plan permits all full-time employees of Kinder Morgan, Inc. and KMGP Services Company, Inc. to contribute between 1% and 50% of base compensation, on a pre-tax basis, into participant accounts. In
36
addition to a mandatory contribution equal to 4% of base compensation per year for most plan participants, Kinder Morgan G.P., Inc. may make discretionary contributions in years when specific performance objectives are met. Certain employees' contributions are based on collective bargaining agreements. The 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 employer contributions, including discretionary contributions, are in the form of Kinder Morgan, Inc. stock that is immediately convertible into other available investment vehicles at the employee's discretion. During the first quarter of 2005, we will not make any discretionary contributions to individual accounts for 2004. For employees hired on or prior to December 31, 2004, all contributions, together with earnings thereon, are immediately vested and not subject to forfeiture. Employer contributions for employees hired on or after January 1, 2005 will vest on the second anniversary of the date of hire. Participants may direct the investment of their contributions into a variety of investments. Plan assets are held and distributed pursuant to a trust agreement. Because levels of future compensation, participant contributions and investment yields cannot be reliably predicted over the span of time contemplated by a plan of this nature, it is impractical to estimate the annual benefits payable at retirement to the individuals listed in the Summary Compensation Table above.
At its July 2004 meeting, the Compensation Committee of the Kinder Morgan, Inc. Board of Directors approved that contingent upon its approval at its July 2005 meeting, each eligible employee will receive an additional 1% company contribution based on eligible base pay to his or her Savings Plan account each pay period beginning with the first pay period after the July 2005 Committee meeting. The 1% contribution will be in the form of Kinder Morgan, Inc. common stock (the same as the current 4% contribution). The 1% contribution will be in addition to, and does not change or otherwise impact, the annual 4% contribution that eligible employees currently receive. It may be converted to any other Savings Plan investment fund at any time and it will vest on the second anniversary of the employee's date of hire. Since this additional 1% company contribution is discretionary, Compensation Committee approval will be required annually for each contribution.
Common Unit Option Plan. Pursuant to Kinder Morgan Energy Partners, L.P.'s Common Unit Option Plan, key personnel are eligible to receive grants of options to acquire common units. The total number of common units authorized under the option plan is 500,000. None of the options granted under the option plan may be "incentive stock options" under Section 422 of the Internal Revenue Code. If an option expires without being exercised, the number of common units covered by such option will be available for a future award. The exercise price for an option may not be less than the fair market value of a common unit on the date of grant. Kinder Morgan Management, LLC's compensation committee administers the option plan, and the plan has a termination date of March 5, 2008.
No individual employee may be granted options for more than 20,000 common units in any year. Kinder Morgan Management, LLC's compensation committee will determine the duration and vesting of the options to employees at the time of grant. As of December 31, 2004, options to purchase 95,400 common units are currently outstanding and held by 30 former Kinder Morgan G.P., Inc. employees who are now employees of Kinder Morgan, Inc. or KMGP Services Company, Inc. Forty percent of such options will vest on the first anniversary of the date of grant and twenty percent on each of the next three anniversaries. The options expire seven years from the date of grant. As of December 31, 2004, all 95,400 outstanding options were fully vested.
The option plan also granted to each of Kinder Morgan G.P., Inc.'s non-employee directors an option to purchase 10,000 common units at an exercise price equal to the fair market value of the common units at the end of the trading day on such date. Under this provision, as of December 31, 2004, options to purchase 20,000 common units are currently outstanding and held by two of Kinder Morgan G.P., Inc.'s three non-employee directors. Forty percent of all such options will vest on the first anniversary of the date of grant and twenty percent on each of the next three anniversaries. The non-employee director
37
options will expire seven years from the date of grant. As of December 31, 2004, all 20,000 outstanding options were fully vested.
No options to purchase common units were granted during 2004 to any of the individuals named in the Summary Compensation Table above. The following table sets forth certain information as of December 31, 2004 and for the fiscal year then ended with respect to common unit options previously granted to the individuals named in the Summary Compensation Table above. Mr. Listengart is the only person named in the Summary Compensation Table who has been granted common unit options. No common unit options were granted at an option price below the fair market value on the date of grant.
Aggregated Common Unit Option Exercises in 2004
and 2004 Year-End Common Unit Option Values
Shares |
Value |
Number of Units |
Value of Unexercised |
|||||||||||
Name |
on Exercise |
Realized |
Exercisable |
Unexercisable |
Exercisable |
Unexercisable |
||||||||
Joseph Listengart | 10,000 | $283,667 | - | - | $ - | $ - |
Kinder Morgan, Inc. Stock Plan. Under Kinder Morgan, Inc.'s stock plan, employees of Kinder Morgan, Inc. and its affiliates, including employees of Kinder Morgan, Inc.'s direct and indirect subsidiaries, like KMGP Services Company, Inc., are eligible to receive grants of restricted Kinder Morgan, Inc. stock and grants of options to acquire shares of common stock of Kinder Morgan, Inc. The Compensation Committee of Kinder Morgan, Inc.'s board of directors administers this plan. The primary purpose for granting restricted Kinder Morgan, Inc. stock and Kinder Morgan, Inc. stock options under this plan to employees of Kinder Morgan, Inc., KMGP Services Company, Inc. and Kinder Morgan Energy Partners, L.P.'s subsidiaries is to provide them with an incentive to increase the value of the common stock of Kinder Morgan, Inc. A secondary purpose of the grants is to provide compensation to those employees for services rendered to Kinder Morgan Energy Partners, L.P. and its subsidiaries. During 2004, none of the persons named in the Summary Compensation Table above were granted Kinder Morgan, Inc. stock options.
Aggregated Kinder Morgan, Inc. Stock Option Exercises in 2004
and 2004 Year-End Kinder Morgan, Inc. Stock Option Values
Number of Shares |
Value of Unexercised |
|||||||||||||
Name |
Shares |
Value |
Exercisable |
Unexercisable |
Exercisable |
Unexercisable |
||||||||
C. Park Shaper | - |
$ - |
170,000 |
50,000 |
$5,984,475 |
$ 807,000 |
||||||||
Deborah A. Macdonald | 50,000 |
1,900,674 |
25,000 |
25,000 |
403,500 |
403,500 |
||||||||
Joseph Listengart | 50,000 |
1,843,154 |
56,300 |
- |
2,612,382 |
- |
||||||||
Richard T. Bradley | 40,000 |
1,284,830 |
25,000 |
- |
1,057,938 |
- |
___________ |
|
1 | Calculated on the basis of the fair market value of the underlying shares at year-end, minus the exercise price. |
Cash Balance Retirement Plan. Employees of KMGP Services Company, Inc. and Kinder Morgan, Inc. are also eligible to participate in a Cash Balance Retirement Plan. Certain employees continue to accrue benefits through a career-pay formula, "grandfathered" according to age and years of service on December 31, 2000, or collective bargaining arrangements. All other employees accrue benefits through a personal retirement account in the Cash Balance Retirement Plan. Employees with prior service and not grandfathered converted to the Cash Balance Retirement Plan on January 1, 2001, and were credited with the current fair value of any benefits they had previously accrued through the defined benefit plan.
38
Under the plan, we make contributions on behalf of participating employees equal to 3% of eligible compensation every pay period. In addition, discretionary contributions are made to the plan based on the performance of Kinder Morgan, Inc. and Kinder Morgan Energy Partners, L.P. No discretionary contributions were made for 2004 performance. Interest is credited to the personal retirement accounts at the 30-year U.S. Treasury bond rate, or an approved substitute, in effect each year. Employees become fully vested in the plan after five years, and they may take a lump sum distribution upon termination of employment or retirement.
The following table sets forth the estimated annual benefits payable as of December 31, 2004, under normal retirement at age sixty-five, assuming current remuneration levels without any salary projection, and participation until normal retirement at age sixty-five, with respect to the named executive officers under the provisions of the Kinder Morgan Cash Balance Retirement Plan. These benefits are subject to federal and state income taxes, where applicable, but are not subject to deduction for social security or other offset amounts.
Name |
Current Credited Years |
Estimated Credited Years |
Age as of |
Current Compensation Covered by Plans |
Estimated Annual Benefit Payable Upon Retirement1 |
|||||||||
Richard D. Kinder | 4 |
8.8 |
60.2 |
$ 1 |
$ - |
|||||||||
C. Park Shaper | 4 |
32.7 |
36.4 |
200,000 |
62,363 |
|||||||||
Joseph Listengart | 4 |
32.5 |
36.6 |
200,000 |
61,608 |
|||||||||
Deborah A. Macdonald | 4 |
15.9 |
53.1 |
200,000 |
15,763 |
|||||||||
Richard T. Bradley | 4 |
19.8 |
49.2 |
200,000 |
22,727 |
________ |
|
1 | The estimated annual benefits payable are based on the straight-life annuity form. |
2000 Annual Incentive Plan. Effective January 20, 2000, Kinder Morgan, Inc. established the 2000 Annual Incentive Plan of Kinder Morgan, Inc. The plan was established, in part, to enable the portion of an officer's or other employee's annual bonus based on objective performance criteria to qualify as "qualified performance-based compensation" under the Internal Revenue Code. "Qualified performance-based compensation" compensation is deductible for tax purposes. The plan permits annual bonuses to be paid to Kinder Morgan, Inc.'s officers and other employees and employees of Kinder Morgan, Inc.'s subsidiaries based on their individual performance, Kinder Morgan, Inc.'s performance and the performance of Kinder Morgan, Inc.'s subsidiaries. The plan is administered by the compensation committee of Kinder Morgan, Inc.'s Board of Directors. Under the plan, at or before the start of each calendar year, the compensation committee establishes written performance objectives. The performance objectives are based on one or more criteria set forth in the plan. The compensation committee may specify a minimum acceptable level of achievement of each performance objective below which no bonus is payable with respect to that objective. The maximum payout to any individual under the plan in any year is $1.5 million, and the compensation committee has the discretion to reduce the bonus amount in any performance period. The cash bonuses set forth in the Summary Compensation Table above were paid under the plan. Awards may be granted under the plan for calendar years 2000 through 2005.
Compensation Committee Interlocks and Insider Participation. Kinder Morgan Management, LLC's compensation committee, comprised of Mr. Edward O. Gaylord, Mr. Gary L. Hultquist and Mr. Perry M. Waughtal, makes compensation decisions regarding our and Kinder Morgan G.P., Inc.'s executive officers. Mr. Richard D. Kinder and Mr. James E. Street, who are executive officers of Kinder Morgan Management, LLC, participate in the deliberations of our compensation committee concerning executive officer compensation. Mr. Kinder receives $1.00 annually in total compensation for services to Kinder Morgan, Inc., Kinder Morgan G.P., Inc. and us.
39
Directors Fees. Kinder Morgan Energy Partners, L.P.'s Directors' Unit Appreciation Rights Plan, as discussed below, served as partial compensation for non-employee directors for 2004. In addition to the awards provided by this plan, each non-employee director received additional compensation of $10,000 in 2004, paid $2,500 per quarter. Mr. Edward O. Gaylord, as chairman of our audit committee, received additional compensation in the amount of $10,000, paid $2,500 per quarter. Mr. Perry M. Waughtal, appointed as lead director in October 2003 by us and who served as lead director until December 2004, received additional compensation in the amount of $25,000, paid $10,000 in the first quarter and $5,000 in each of the last three quarters. In addition, directors are reimbursed for reasonable expenses in connection with board meetings.
In January 2005, we terminated the Directors' Unit Appreciation Rights Plan and implemented the Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors, as discussed below, to compensate non-employee directors for 2005.
Directors' Unit Appreciation Rights Plan. On April 1, 2003, our compensation committee established the Kinder Morgan Energy Partners, L.P. Directors' Unit Appreciation Rights Plan. Pursuant to this plan, each of our three non-employee directors was eligible to receive common unit appreciation rights. Upon the exercise of unit appreciation rights, we will pay, within thirty days of the exercise date, the participant an amount of cash equal to the excess, if any, of the aggregate fair market value of the unit appreciation rights exercised as of the exercise date over the aggregate award price of the rights exercised. The fair market value of one unit appreciation right as of the exercise date will be equal to the closing price of one common unit on the New York Stock Exchange on that date. The award price of one unit appreciation right will be equal to the closing price of one common unit on the New York Stock Exchange on the date of grant. Proceeds, if any, from the exercise of a unit appreciation right granted under the plan will be payable only in cash (that is, no exercise will result in the issuance of additional common units) and will be evidenced by a unit appreciation rights agreement.
All unit appreciation rights granted vest on the six-month anniversary of the date of grant. If a unit appreciation right is not exercised in the ten year period following the date of grant, the unit appreciation right will expire and not be exercisable after the end of such period. In addition, if a participant ceases to serve on the board for any reason prior to the vesting date of a unit appreciation right, such unit appreciation right will immediately expire on the date of cessation of service and may not be exercised.
On April 1, 2003, the date of adoption of the plan, each of our three non-employee directors were granted 7,500 unit appreciation rights. In addition, 10,000 unit appreciation rights were granted to each of our three non-employee directors on January 21, 2004, at the first meeting of the board in 2004. As of December 31, 2004, 52,500 unit appreciation rights had been granted. No unit appreciation rights were exercised during 2004. During the first board meeting of 2005, the plan was terminated and replaced by the Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors; however, all unexercised awards made under the plan remain outstanding.
Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors. On January 18, 2005, our compensation committee established the Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan compensate our non-employee directors for 2005. The plan is administered by our compensation committee and our board has sole discretion to terminate the plan at any time. The primary purpose of this plan was to promote Kinder Morgan Energy Partners, L.P.'s interests and the interests of Kinder Morgan Energy Partners, L.P.'s unitholders by aligning the compensation of the non-employee members of our board of directors with unitholders' interests. Further, since our success is dependent on our operation and management of Kinder Morgan Energy Partners, L.P.'s business and its resulting performance, the plan is expected to align the compensation of the non-employee members of the board with the interests of our shareholders.
40
The plan recognizes that the compensation to be paid to each non-employee director is fixed by our board, generally annually, and that the compensation is expected to include an annual retainer payable in cash and other cash compensation. Pursuant to the plan, in lieu of receiving the other cash compensation, each non-employee director may elect to receive common units. Each election shall be generally at or around the first board meeting in January of each calendar year and will be effective for the entire calendar year. The initial election under this plan was made effective January 20, 2005. A non-employee director may make a new election each calendar year. The total number of common units authorized under this compensation plan is 100,000.
Each annual election shall be evidenced by an agreement, the Common Unit Compensation Agreement, between Kinder Morgan Energy Partners, L.P. and each non-employee director, and this agreement will contain the terms and conditions of each award. Pursuant to this agreement, all common units issued under this plan are subject to forfeiture restrictions that expire six months from the date of issuance. Until the forfeiture restrictions lapse, common units issued under the plan may not be sold, assigned, transferred, exchanged, or pledged by a non-employee director. In the event the director's service as a director of our board is terminated prior to the lapse of the forfeiture restriction either for cause, or voluntary resignation, each director shall, for no consideration, forfeit to Kinder Morgan Energy Partners, L.P. all common units to the extent then subject to the forfeiture restrictions. Common units with respect to which forfeiture restrictions have lapsed shall cease to be subject to any forfeiture restrictions, and Kinder Morgan Energy Partners, L.P. will provide each director a certificate representing the units as to which the forfeiture restrictions have lapsed. In addition, each non-employee director shall have the right to receive distributions with respect to the common units awarded to him under the plan, to vote such common units and to enjoy all other unitholder rights, including during the period prior to the lapse of the forfeiture restrictions.
The number of common units to be issued to a non-employee director electing to receive the other cash compensation in the form of common units will equal such other cash compensation awarded, divided by the closing price of the common units on the New York Stock Exchange on the day the cash compensation is awarded (such price, the fair market value), rounded down to the nearest 50 common units. The common units will be issuable as specified in the Common Unit Compensation Agreement. A non-employee director electing to receive the other cash compensation in the form of common units will receive cash equal to the difference between (i) the other cash compensation awarded to such non-employee director and (ii) the number of common units to be issued to such non-employee director multiplied by the fair market value of a common unit. This cash payment shall be payable in four equal installments (together with the annual cash retainer) generally around March 31, June 30, September 30 and December 31 of the calendar year in which such cash compensation is awarded.
On January 18, 2005, the date of adoption of the plan, each of our three non-employee directors was awarded a cash retainer of $40,000 that will be paid quarterly during 2005, and other cash compensation of $79,750. Effective January 20, 2005, each non-employee director elected to receive the other cash compensation of $79,750 in the form of Kinder Morgan Energy Partners, L.P. common units and was issued 1,750 common units pursuant to the plan and its agreements (based on the $45.55 closing market price of Kinder Morgan Energy Partners, L.P. common units on January 18, 2005, as reported on the New York Stock Exchange). Also, consistent with the plan, the $37.50 of other cash compensation that did not equate to a whole common unit, based on the January 18, 2005 $45.55 closing price, will be paid to each of the non-employee directors as described above. No other compensation is to be paid to the non-employee directors during 2005.
41
Item 12. Security Ownership of Certain Beneficial Owners and Management.
The following table sets forth information as of January 31, 2005, regarding (a) the beneficial ownership of (i) Kinder Morgan Energy Partners, L.P.'s common and Class B units, (ii) our shares and (iii) the common stock of Kinder Morgan, Inc., the parent company of Kinder Morgan G.P., Inc., by all our directors and those of Kinder Morgan G.P., Inc., by each of the named executive officers and by all our directors and executive officers as a group and (b) the beneficial ownership of Kinder Morgan Energy Partners, L.P.'s common and Class B units or our shares by all persons known by us to own beneficially more than 5% of Kinder Morgan Energy Partners, L.P.'s common and Class B units and our shares. Unless otherwise noted, the address of each person below is c/o Kinder Morgan Energy Partners, L.P., 500 Dallas Street, Suite 1000, Houston, Texas 77002.
Amount and Nature of Beneficial Ownership1
Kinder Morgan Energy Partners, L.P. |
Kinder Morgan |
Kinder Morgan, Inc. |
||
Common Units |
Class B Units |
Management, LLC Shares |
Voting Stock |
Number |
Percent |
Number |
Percent |
Number |
Percent |
Number |
Percent |
|
Richard D. Kinder6 | 315,979 |
* |
- |
- |
47,379 |
* |
23,995,415 |
19.45% |
C. Park Shaper7 | 4,000 |
* |
- |
- |
2,534 |
* |
326,808 |
* |
Edward O. Gaylord8 | 34,750 |
* |
- |
- |
- |
- |
2,000 |
* |
Gary L. Hultquist9 | 11,750 |
* |
- |
- |
- |
- |
- |
- |
Perry M. Waughtal10 | 39,050 |
* |
- |
- |
37,594 |
* |
50,000 |
* |
Joseph Listengart11 | 4,198 |
* |
- |
- |
- |
- |
140,106 |
* |
Deborah A. Macdonald12 | - |
- |
- |
- |
- |
- |
121,374 |
* |
Richard T. Bradley13 | - |
- |
- |
- |
- |
- |
71,314 |
* |
Directors and Executive
Officers as a group (12 persons)14 |
427,006 |
* |
- |
- |
90,607 |
* |
25,033,714 |
20.29% |
Kinder Morgan, Inc.15 | 14,355,735 |
9.73% |
5,313,400 |
100.00% |
13,293,298 |
24.55% |
- |
- |
Fayez Sarofim16 | 7,888,871 |
5.35% |
- |
- |
- |
- |
- |
- |
Capital Group International, Inc.17 | - |
- |
- |
- |
4,970,550 |
9.18% |
- |
- |
OppenheimerFunds, Inc.18 | - |
- |
- |
- |
4,822,317 |
8.90% |
- |
- |
Kayne Anderson Capital Advisors, L.P.19 | - |
- |
- |
- |
3,816,642 |
7.05% |
- |
- |
____________ |
|
1 |
Except as noted otherwise, all units, our shares and Kinder Morgan, Inc. shares involve sole voting power and sole investment power. For Kinder Morgan Management, LLC, see note (4). On January 18, 2005, Kinder Morgan Management, LLC's board of directors initiated a rule requiring each director to own a minimum of 10,000 common units, Kinder Morgan Management, LLC shares, or a combination thereof. If a director does not already own the minimum number of required securities, the director will have six years to acquire such securities. |
2 |
As of January 31, 2005, Kinder Morgan Energy Partners, L.P. had 147,555,658 common units issued and outstanding. |
3 |
As of January 31, 2005, Kinder Morgan Energy Partners, L.P. had 5,313,400 Class B units issued and outstanding. |
4 |
Represent the limited liability company shares of Kinder Morgan Management, LLC. As of January 31, 2005, there were 54,157,641 issued and outstanding Kinder Morgan Management, LLC shares, including two voting shares owned by Kinder Morgan G.P., Inc. In all cases, Kinder Morgan Energy Partners, L.P.'s i-units will be voted in proportion to the affirmative and negative votes, abstentions and non-votes of owners of Kinder Morgan Management, LLC shares. Through the provisions in Kinder Morgan Energy Partners, L.P.'s partnership agreement and Kinder Morgan Management, LLC's limited liability company agreement, the number of outstanding Kinder Morgan Management, LLC shares, including voting shares owned by Kinder Morgan G.P., Inc., and the number of Kinder Morgan Energy Partners, L.P.'s i-units will at all times be equal. |
5 |
As of January 31, 2005, Kinder Morgan, Inc. had a total of 123,378,197 shares of issued and outstanding voting common stock, which excludes 11,076,901 shares held in treasury. |
6 |
Includes (a) 7,879 common units owned by Mr. Kinder's spouse, (b) 5,173 Kinder Morgan, Inc. shares held by Mr. Kinder's spouse and (c) 250 Kinder Morgan, Inc. shares held by Mr. Kinder in a custodial account for his nephew. Mr. Kinder disclaims any and all beneficial or pecuniary interest in these units and shares. |
42
7 | Includes options to purchase 195,000 Kinder Morgan, Inc. shares exercisable within 60 days of January 31, 2005, and includes 112,500 shares of restricted Kinder Morgan, Inc. stock. |
8 | Includes 1,750 restricted common units. |
9 | Includes options to purchase 10,000 common units exercisable within 60 days of January 31, 2005, and includes 1,750 restricted common units. |
10 | Includes options to purchase 10,000 common units exercisable within 60 days of January 31, 2005, and includes 1,750 restricted common units. |
11 | Includes options to purchase 56,300 Kinder Morgan, Inc. shares exercisable within 60 days of January 31, 2005, and includes 72,500 shares of restricted Kinder Morgan, Inc. stock. |
12 | Includes 102,500 shares of restricted Kinder Morgan, Inc. stock. |
13 | Includes options to purchase 20,000 Kinder Morgan, Inc. shares exercisable within 60 days of January 31, 2005, and includes 41,250 shares of restricted Kinder Morgan, Inc. stock. |
14 | Includes options to purchase 24,000 common units and 433,300 Kinder Morgan, Inc. shares exercisable within 60 days of January 31, 2005, and includes 5,250 restricted common units and 467,500 shares of restricted Kinder Morgan, Inc. stock. |
15 | Includes common units owned by Kinder Morgan, Inc. and its consolidated subsidiaries, including 1,724,000 common units owned by Kinder Morgan G.P., Inc. |
16 | As reported on the Schedule 13G/A filed February 11, 2005 by Fayez Sarofim & Co. and Fayez Sarofim. Mr. Sarofim reports that in regard to Kinder Morgan Energy Partners, L.P.'s common units, he has sole voting power over 2,300,000 common units, shared voting power over 4,242,612 common units, sole disposition power over 2,300,000 common units and shared disposition power over 5,588,871 common units. Mr. Sarofim's address is 2907 Two Houston Center, Houston, Texas 77010. |
17 |
As reported on the Schedule 13G/A filed February 14, 2005 by Capital Group International, Inc. and Capital Guardian Trust Company. Capital Group International, Inc. and Capital Guardian Trust Company report that in regard to Kinder Morgan Management, LLC shares, they have sole voting power over 3,913,560 shares, shared voting power over 0 shares, sole disposition power over 4,970,550 shares and shared disposition power over 0 shares. Capital Group International, Inc.'s and Capital Guardian Trust Company's address is 11100 Santa Monica Blvd., Los Angeles, California 90025. |
18 |
As reported on the Schedule 13G/A filed February 11, 2005 by OppenheimerFunds, Inc. and Oppenheimer Capital Income Fund. OppenheimerFunds, Inc. reports that in regard to Kinder Morgan Management, LLC shares, it has sole voting power over 0 shares, shared voting power over 0 shares, sole disposition power over 0 shares and shared disposition power over 4,822,317 shares. Of these 4,822,317 Kinder Morgan Management, LLC shares, Oppenheimer Capital Income Fund has sole voting power over 3,232,500 shares, shared voting power over 0 shares, sole disposition power over 0 shares and shared disposition power over 3,232,500 shares. OppenheimerFunds, Inc.'s address is 225 Liberty Street, 11th Floor, New York, New York 10281, and Oppenheimer Capital Income Fund's address is 6803 Tucson Way, Centennial, Colorado 80112. |
19 |
As reported on the Schedule 13G filed February 11, 2005 by Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne. Kayne Anderson Capital Advisors, L.P. reports that in regard to Kinder Morgan Management, LLC shares, it has sole voting power over 0 shares, shared voting power over 3,815,712 shares, sole disposition power over 0 shares and shared disposition power over 3,815,712 shares. Mr. Anderson reports that in regard to Kinder Morgan Management, LLC shares, he has sole voting power over 930 shares, shared voting power over 3,815,712 shares, sole disposition power over 930 shares and shared disposition power over 3,815,712 shares. Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne's address is 1800 Avenue of the Stars, Second Floor, Los Angeles, California 90067. |
43
Equity Compensation Plan Information
The following table sets forth information regarding Kinder Morgan Energy Partners, L.P.'s equity compensation plans as of January 31, 2005.
Number of
securities to be |
Weighted
average |
Number of
securities |
||||||||||
Plan category |
(a) |
(b) |
(c) |
|||||||||
Equity compensation plans approved by security holders |
- |
- |
- |
|||||||||
Equity compensation plans not approved by security holders |
95,900 |
$ 18.0755 |
55,400 |
|||||||||
Total | 95,900 |
55,400 |
||||||||||
======= |
======= |
|||||||||||
Item 13. Certain Relationships and Related Transactions.
General and Administrative Expenses
KMGP Services Company, Inc., a subsidiary of Kinder Morgan G.P., Inc., provides employees and Kinder Morgan Services LLC, our wholly owned subsidiary, provides centralized payroll and employee benefits services to us, Kinder Morgan G.P., Inc., Kinder Morgan Energy Partners, L.P. and Kinder Morgan Energy Partners, L.P.'s operating partnerships and subsidiaries (collectively, the "Group"). Employees of KMGP Services Company, Inc. are assigned to work for one or more members of the Group. The direct costs of all compensation, benefits expenses, employer taxes and other employer expenses for these employees are allocated and charged by Kinder Morgan Services LLC to the appropriate members of the Group, and the members of the Group reimburse for their allocated shares of these direct costs. There is no profit or margin charged by Kinder Morgan Services LLC to the members of the Group. The administrative support necessary to implement these payroll and benefits services is provided by the human resource department of Kinder Morgan, Inc., and the related administrative costs are allocated to members of the Group in accordance with existing expense allocation procedures. The effect of these arrangements is that each member of the Group bears the direct compensation and employee benefits costs of its assigned or partially assigned employees, as the case may be, while also bearing its allocable share of administrative costs. Pursuant to its limited partnership agreement, Kinder Morgan Energy Partners, L.P. provides reimbursement for its share of these administrative costs and such reimbursements will be accounted for as described above. Additionally, Kinder Morgan Energy Partners, L.P. reimburses us with respect to costs incurred or allocated to us in accordance with Kinder Morgan Energy Partners, L.P.'s limited partnership agreement, the delegation of control agreement among Kinder Morgan G.P., Inc., Kinder Morgan Energy Partners, L.P., us and others, and our limited liability company agreement.
Our named executive officers and other employees that provide management or services to both Kinder Morgan, Inc. and the Group are employed by Kinder Morgan, Inc. Additionally, other Kinder Morgan, Inc. employees assist in the operation of Kinder Morgan Energy Partners, L.P.'s Natural Gas Pipeline assets. These Kinder Morgan, Inc. employees' expenses are allocated without a profit component between Kinder Morgan, Inc. and the appropriate members of the Group.
44
Kinder Morgan Energy Partners, L.P. Distributions
Kinder Morgan G.P., Inc.
Kinder Morgan G.P., Inc. serves as the sole general partner of Kinder Morgan Energy Partners, L.P. Pursuant to their partnership agreements, Kinder Morgan G.P., Inc.'s general partner interests represent a 1% ownership interest in Kinder Morgan Energy Partners, L.P., and a direct 1.0101% ownership interest in each of Kinder Morgan Energy Partners, L.P.'s five operating partnerships. Collectively, Kinder Morgan G.P., Inc. owns an effective 2% interest in the operating partnerships, excluding incentive distributions rights as follows:
|
its 1.0101% direct general partner ownership interest (accounted for as minority interest in the consolidated financial statements of Kinder Morgan Energy Partners, L.P.); and |
|
its 0.9899% ownership interest indirectly owned via its 1% ownership interest in Kinder Morgan Energy Partners, L.P. |
As of December 31, 2004, Kinder Morgan G.P., Inc. owned 1,724,000 common units, representing approximately 0.83% of Kinder Morgan Energy Partners, L.P.'s outstanding limited partner units. Kinder Morgan Energy Partners, L.P.'s partnership agreement requires that it distribute 100% of available cash, as defined in the partnership agreement, to its 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 Kinder Morgan Energy Partners, L.P.'s cash receipts, including cash received by its 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 SFPP, L.P. in respect of its remaining 0.5% interest in SFPP, L.P.
Kinder Morgan G.P., Inc. is granted discretion by Kinder Morgan Energy Partners, L.P.'s partnership agreement, which discretion has been delegated to us, subject to the approval of Kinder Morgan G.P., Inc. in certain cases, to establish, maintain and adjust reserves for future operating expenses, debt service, maintenance capital expenditures, rate refunds and distributions for the next four quarters. These reserves are not restricted by magnitude, but only by type of future cash requirements with which they can be associated. When we determine Kinder Morgan Energy Partners, L.P.'s quarterly distributions, we consider current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level.
Kinder Morgan G.P., Inc. and owners of Kinder Morgan Energy Partners, L.P.'s common units and Class B units receive distributions in cash, while we, the sole owner of Kinder Morgan Energy Partners, L.P.'s i-units, receive distributions in additional i-units. The cash equivalent of distributions of i-units is treated as if it had actually been distributed for purposes of determining the distributions to Kinder Morgan G.P., Inc. Kinder Morgan Energy Partners, L.P. does not distribute cash to i-unit owners but retains the cash for use in its business.
Available cash is initially distributed 98% to Kinder Morgan Energy Partners, L.P.'s limited partners and 2% to Kinder Morgan G.P., Inc. These distribution percentages are modified to provide for incentive distributions to be paid to Kinder Morgan G.P., Inc. in the event that quarterly distributions to unitholders exceed certain specified targets.
Available cash for each quarter is distributed:
|
first, 98% to the owners of all classes of units pro rata and 2% to Kinder Morgan G.P., Inc. until the owners of all classes of units have received a total of $0.15125 per unit in cash or equivalent |
45
i-units for such quarter; | |
|
second, 85% of any available cash then remaining to the owners of all classes of units pro rata and 15% to Kinder Morgan G.P., Inc. until the owners of all classes of units have received a total of $0.17875 per unit in cash or equivalent i-units for such quarter; |
|
third, 75% of any available cash then remaining to the owners of all classes of units pro rata and 25% to Kinder Morgan G.P., Inc. until the owners of all classes of units have received a total of $0.23375 per unit in cash or equivalent i-units for such quarter; and |
|
fourth, 50% of any available cash then remaining to the owners of all classes of units pro rata, to owners of common units and Class B units in cash and to us, as the owner of i-units, in the equivalent number of i-units, and 50% to Kinder Morgan G.P., Inc. in cash. |
Incentive distributions are generally defined as all cash distributions paid to Kinder Morgan G.P., Inc. that are in excess of 2% of the aggregate amount of cash and i-units being distributed. Kinder Morgan G.P., Inc.'s declared incentive distributions for the years ended December 31, 2004, 2003 and 2002 were $390.7 million, $322.8 million and $267.4 million, respectively.
Kinder Morgan, Inc.
Kinder Morgan, Inc., through its subsidiary Kinder Morgan (Delaware), Inc., remains the sole stockholder of Kinder Morgan G.P., Inc. At December 31, 2004, Kinder Morgan, Inc. directly owned 8,838,095 common units and 5,313,400 Class B units, indirectly owned 5,517,640 common units owned by its consolidated affiliates, including Kinder Morgan G.P., Inc., and owned 15,135,460 of our shares, representing an indirect ownership interest of 15,135,460 Kinder Morgan Energy Partners, L.P.'s i-units. Together, these units represent approximately 16.8% of Kinder Morgan Energy Partners, L.P.'s outstanding limited partner units. Including both its general and limited partner interests in Kinder Morgan Energy Partners, L.P., at the 2004 distribution level, Kinder Morgan, Inc. received approximately 51% of all quarterly distributions from Kinder Morgan Energy Partners, L.P., of which approximately 41% is attributable to its general partner interest and 10% is attributable to its limited partner interest. The actual level of distributions Kinder Morgan, Inc. will receive in the future will vary with the level of distributions to the limited partners determined in accordance with Kinder Morgan Energy Partners, L.P.'s partnership agreement.
Kinder Morgan Management, LLC
We, as Kinder Morgan G.P., Inc.'s delegate, are the sole owner of Kinder Morgan Energy Partners, L.P.'s 54,157,641 i-units.
Operations
Kinder Morgan, Inc. or its subsidiaries operate and maintain for Kinder Morgan Energy Partners, L.P. the assets comprising Kinder Morgan Energy Partners, L.P.'s Natural Gas Pipelines business segment. Natural Gas Pipeline Company of America, a subsidiary of Kinder Morgan, Inc., operates Trailblazer Pipeline Company's assets under a long-term contract pursuant to which Trailblazer Pipeline Company incurs the costs and expenses related to Natural Gas Pipeline Company of America's operating and maintaining the assets. Trailblazer Pipeline Company provides the funds for capital expenditures. Natural Gas Pipeline Company of America does not profit from or suffer loss related to its operation of Trailblazer Pipeline Company's assets.
The remaining assets comprising Kinder Morgan Energy Partners, L.P.'s Natural Gas Pipelines business segment are operated under agreements between Kinder Morgan, Inc. and Kinder Morgan Energy
46
Partners, L.P. Pursuant to the applicable underlying agreements, Kinder Morgan Energy Partners, L.P. pays Kinder Morgan, Inc. either a fixed amount or actual costs incurred as reimbursement for the corporate general and administrative expenses incurred in connection with the operation of these assets. On January 1, 2003, Kinder Morgan, Inc. began operating additional pipeline assets, including Kinder Morgan Energy Partners, L.P.'s North System and Cypress Pipeline, which are part of Kinder Morgan Energy Partners, L.P.'s Products Pipelines business segment. The amounts paid to Kinder Morgan, Inc. for corporate general and administrative costs, including amounts related to Trailblazer Pipeline Company, were $8.8 million of fixed costs and $13.1 million of actual costs incurred for 2004, and $8.7 million of fixed costs and $10.8 million of actual costs incurred for 2003. Kinder Morgan Energy Partners, L.P. estimates the total reimbursement for corporate general and administrative costs to be paid to Kinder Morgan, Inc. in respect of all pipeline assets operated by Kinder Morgan, Inc. and its subsidiaries for Kinder Morgan Energy Partners, L.P. for 2005 will be approximately $24.7 million, which includes $5.5 million of fixed costs (adjusted for inflation) and $19.2 million of actual costs.
Kinder Morgan Energy Partners, L.P. believes the amounts paid to Kinder Morgan, Inc. for the services they provided each year fairly reflect the value of the services performed. However, due to the nature of the allocations, these reimbursements may not have exactly matched the actual time and overhead spent. Kinder Morgan Energy Partners, L.P. believes the fixed amounts that were agreed upon at the time the contracts were entered into were reasonable estimates of the corporate general and administrative expenses to be incurred by Kinder Morgan, Inc. and its subsidiaries in performing such services. Kinder Morgan Energy Partners, L.P. also reimburses Kinder Morgan, Inc. and its subsidiaries for operating and maintenance costs and capital expenditures incurred with respect to these assets.
From time to time in the ordinary course of business, Kinder Morgan Energy Partners, L.P. buys and sells pipeline and related services from Kinder Morgan, Inc. and its subsidiaries. Such transactions are conducted in accordance with all applicable laws and regulations and on an arms' length basis consistent with Kinder Morgan Energy Partners, L.P.'s policies governing such transactions.
Certain of Kinder Morgan Energy Partners, L.P.'s business activities expose Kinder Morgan Energy Partners, L.P. to risks associated with changes in the market price of natural gas, natural gas liquids, crude oil and carbon dioxide. Kinder Morgan Energy Partners, L.P. performs risk management activities that involve the use of energy financial instruments to reduce these risks and protect Kinder Morgan Energy Partners, L.P.'s profit margins. Kinder Morgan Energy Partners, L.P.'s risk management policies prohibit Kinder Morgan Energy Partners, L.P. from engaging in speculative trading. Commodity-related activities of Kinder Morgan Energy Partners, L.P.'s risk management group are monitored by Kinder Morgan Energy Partners, L.P.'s risk management committee, which is a separately designated standing committee comprised of eleven executive-level employees of Kinder Morgan, Inc. or KMGP Services Company, Inc. whose job responsibilities involve operations exposed to commodity market risk and other external risks in the ordinary course of business.
Other
Generally, we make all decisions relating to the management and control of Kinder Morgan Energy Partners, L.P.'s business. Kinder Morgan G.P., Inc. owns all of our voting securities and is our sole managing member. Kinder Morgan, Inc., through its wholly owned and controlled subsidiary Kinder Morgan (Delaware), Inc., owns all the common stock of Kinder Morgan G.P., Inc. Certain conflicts of interest could arise as a result of the relationships among Kinder Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc., Kinder Morgan, Inc. and us. The directors and officers of Kinder Morgan, Inc. have fiduciary duties to manage Kinder Morgan, Inc., including selection and management of its investments in its subsidiaries and affiliates, in a manner beneficial to the shareholders of Kinder Morgan, Inc. In general, we have a fiduciary duty to manage Kinder Morgan Energy Partners, L.P. in a manner beneficial to Kinder Morgan Energy Partners, L.P. unitholders. The partnership agreements for Kinder
47
Morgan Energy Partners, L.P. and its operating partnerships contain provisions that allow us to take into account the interests of parties in addition to Kinder Morgan Energy Partners, L.P. in resolving conflicts of interest, thereby limiting our fiduciary duty to Kinder Morgan Energy Partners, L.P. unitholders, as well as provisions that may restrict the remedies available to Kinder Morgan Energy Partners, L.P. unitholders for actions taken that might, without such limitations, constitute breaches of fiduciary duty.
The partnership agreements provide that in the absence of bad faith by us, the resolution of a conflict by us will not be a breach of any duties. The duty of the directors and officers of Kinder Morgan, Inc. to the shareholders of Kinder Morgan, Inc. may, therefore, come into conflict with our duties and the duties of our directors and officers to Kinder Morgan Energy Partners, L.P. unitholders. The Audit Committee of our board of directors will, at our request, review (and is one of the means for resolving) conflicts of interest that may arise between Kinder Morgan, Inc. or its subsidiaries, on the one hand, and Kinder Morgan Energy Partners, L.P., on the other hand.
Item 14. Principal Accounting Fees and Services.
The following sets forth fees billed for the audit and other services provided by PricewaterhouseCoopers LLP to us for the fiscal years ended December 31, 2004, and December 31, 2003:
Year Ended December 31, |
|||
2004 |
2003 |
||
(In dollars) |
|||
Audit fees1 | $ 171,000 |
$ 72,667 |
|
Total |
$ 171,000 |
$ 72,667 |
|
========== |
========== |
1 | Includes fees for audit of annual financial statements, reviews of the related quarterly financial statements and reviews of documents filed with the Securities and Exchange Commission. |
All services rendered by PricewaterhouseCoopers LLP are permissible under applicable laws and regulations, and are pre-approved by our audit committee. Pursuant to the charter of our audit committee, the committee's primary purposes include the following:
|
to select, appoint, engage, oversee, retain, evaluate and terminate our external auditors; |
|
to pre-approve all audit and non-audit services, including tax services, to be provided, consistent with all applicable laws, to us by our external auditors; and |
|
to establish the fees and other compensation to be paid to our external auditors. |
Furthermore, the audit committee will review the external auditors' proposed audit scope and approach as well as the performance of the external auditors. It also has direct responsibility for and sole authority to resolve any disagreements between our management and our external auditors regarding financial reporting, will regularly review with the external auditors any problems or difficulties the auditors encountered in the course of their audit work, and will, at least annually, use its reasonable efforts to obtain and review a report from the external auditors addressing the following (among other items):
|
the auditors' internal quality-control procedures; |
|
any material issues raised by the most recent internal quality-control review, or peer review, of the external auditors; |
|
the independence of the external auditors; and |
|
the aggregate fees billed by our external auditors for each of the previous two fiscal years. |
48
Item 15. Exhibits and Financial Statement Schedules.
(a) 1. |
Financial Statements |
Reference is made to the index of financial statements and supplementary data under Item 8 in Part II.
2. |
Financial Statement Schedules |
The financial statements of Kinder Morgan Energy Partners, L.P., an equity method investee of the Registrant, are incorporated herein by reference from pages 101 through 181 of Kinder Morgan Energy Partners, L.P.'s Annual Report on Form 10-K for the year ended December 31, 2004.
KINDER MORGAN MANAGEMENT, LLC AND SUBSIDIARY
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
We have no valuation or qualifying accounts subject to disclosure in Schedule II.
3. |
Exhibits |
Exhibit |
Description |
3.1 |
Form of Certificate of Formation of the Company (filed as Exhibit 3.1 to the Company's Registration Statement on Form S-1 (Registration No. 333-55868) and incorporated by reference herein). |
|
|
3.2 |
Second Amended and Restated Limited Liability Company Agreement of the Company (filed as Exhibit 4.2 to the Company's Registration Statement on Form 8-A/A filed on July 24, 2002 and incorporated by reference herein). |
|
|
4.1 |
Form of certificate representing shares of the Company (filed as Exhibit 4.3 to the Company's Registration Statement on Form 8-A/A filed on July 24, 2002 and incorporated by reference herein). |
|
|
4.2 |
Form of Purchase Provisions between the Company and Kinder Morgan, Inc. (included as Annex B to the Second Amended and Restated Limited Liability Company Agreement filed as Exhibit 4.2 to the Company's Registration Statement on Form 8-A/A filed on July 24, 2002 and incorporated by reference herein). |
|
|
4.3 |
Registration Rights Agreement dated May 18, 2001 among the Company, Kinder Morgan Energy Partners, L.P. and Kinder Morgan, Inc. (Exhibit 4.3 to the Company's Annual Report on Form 10-K for the year ended December 31, 2002). |
|
|
10.1 |
Form of Tax Indemnity Agreement between the Company and Kinder Morgan, Inc. (filed as Exhibit 10.1 to the Company's Registration Statement on Form S-1 (Registration No. 333-55868) and incorporated by reference herein). |
|
|
10.2 |
Delegation of Control Agreement among Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan Energy Partners, L.P. and its operating partnerships (filed as Exhibit 10.1 to the Kinder Morgan Energy Partners, L.P. June 30, 2001 Form 10-Q (Commission File No. 1-11234)). |
49
10.3 |
Resignation and Non-Compete Agreement, dated as of July 21, 2004, between KMGP Services, Inc. and Michael C. Morgan (Exhibit 10.4 to Kinder Morgan Management, LLC's Quarterly Report on Form 10-Q for the quarter ended June 30, 2004). |
|
|
21.1* |
List of Subsidiaries. |
|
|
23.1* |
Consent of PricewaterhouseCoopers LLP. |
|
|
31.1* |
Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
31.2* |
Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
32.1* |
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
32.2* |
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
__________ * Filed herewith. |
50
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
KINDER
MORGAN MANAGEMENT, LLC (Registrant) |
||
By | /s/ C. Park Shaper | |
C. Park Shaper Executive Vice President and Chief Financial Officer |
||
Date: March 4, 2005 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities set forth below and as of the date set forth above.
/s/ Richard D. Kinder | Director, Chairman, Chief Executive Officer | |
Richard D. Kinder | and President (Principal Executive Officer) | |
/s/ Edward O. Gaylord | Director | |
Edward O. Gaylord | ||
/s/ Gary L. Hultquist | Director | |
Gary L. Hultquist | ||
/s/ C. Park Shaper | Director, Executive Vice President and Chief Financial | |
C. Park Shaper | Officer (Principal Financial and Accounting Officer) | |
/s/ Perry M. Waughtal | Director | |
Perry M. Waughtal | ||
51
UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 --------------- Form 10-K [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2004 Or [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to Commission file number: 1-11234 Kinder Morgan Energy Partners, L.P. (Exact name of registrant as specified in its charter) Delaware 76-0380342 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 500 Dallas, Suite 1000, Houston, Texas 77002 (Address of principal executive offices)(zip code) Registrant's telephone number, including area code: 713-369-9000 --------------- Securities registered pursuant to Section 12(b) of the Act: Title of each class Name of each exchange on which registered ------------------- ----------------------------------------- Common Units New York Stock Exchange Securities registered Pursuant to Section 12(g) of the Act: None Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] Indicate by check mark whether the registrant is an accelerated filer (as defined by Rule 12b-2 of the Securities Exchange Act of 1934). Yes [X] No [ ] Aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant, based on closing prices in the daily composite list for transactions on the New York Stock Exchange on June 30, 2004 was approximately $5,153,909,088. As of January 31, 2005, the registrant had 147,555,658 Common Units outstanding. 1 <PAGE> KINDER MORGAN ENERGY PARTNERS, L.P. TABLE OF CONTENTS Page Number PART I Items 1 and 2. Business and Properties....................... 3 Overview...................................... 3 General Development of Business............... 3 History...................................... 4 Business Strategy............................ 4 Recent Developments.......................... 7 Financial Information about Segments.......... 10 Narrative Description of Business............. 10 Products Pipelines........................... 10 Natural Gas Pipelines........................ 22 CO2.......................................... 29 Terminals.................................... 32 Major Customers............................... 39 Regulation.................................... 39 Environmental Matters......................... 42 Risk Factors.................................. 45 Other......................................... 50 Financial Information about Geographic Areas.. 51 Available Information......................... 51 Item 3. Legal Proceedings.............................. 51 Item 4. Submission of Matters to a Vote of Security Holders....................................... 51 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities................ 52 Item 6. Selected Financial Data........................ 53 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations................................. 55 Critical Accounting Policies and Estimates.... 55 Results of Operations......................... 57 Liquidity and Capital Resources............... 70 Recent Accounting Pronouncements.............. 79 Information Regarding Forward-Looking Statements................................... 79 Item 7A. Quantitative and Qualitative Disclosures About Market Risk............................. 81 Energy Financial Instruments.................. 81 Interest Rate Risk............................ 82 Item 8. Financial Statements and Supplementary Data.... 83 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure........ 83 Item 9A. Controls and Procedures........................ 83 Item 9B. Other Information.............................. 84 PART III Item 10. Directors and Executive Officers of the Registrant.................................... 85 Directors and Executive Officers of our General Partner and the Delegate......... 85 Corporate Governance......................... 87 Section 16(a) Beneficial Ownership Reporting Compliance........................ 88 Item 11. Executive Compensation......................... 88 Item 12. Security Ownership of Certain Beneficial Owners and Management......................... 94 Item 13. Certain Relationships and Related Transactions.................................. 96 Item 14. Principal Accounting Fees and Services......... 96 PART IV Item 15. Exhibits and Financial Statement Schedules..... 98 Index to Financial Statements.................. 101 Signatures..................................................... 188 2 <PAGE> PART I Items 1 and 2. Business and Properties. Overview Kinder Morgan Energy Partners, L.P., a Delaware limited partnership, is a publicly traded limited partnership that was formed in August 1992. We are one of the largest publicly-traded pipeline limited partnerships in the United States in terms of market capitalization and we own the largest independent refined petroleum products pipeline system in the United States in terms of volumes delivered. Unless the context requires otherwise, references to "we," "us," "our," "KMP" or the "Partnership" are intended to mean Kinder Morgan Energy Partners, L.P., our subsidiary operating limited partnerships and their subsidiaries. The address of our principal executive offices is 500 Dallas, Suite 1000, Houston, Texas 77002, and our telephone number at this address is (713) 369-9000. Our common units trade on the New York Stock Exchange under the symbol "KMP." You should read the following discussion and analysis in conjunction with our consolidated financial statements included elsewhere in this report. (a) General Development of Business We focus on providing fee-based services to customers and creating value for our unitholders primarily through the following activities: o transporting, storing and processing refined petroleum products; o transporting, storing and selling natural gas; o producing, transporting and selling carbon dioxide for use in, and selling crude oil produced from, enhanced oil recovery operations; and o transloading, storing and delivering a wide variety of bulk, petroleum and petrochemical products at terminal facilities located across the United States. Our operations are conducted through our subsidiary operating limited partnerships and their subsidiaries. While we conduct these operations, we focus on generally avoiding commodity price risks and maximizing the benefits of our characterization as a partnership for federal income tax purposes. The portfolio of businesses we own or operate are grouped into four reportable business segments according to the services we provide and how our management makes decisions about allocating resources and measuring financial performance. These segments are as follows: o Products Pipelines. Delivers gasoline, diesel fuel, jet fuel and natural gas liquids to various markets through over 10,000 miles of products pipelines and 60 associated terminals serving customers across the United States; o Natural Gas Pipelines. Transports, stores and sells natural gas over approximately 14,000 miles of natural gas transmission pipelines and gathering lines, plus natural gas gathering and storage facilities; o CO2. Produces, transports through pipelines and markets carbon dioxide, commonly called CO2, to oil fields that use CO2 to increase production of oil, owns interests in and/or operates six oil fields in West Texas, and owns and operates a crude oil pipeline system in West Texas; and o Terminals. Composed of approximately 75 owned or operated liquid and bulk terminal facilities and more than 55 rail transloading and materials handling facilities located throughout the United States. 3 <PAGE> History In February 1997, Kinder Morgan (Delaware), Inc., a Delaware corporation, acquired all of the issued and outstanding stock of our general partner, changed the name of our general partner to Kinder Morgan, G.P., Inc., and changed our name to Kinder Morgan Energy Partners, L.P. Since that time, our operations have experienced significant growth, and our net income has increased from $17.7 million for the year ended December 31, 1997, to $831.6 million for the year ended December 31, 2004. In October 1999, K N Energy, Inc., a Kansas corporation that provided integrated energy services, acquired Kinder Morgan (Delaware), Inc. At the time of the closing of this transaction, K N Energy, Inc. changed its name to Kinder Morgan, Inc., referred to in this report as KMI. In connection with the acquisition, Richard D. Kinder, Chairman and Chief Executive Officer of our general partner and its delegate (see below), became the Chairman and Chief Executive Officer of KMI. KMI trades on the New York Stock Exchange under the symbol "KMI" and is one of the largest energy transportation and storage companies in the United States, operating, either for itself or on our behalf, more than 35,000 miles of natural gas and products pipelines and approximately 135 terminals. As of December 31, 2004, KMI and its consolidated subsidiaries owned, through its general and limited partner interests, an approximate 18.5% interest in us. In addition to the distributions it receives from its limited and general partner interests, KMI also receives an incentive distribution from us as a result of its ownership of our general partner. This incentive distribution is calculated in increments based on the amount by which quarterly distributions to our unitholders exceed specified target levels as set forth in our partnership agreement, reaching a maximum of 50% of distributions allocated to the general partner for distributions above $0.23375 per limited partner unit per quarter. Including both its general and limited partner interests in us, at the 2004 distribution level, KMI received approximately 51% of all quarterly distributions from us, of which approximately 41% was attributable to its general partner interest and 10% was attributable to its limited partner interest. The actual level of distributions KMI will receive in the future will vary with the level of distributions to our limited partners determined in accordance with our partnership agreement. In February 2001, Kinder Morgan Management, LLC, a Delaware limited liability company referred to in this report as KMR, was formed. Our general partner owns all of KMR's voting securities and, pursuant to a delegation of control agreement, our general partner delegated to KMR, to the fullest extent permitted under Delaware law and our partnership agreement, all of its power and authority to manage and control our business and affairs, except that KMR cannot take certain specified actions without the approval of our general partner. Under the delegation of control agreement, KMR, as the delegate of our general partner, manages and controls our business and affairs and the business and affairs of our operating limited partnerships and their subsidiaries. Furthermore, in accordance with its limited liability company agreement, KMR's activities are limited to being a limited partner in, and managing and controlling the business and affairs of us, our operating limited partnerships and their subsidiaries. In May 2001, KMR issued 2,975,000 of its shares representing limited liability company interests to KMI and 26,775,000 of its shares to the public in an initial public offering. The shares trade on the New York Stock Exchange under the symbol "KMR." KMR became a limited partner in us by using substantially all of the net proceeds from that offering to purchase i-units from us. The i-units are a separate class of limited partner interests in us and are issued only to KMR. Under the terms of our partnership agreement, the i-units are entitled to vote on all matters on which the common units are entitled to vote. In general, our limited partner units, consisting of i-units, common units and Class B units (the Class B units are similar to our common units except that they are not eligible for trading on the New York Stock Exchange), will vote together as a single class, with each i-unit, common unit, and Class B unit having one vote. We pay our quarterly distributions from operations and from interim capital transactions to KMR in additional i-units rather than in cash. As of December 31, 2004, KMR, through its ownership of our i-units, owned approximately 26.2% of all of our outstanding limited partner units. Business Strategy The objective of our business strategy is to grow our portfolio of businesses by: o providing, for a fee, transportation, storage and handling services which are core to the energy infrastructure of growing markets; 4 <PAGE> o increasing utilization of our assets while controlling costs by: o operating classic fixed-cost businesses with relatively little variable costs; and o improving productivity to drop top-line growth to the bottom line; o leveraging economies of scale from incremental acquisitions and expansions principally by: o reducing overhead; and o eliminating duplicate costs in core operations; and o maximizing the benefits of our financial structure, which allows us to: o minimize the taxation of net income, thereby increasing distributions from our high cash flow businesses; and o maintain a strong balance sheet, thereby allowing flexibility when raising capital for acquisitions and/or expansions. Primarily, our business model consists of a solid asset base designed and operated to generate stable, fee-based income and distributable cash flow that together provides overall long-term value to our unitholders. Generally, as utilization of our pipelines and terminals increases, our fee-based revenues increase. We do not face significant risks relating directly to short-term movements in commodity prices for two principal reasons. First, we primarily transport and/or handle products for a fee and are not engaged in significant unmatched purchases and resales of commodity products. Second, in those areas of our business, primarily oil production in our CO2 business segment, where we do face exposure to fluctuations in commodity prices, we engage in a hedging program to mitigate this exposure. The business strategies of our four business segments are as follows: o Products Pipelines. We plan to continue to expand our presence in the growing refined petroleum products markets in the western and southeastern United States through incremental pipeline expansions and through strategic pipeline and terminal acquisitions that we believe will enhance our ability to serve our customers while increasing distributable cash flow. On systems serving relatively mature markets, such as our North System, we intend to focus on increasing product throughput by continuing to increase the range of products transported and services offered while remaining a reliable, cost-effective provider of transportation services; o Natural Gas Pipelines. We intend to grow our Texas intrastate natural gas transportation and storage businesses by identifying and serving significant new customers with demand for capacity on our pipeline systems and reducing volatility through long-term agreements. On our Rocky Mountain natural gas pipeline systems, our goals are to continue to operate our existing operations efficiently, to continue to meet our customers' needs and to capitalize on expansion and growth opportunities in moving natural gas out of the Rocky Mountain region. Red Cedar Gas Gathering Company, our partnership with the Southern Ute Indian Tribe, is pursuing additional gathering opportunities on tribal lands. Overall, we will continue to explore expansion and storage opportunities to increase utilization levels throughout our natural gas pipeline operations; o CO2. Our carbon dioxide sales and transportation business has two primary strategies. First, we seek to increase the utilization of our carbon dioxide supply and transportation assets by providing a full range of supply, transportation and technical support services to third party customers. As a service provider, our strategy is to offer customers "one-stop shopping" for carbon dioxide supply, transportation and technical support service. Second, we seek to increase the economic benefits from our oil and gas production activities by increasing oil field carbon dioxide flooding, efficiently managing oil field operating expenses, and capturing downstream value in assets which complement our oil field operations. In our oil and gas 5 <PAGE> production business, we plan to grow production from our interests in oil fields located in the Permian Basin of West Texas by increasing our use of carbon dioxide in enhanced oil recovery projects. We intend to compete for new supply and transportation projects, both inside and outside the Permian Basin, including the acquisition of attractive carbon dioxide injection projects that would further increase the demand for our carbon dioxide reserves and utilization of our carbon dioxide supply and pipeline assets. Our management believes these projects will arise as other oil producing basins mature and make the transition from primary production to enhanced recovery methods; and o Terminals. We are dedicated to growing our terminals segment through a core strategy which includes dedicating capital to expand existing facilities, maintaining a strong commitment to operational safety and efficiency, and growing through strategic acquisitions. The bulk terminals industry in the United States is highly fragmented, leading to opportunities for us to make selective, accretive acquisitions. In addition to efforts to expand and improve our existing terminals, we plan to design, construct and operate new facilities for current and prospective customers. Our management believes we can use newly acquired or developed facilities to leverage our operational expertise and customer relationships. In addition, we believe our experience and expertise in managing and operating our liquids and bulk terminals businesses in an integrated manner gives us an advantage in pursuing acquisitions of terminals that handle both bulk and liquid materials. To accomplish our strategy, we will continue to rely on the following three-pronged approach: o Cost Reductions. We continue to seek greater productivity and cost savings by focusing on the efficiencies of our operations and the related incurrence of associated operating, maintenance, and general and administrative expenses. In addition, we have made reductions in the operating, maintenance, and general and administrative expenses of many of the businesses and assets that we have acquired. Generally, these reductions in expense have been achieved by eliminating duplicative functions that we and the acquired businesses each maintained prior to their combination; o Internal Growth. We intend to grow income from our current assets both through increased utilization of existing assets, and through internal expansion projects. We primarily operate classic fixed cost businesses with relatively little variable costs. By controlling variable costs, any increase in utilization of our pipelines and terminals generally results in an increase in income. Increases in utilization are principally driven by increases in demand for gasoline, jet fuel, natural gas and other energy products and bulk materials that we transport, store or handle. Increases in demand for these products are typically driven by demographic growth in markets we serve, including the rapidly growing western and southeastern United States. In addition, we have undertaken a number of expansion projects that we believe will increase revenues from existing operations; and o Strategic Acquisitions. We regularly seek opportunities to make additional strategic acquisitions, to expand existing businesses and to enter into related businesses. We regularly consider and enter into discussions regarding potential acquisitions, including those from KMI or its affiliates, and are currently contemplating potential acquisitions. While there are currently no unannounced purchase agreements for the acquisition of any material business or assets, such transactions can be effected quickly, may occur at any time and may be significant in size relative to our existing assets or operations. We anticipate financing acquisitions by borrowings under our bank credit facility or by issuing commercial paper, and subsequently reducing these short-term borrowings by issuing new long-term debt securities, common units and/or i-units to KMR. For more information on the costs and methods of financing for each of our 2004 acquisitions, see "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Capital Requirements for Recent Transactions" included elsewhere in this report. Achieving success in implementing our strategy will depend partly on the following characteristics of our management's philosophy: o Low cost asset operator and attention to detail. An important element of our strategy to improve unitholder value is controlling costs whenever possible. We believe that our overall cost and expense infrastructure has been improved by numerous simplification and transformation efforts. We continue to focus on improving employee and process productivity in order to create a more efficient expense structure while, at the same 6 <PAGE> time, we focus on providing the highest level of expertise and uncompromising service to our customers. We have recognized for years the need to have an unwavering commitment to safety, and we employ full-time safety professionals to provide training and awareness through ongoing programs for our employees, especially those working with hazardous materials at our pipeline and terminal facilities; o Risk Management. We avoid businesses with direct commodity price exposure wherever possible, and we hedge incidental commodity price risk. In the normal course of business, we are exposed to risks associated with changes in the market price of energy products; however, we attempt to limit these risks by following established risk management policies and procedures, including the use of energy financial instruments, also known as derivatives. Our risk management process also includes identifying the areas in our operations where assets are at risk of loss and areas where exposures exist to third-party liabilities. Our management strives to recognize and insure against such risk; and o Alignment of incentives. Whenever possible, we align the compensation of our management and employees with the interests of our unitholders. Under the Kinder Morgan Savings Plan, a defined contribution 401(k) plan, all full-time employees of KMI and KMGP Services Company, Inc. (the entities that employ all persons necessary for the operation of our business) can contribute between 1% and 50% of base compensation, on a pre-tax basis, into participant accounts. In addition to a mandatory contribution equal to 4% of base compensation per year for most plan participants, our general partner may make discretionary contributions in years when specific performance objectives are met. All employer 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. Furthermore, KMI's ten most senior executives (excluding Mr. Kinder, who receives $1 per year in salary and receives no bonus) have their base salaries capped at $200,000 per year and are not eligible for stock options, but instead are eligible to receive grants of KMI restricted stock. Additionally, all employees, including the most senior executives, are eligible for annual bonuses when KMI and we meet annual earnings per share and distributions per unit targets. Recent Developments The following is a brief listing of significant developments since December 31, 2003. Additional information regarding most of these items may be found elsewhere in this report. o On February 9, 2004, we completed a public offering of an additional 5,300,000 of our common units at a price of $46.80 per unit, less commissions and underwriting expenses. We received net proceeds of $237.8 million for the issuance of these common units and we used the proceeds to reduce the borrowings under our commercial paper program; o Effective March 9, 2004, we acquired seven refined petroleum products terminals in the southeastern United States from Exxon Mobil Corporation for an aggregate consideration of approximately $50.9 million, consisting of $48.2 million in cash and the assumption of $2.7 million of liabilities. In addition, as part of the transaction, ExxonMobil entered into a long-term contract to store refined petroleum products at the terminals. As of our acquisition date, we expected to invest an additional $1.2 million in the facilities in the near-term following acquisition. The terminals are located in Collins, Mississippi; Knoxville, Tennessee; Charlotte and Greensboro, North Carolina; and Richmond, Roanoke and Newington, Virginia. Combined, the terminals have a total storage capacity of approximately 3.2 million barrels for gasoline, diesel fuel and jet fuel; o On March 26, 2004, the Federal Energy Regulatory Commission issued an order on the phase one initial decision that was issued on June 24, 2003 by an administrative law judge hearing a case on the rates charged by our Pacific operations' interstate portion of its pipelines. We believe the Energy Policy Act of 1992 "grandfathered" most of our Pacific operations' interstate rates, deeming them lawful. However, pursuant to rate challenges made by certain shippers, the administrative law judge recommended that the FERC "ungrandfather" our Pacific operations' interstate rates. The FERC's phase one order reversed the initial decision by finding that our Pacific operations' rates for its North and Oregon Lines should remain "grandfathered" and amended the initial decision by finding that SFPP's West Line rates (i) to Yuma and Tucson, Arizona and to our CALNEV Pipeline, as of 1995, and (ii) to Phoenix, Arizona, as of 1997, should 7 <PAGE> no longer be "grandfathered" and are not just and reasonable. If these rates are "ungrandfathered," they could be lowered prospectively and complaining shippers could be entitled to reparations for prior periods. Both SFPP and certain shippers have appealed the FERC's decision to the United States Court of Appeals for the District of Columbia; o On June 1, 2004, we commenced service on our Kinder Morgan Interstate Gas Transmission LLC's Cheyenne Market Center. This $28.4 million project involved the construction of pipeline, compression and storage facilities to accommodate an additional six billion cubic feet of natural gas storage capacity, which has been fully subscribed under 10-year contracts. The Cheyenne Market Center offers firm natural gas storage capabilities that allow for the receipt, storage and subsequent re-delivery of natural gas supplies at applicable points located in the vicinity of the Cheyenne Hub in Weld County, Colorado and our Huntsman storage facility in Cheyenne County, Nebraska; o On July 13, 2004, we announced that we had commenced service on our 135-mile natural gas pipeline segment which extends from an intersection with our Kinder Morgan Texas Pipeline system just west of Katy, Texas to the west side of Austin, Texas. The $30 million project included the December 2003 acquisition of the pipeline, the subsequent conversion of the pipeline from crude oil to natural gas service, and the construction of a 5-mile pipeline lateral to serve a municipal power plant located in Austin, Texas. The pipeline adds approximately 170 dekatherms per day of natural gas to the Austin market and is supported by long-term contracts with local utilities; o On August 18, 2004, we entered into a new five-year unsecured revolving credit facility with a total commitment of $1.25 billion. The new facility expires on August 18, 2009, and replaced our 364-day and three-year facilities, which had total commitments of $1.05 billion. The five-year facility will result in benefits over our prior credit facilities, including lower annual fees, reduced pricing and rollover risk, and lower administrative costs. Our credit covenants remained substantially unchanged as compared to the previous facilities, with the only meaningful modification being the removal of any net worth restriction. The facility primarily serves as a backup to our commercial paper program, which had $416.9 million outstanding as of December 31, 2004; o Effective August 31, 2004, we acquired all of the partnership interests in Kinder Morgan Wink Pipeline, L.P., formerly Kaston Pipeline Company, L.P., from KPL Pipeline Company, LLC and RHC Holdings, L.P. for an aggregate consideration of approximately $100.3 million, consisting of $89.9 million in cash and the assumption of $10.4 million of liabilities. The acquisition included a 450-mile crude oil pipeline system, consisting of four mainline sections, numerous gathering systems and truck off-loading stations. The mainline sections, all in the State of Texas, have a total capacity of 115,000 barrels of crude oil per day. As part of the transaction, we entered into a long-term throughput agreement with Western Refining Company, L.P. to transport crude oil into Western's 107,000 barrel per day refinery in El Paso, Texas. As of the acquisition date, we expected to invest approximately $11.0 million over the next five years to upgrade the assets; o On September 9, 2004, a non-binding, phase two initial decision was issued by an administrative law judge hearing the FERC case on the rates charged by our Pacific operations' interstate portion of its pipelines. If affirmed by the FERC, the phase two initial decision would establish the basis for prospective rates and the calculation of reparations for complaining shippers with respect to our Pacific operations' West Line and East Line. However, as with the phase one initial decision, issued on June 24, 2003, the phase two initial decision has no force or effect and must be fully reviewed by the FERC, which may accept, reject or modify the decision. A FERC order on phase two of the case is not expected before the third quarter of 2005. Furthermore, any such order may be subject to further FERC review, review by the United States Court of Appeals for the District of Columbia Circuit, or both; o Effective October 1, 2004, we acquired an additional undivided 5% interest in the Cochin Pipeline System from a subsidiary of ConocoPhillips Corporation for approximately $10.9 million. We record our 49.8% proportionate share of the results of operations of the Cochin Pipeline System as part of our Products Pipelines business segment; 8 <PAGE> o Effective October 6, 2004, we acquired Kinder Morgan River Terminals LLC, formerly Global Materials Services LLC, from Mid-South Terminal Company, L.P. for an aggregate consideration of approximately $89.6 million, consisting of $31.8 million in cash and $57.8 million of assumed liabilities. Kinder Morgan River Terminals LLC operates a network of 21 river terminals and two rail transloading facilities primarily located along the Mississippi River system. The network provides loading, storage and unloading points for various bulk commodity imports and exports. As of the acquisition date, we expected to invest an additional $9.4 million over the next two years to expand and upgrade the terminals, which are located in 11 Mid-Continent states; o On October 13, 2004, we announced that Shell Trading (U.S.) Company had assumed ownership of the processing rights at our transmix facilities located in Richmond, Virginia; Indianola, Pennsylvania; and Wood River, Illinois. In a transaction that closed on September 30, 2004, Shell Trading purchased the eastern transmix trading business formerly owned by Duke Energy Merchants LLC, which included a transmix processing agreement with us effective through March 16, 2011; o Effective November 1, 2004, we acquired all of the partnership interests in TransColorado Gas Transmission Company from two wholly-owned subsidiaries of KMI. TransColorado Gas Transmission Company is a Colorado general partnership and, at the date of acquisition, owned assets of approximately $284.5 million. As consideration for TransColorado, we paid to KMI $211.2 million in cash and assumed liabilities of approximately $9.3 million. In addition, we issued 1,400,000 common units having a market value of approximately $64 million to KMI. TransColorado owns a 300-mile interstate natural gas pipeline that originates in the Piceance Basin of western Colorado and extends to the Blanco Hub in northwest New Mexico, providing a strategic link to the southwestern United States and other key markets; o Effective November 5, 2004, we acquired ownership interests in nine refined petroleum products terminals in the southeastern United States from Charter Terminal Company and Charter-Triad Terminals, LLC for an aggregate consideration of approximately $75.2 million, consisting of $72.4 million in cash and $2.8 million of assumed liabilities. Three terminals are located in Selma, North Carolina, and the remaining facilities are located in Greensboro and Charlotte, North Carolina; Chesapeake and Richmond, Virginia; Athens, Georgia; and North Augusta, South Carolina. We fully own seven of the terminals and jointly own the remaining two. The nine facilities have a combined 3.2 million barrels of storage. As of the acquisition date, we expected to invest an additional $2 million over the next two years to upgrade the facilities. All of the terminals are connected to products pipelines owned by either Plantation Pipe Line Company or Colonial Pipeline Company, and the acquisition will increase our southeast terminal storage capacity 76% (to 7.7 million barrels) and terminal throughput capacity 62% (to over 340,000 barrels per day); o On November 10, 2004, we completed a public offering of 5,500,000 of our common units at a price of $46.00 per unit, less commissions and underwriting expenses. On December 8, 2004, we issued an additional 575,000 units upon the exercise by the underwriters of an over-allotment option. We received net proceeds of $268.3 million for the issuance of these 6,075,000 common units. At approximately the same time as our November public offering, KMR issued 1,300,000 of its shares at a price of $41.29 per share, less closing fees and commissions. The net proceeds from the offering were used by KMR to buy additional i-units from us, and we received net proceeds of $52.6 million for the issuance of 1,300,000 i-units. We used the proceeds from each of these three issuances to reduce the borrowings under our commercial paper program; o On November 12, 2004, we closed a public offering of $500 million in principal amount of 5.125% senior notes due November 15, 2014. The proceeds to us from the issuance of the notes, after underwriting discounts and commissions, were approximately $496.3 million, which we used to reduce commercial paper debt; o Effective December 1, 2004, we acquired substantially all of the assets used to operate the major port distribution facility located at the Fairless Industrial Park in Bucks County, Pennsylvania. The aggregate cost of the acquisition was approximately $7.5 million, consisting of $7.2 million in cash and $0.3 million in assumed liabilities. The bulk terminal facility is located on the Delaware River and is the largest port on the East Coast for the handling of semi-finished steel slabs, which are used as feedstock by domestic steel mills. The facility, referred to as our Kinder Morgan Fairless Hills Terminal, was purchased from Novolog Bucks 9 <PAGE> County, Inc. The port operations at Fairless Hills also include the handling of other types of steel and specialized cargo that caters to the construction industry and service centers that use steel sheet and plate. As of the acquisition date, we expected to invest an additional $8.3 million in the facility; o On December 8, 2004, we announced that we expect to declare cash distributions of $3.13 per unit for 2005, a 9% increase over our cash distributions of $2.87 per unit for 2004. This expectation includes contributions from assets owned by us as of the announcement date and does not include any projected benefits from unidentified acquisitions; o On December 15, 2004, we announced the start of service on our new $95 million, 70-mile, 20-inch replacement common carrier refined petroleum products pipeline between Concord and Sacramento, California. This project included replacing an existing 14-inch diameter refined products pipeline with a new 20-inch diameter line and rerouting portions of the pipeline away from environmentally sensitive areas and residential neighborhoods. The capital expansion project significantly increases the capacity on the pipeline and provides the necessary infrastructure to help meet the region's growing demand for gasoline, diesel and jet fuel. Capacity on the new pipeline is approximately 167,000 barrels per day, and with additional pumping capability, maximum capacity could increase to over 200,000 barrels per day; o During 2004, we spent $747.3 million for additions to our property, plant and equipment, including both expansion ($628.0 million) and maintenance projects ($119.3 million). Our capital expenditures included the following: o $302.9 million in our CO2 segment, mostly related to additional infrastructure, including wells, injection and compression facilities, to support the expanding carbon dioxide flooding operations at the SACROC and Yates oil field units in West Texas; o $213.8 million in our Products Pipelines segment, mostly related to expansion work on our Pacific operations' Concord to Sacramento, California products pipeline, the expansion of our Pacific operations' East Line products pipeline, described above, and to a storage and expansion project at our combined Carson/Los Angeles Harbor terminal system in the State of California; o $124.2 million in our Terminals segment, largely related to expanding the petroleum products storage capacity at our liquid terminal facility located in Carteret, New Jersey and the construction of a cement facility at our Dakota bulk terminal located in St. Paul, Minnesota, as well as other smaller projects; and o $106.4 million in our Natural Gas Pipelines segment, mostly related to completing the construction and start up of our Cheyenne Market Center and our Katy to Austin, Texas intrastate natural gas pipeline project, both described above; and o On February 24, 2005, we announced that we had received the necessary permits and approvals from the city of Carson, California, to construct new storage tanks as part of a major expansion of our West Coast petroleum products storage and transfer terminal located in Carson, California. The almost $40 million investment includes the addition of ten new tanks that will increase storage capacity at the facility by 800,000 barrels (16%) and help meet Southern California's growing demand for petroleum products. (b) Financial Information about Segments For financial information on our four reportable business segments, see Note 15 to our consolidated financial statements. (c) Narrative Description of Business Products Pipelines Our Products Pipelines segment consists of refined petroleum products and natural gas liquids pipelines, related terminals and transmix processing facilities, including: 10 <PAGE> o our Pacific operations, which include interstate common carrier pipelines regulated by the Federal Energy Regulatory Commission, intrastate pipelines in California regulated by the California Public Utilities Commission and certain non rate-regulated operations and terminal facilities. Specifically, our Pacific operations include: o our SFPP, L.P. operations, comprised of approximately 2,500 miles of pipelines that transport refined petroleum products to some of the fastest growing population centers in the United States, including Southern California; the San Francisco Bay Area; Las Vegas, Nevada (through our CALNEV Pipeline) and Phoenix and Tucson, Arizona, and 13 truck-loading terminals with an aggregate usable tankage capacity of approximately nine million barrels; o our CALNEV Pipeline operations, comprised of approximately 550-miles of pipelines that transport refined petroleum products from Colton, California to the growing Las Vegas, Nevada market, McCarran International Airport in Las Vegas, Nevada, and refined petroleum products terminals located in Barstow, California and Las Vegas, Nevada; and o our West Coast terminals operations, which are comprised of six terminal facilities on the West Coast that transload and store refined petroleum products; o our Central Florida Pipeline, two pipelines that total 195-miles and transport refined petroleum products from Tampa to the Orlando, Florida market and two refined petroleum products terminals at Tampa and Orlando, Florida; o our North System, a 1,600-mile pipeline system that transports natural gas liquids in both directions between south central Kansas and the Chicago area and various intermediate points, including eight terminals, and our 50% interest in the Heartland Pipeline Company, which ships refined petroleum products in the Midwest; o our 51% interest in Plantation Pipe Line Company, which owns the 3,100-mile Plantation pipeline system that transports refined petroleum products throughout the southeastern United States, serving major metropolitan areas including Birmingham, Alabama; Atlanta, Georgia; Charlotte, North Carolina; and the Washington, D.C. area; o our Kinder Morgan Southeast Terminals LLC, comprised of 23 refined petroleum products terminals acquired between December 2003 and November 2004; o our 49.8% interest in the Cochin Pipeline system, a 1,900-mile pipeline transporting natural gas liquids and traversing Canada and the United States from Fort Saskatchewan, Alberta to Sarnia, Ontario, including five terminals; o our Cypress Pipeline, a 104-mile pipeline transporting natural gas liquids from Mont Belvieu, Texas to a major petrochemical producer in Lake Charles, Louisiana; and o our Transmix operations, which include the processing of petroleum pipeline transmix (a blend of dissimilar refined petroleum products that have become co-mingled in the pipeline transportation process) through transmix processing plants in Colton, California; Richmond, Virginia; Dorsey Junction, Maryland; Indianola, Pennsylvania; and Wood River, Illinois. Pacific Operations Our Pacific operations' pipelines are split into a South Region and a North Region. Combined, the two regions consist of seven pipeline segments that serve six western states with approximately 3,100 miles of refined petroleum products pipeline and related terminal facilities. 11 <PAGE> Refined petroleum products and related uses are: Product Use --------- -------------------------------- Gasoline Transportation Diesel fuel Transportation (auto, rail, marine), agricultural, industrial and commercial Jet fuel Commercial and military air transportation Our Pacific operations transport over 1.1 million barrels per day of refined petroleum products, providing pipeline service to approximately 39 customer-owned terminals, nine commercial airports and 15 military bases. For 2004, the three main product types transported were gasoline (62%), diesel fuel (22%) and jet fuel (16%). Our Pacific operations also include 15 truck-loading terminals (13 on SFPP, L.P. and two on CALNEV). Our Pacific operations provide refined petroleum products to some of the fastest growing population centers in the United States, including California; Las Vegas and Reno, Nevada; and the Phoenix-Tucson, Arizona corridor. Pipeline transportation of gasoline and jet fuel generally has a direct correlation with demographic patterns. We believe that the population growth associated with the markets served by our Pacific operations will continue in the foreseeable future. South Region. Our Pacific operations' South Region consists of four pipeline segments: o West Line; o East Line; o San Diego Line; and o CALNEV Line. The West Line consists of approximately 670 miles of primary pipeline and currently transports products for 37 shippers from six refineries and three pipeline terminals in the Los Angeles Basin to Phoenix and Tucson, Arizona and various intermediate commercial and military delivery points. Product for the West Line can also come from foreign and domestic sources through the Los Angeles and Long Beach port complexes and the three pipeline terminals. A significant portion of West Line volumes is transported to Colton, California for local distribution and for delivery to our CALNEV Pipeline. The West Line serves our terminals located in Colton and Imperial, California as well as in Phoenix and Tucson, Arizona. The East Line is comprised of two parallel 8-inch diameter and 12-inch diameter pipelines originating in El Paso, Texas and continuing approximately 300 miles west to our Tucson terminal and one line continuing northwest approximately 130 miles from Tucson to Phoenix. All products received by the East Line at El Paso come from a refinery in El Paso or are delivered through connections with non-affiliated pipelines from refineries in Texas and New Mexico. The East Line serves our terminals located in Phoenix and Tucson as well as various intermediate commercial and military delivery points. We have embarked on a major expansion of this pipeline system. The expansion consists of replacing 160 miles of 8-inch diameter pipe between El Paso and Tucson and 84 miles of 8-inch diameter pipe between Tucson and Phoenix, with 16-inch and 12-inch diameter pipe, respectively. The project also includes the construction of a major origin pump station. The project is estimated to cost $210 million and is scheduled to be completed in the first quarter of 2006. The San Diego Line is a 135-mile pipeline serving major population areas in Orange County (immediately south of Los Angeles) and San Diego. The same refineries and terminals that supply the West Line also supply the San Diego Line. The San Diego Line serves our terminals at Orange and Mission Valley as well as shipper terminals in San Diego and San Diego Airport through a non-affiliated connecting pipeline. The CALNEV Line consists of two parallel 248-mile, 14-inch and 8-inch diameter pipelines from our facilities at Colton, California to Las Vegas, Nevada. It also includes approximately 55 miles of pipeline serving Edwards Air Force Base. CALNEV originates at Colton, California and serves two CALNEV terminals at Barstow, California and Las Vegas, Nevada. The CALNEV Pipeline also serves McCarran International Airport, Edwards Air Force 12 <PAGE> Base and Nellis Air Force Base, as well as certain smaller delivery points, including the Burlington Northern Santa Fe and Union Pacific railroad yards. North Region. Our Pacific operations' North Region consists of three pipeline segments: o the North Line; o the Bakersfield Line; and o the Oregon Line. The North Line consists of approximately 820 miles of trunk pipeline in five segments originating in Richmond and Concord, California. This line serves our terminals located in Brisbane, Sacramento, Chico, Fresno and San Jose, California, and Reno, Nevada. The products delivered through the North Line come from refineries in the San Francisco Bay Area and from various pipeline and marine terminals that deliver products from foreign and domestic ports. On December 15, 2004, we announced the start of service on our new $95 million, 70-mile, 20-inch replacement common carrier pipeline between Concord and Sacramento, California. The project included replacing the existing 14-inch diameter refined products pipeline with a new 20-inch diameter line and rerouting portions of the pipeline away from environmentally sensitive areas and residential neighborhoods. The capital expansion project increases the capacity on the pipeline from 119,000 barrels per day to 167,000 barrels per day, and with additional pumping capability, maximum capacity could increase to 200,000 barrels per day. The Bakersfield Line is a 100-mile, 8-inch diameter pipeline serving Fresno, California. The Oregon Line is a 114-mile pipeline serving 13 shippers. Our Oregon Line receives products from marine terminals in Portland, Oregon and from Olympic Pipeline. Olympic Pipeline is a non-affiliated pipeline that transports products from the Puget Sound, Washington area to Portland. From its origination point in Portland, the Oregon Line extends south and serves our terminal located in Eugene, Oregon. West Coast Terminals. These terminals are operated as part of our Pacific operations and include: o the Carson Terminal; o the Los Angeles Harbor Terminal; o the Richmond Terminal; o the Linnton and Willbridge Terminals; and o the Harbor Island Terminal. The West Coast terminals are fee-based terminals. They are located in several strategic locations along the west coast of the United States and have a combined total capacity of nearly eight million barrels of storage for both petroleum products and chemicals. The Carson terminal and the connected Los Angeles Harbor terminal are strategically located near the many refineries in the Los Angeles Basin. The combined Carson/LA Harbor system is connected to numerous other pipelines and facilities throughout the Los Angeles area, which gives the system significant flexibility and allows customers to quickly respond to market conditions. Storage at the Carson facility is primarily arranged via term contracts with customers, ranging from one to five years. Term contracts represent 52% of total revenues at the facility. The Richmond terminal is located in the San Francisco Bay Area. The facility serves as a storage and distribution center for chemicals, lubricants and paraffin waxes. It is also the principal location in northern California through which tropical oils are imported for further processing, and from which United States' produced 13 <PAGE> vegetable oils are exported to consumers in the Far East. The Linnton and Willbridge terminals are located in Portland, Oregon. These facilities handle petroleum products for distribution to both local and regional markets. Refined products are received by pipeline, marine vessel, barge, and rail car for distribution to local markets by truck; to southern Oregon via our Oregon Line; to Portland International Airport via a non-affiliated pipeline; and to eastern Washington and Oregon by barge. The Harbor Island terminal is located in Seattle, Washington. The facility is supplied via pipeline and barge from northern Washington-state refineries, allowing customers to distribute fuels economically to the greater Seattle-area market by truck. The terminal is the largest marine fuel oil storage facility in Puget Sound and also has a multi-component, in-line blending system for providing customized bunker fuels to the marine industry. Truck-Loading Terminals. Our Pacific operations include 15 truck-loading terminals (13 on SFPP, L.P. and two on CALNEV) with an aggregate usable tankage capacity of approximately ten million barrels. The truck terminals are located at most destination points on each of our Pacific operations' pipelines as well as some intermediate points along each pipeline. The simultaneous truck-loading capacity of each terminal ranges from two to 12 trucks. We provide the following services at these terminals: o short-term product storage; o truck-loading; o vapor handling; o deposit control additive injection; o dye injection; o oxygenate blending; and o quality control. The capacity of terminaling facilities varies throughout our Pacific operations. We charge a separate fee (in addition to pipeline tariffs) for these additional terminaling services. These fees are not regulated except for the fees at our CALNEV terminals. At certain locations, we make product deliveries to facilities owned by shippers or independent terminal operators. Markets. Currently our Pacific operations' pipeline system serves approximately 75 shippers in the refined products market, with the largest customers consisting of: o major petroleum companies; o independent refiners; o the United States military; and o independent marketers and distributors of refined petroleum products. A substantial portion of the product volume transported is gasoline. Demand for gasoline depends on such factors as prevailing economic conditions, vehicular use patterns and demographic changes in the markets served. If current trends continue, we expect the majority of our Pacific operations' markets to maintain growth rates that will exceed the national average for the foreseeable future. Currently, the California gasoline market is approximately 970,000 barrels per day. The Arizona gasoline market is served primarily by us at a market demand of approximately 121,000 barrels per day. Nevada's gasoline market is approximately 50,000 barrels per day and Oregon's is approximately 96,000 barrels per day. The diesel 14 <PAGE> and jet fuel market is approximately 560,000 barrels per day in California, 73,000 barrels per day in Arizona, 40,000 barrels per day in Nevada and 63,000 barrels per day in Oregon. We transport over 1.1 million barrels of petroleum products per day in these states. The volume of products transported is directly affected by the level of end-user demand for such products in the geographic regions served. Certain product volumes can experience seasonal variations and, consequently, overall volumes may be lower during the first and fourth quarters of each year. California mandated the elimination of MTBE (methyl tertiary-butyl ether) from gasoline by January 1, 2004. MTBE-blended gasoline has been replaced by ethanol-blended gasoline. Since ethanol cannot be shipped by pipeline, we are realizing a reduction in gasoline volumes delivered in California; however, our overall revenues were not adversely impacted as our terminals receive a fee to blend ethanol. Supply. The majority of refined products supplied to our Pacific operations' pipeline system come from the major refining centers around Los Angeles, San Francisco and Puget Sound, as well as waterborne terminals located near these refining centers. Competition. The most significant competitors of our Pacific operations' pipeline system are proprietary pipelines owned and operated by major oil companies in the area where our pipeline system delivers products as well as refineries with related trucking arrangements within our market areas. We believe that high capital costs, tariff regulation and environmental permitting considerations make it unlikely that a competing pipeline system comparable in size and scope to our Pacific operations will be built in the foreseeable future. However, the possibility of pipelines being constructed or expanded to serve specific markets is a continuing competitive factor. The use of trucks for product distribution from either shipper-owned proprietary terminals or from their refining centers continues to compete for short haul movements by pipeline. The mandated elimination of MTBE and required substitution of ethanol in California gasoline has resulted in at least a temporary increase in trucking distribution from shipper owned terminals. We cannot predict with any certainty whether the use of short haul trucking will decrease or increase in the future. Longhorn Partners Pipeline is a joint venture pipeline project that began transporting refined products from refineries on the Gulf Coast to El Paso and other destinations in Texas in late 2004. Increased product supply in the El Paso area could result in some shift of volumes transported into Arizona from our West Line to our East Line. Increased movements into the Arizona market from El Paso would currently displace higher tariff volumes supplied from Los Angeles on our West Line. However, our East Line is currently running at full capacity and we have plans to increase East Line capacity to meet market demand. The planned capacity increase will require significant investment which should, under the FERC cost of service methodology, result in a more balanced tariff between our East and West Lines. Such shift of supply sourcing has not had, and is not expected to have, a material effect on our operating results. Terminals owned by our Pacific operations also compete with terminals owned by our shippers and by third party terminal operators in numerous locations. Competing terminals are located in Reno, Sacramento, San Jose, Stockton, Colton, Orange County, Mission Valley, and San Diego, California and Phoenix and Tucson, Arizona and Las Vegas, Nevada. Short haul trucking from the refinery centers is also a competitive factor to close-in terminals. Competitors of our Carson terminal in the refined products market include Shell Oil Products U.S. and BP (formerly Arco Terminal Services Company). In the crude/black oil market, competitors include Pacific Energy, Wilmington Liquid Bulk Terminals (Vopak) and BP. Competition to our Richmond terminal's chemical business comes primarily from IMTT. Competitors to our Linnton and Willbridge terminals include ST Services, ChevronTexaco and Shell Oil Products U.S. Our Harbor Island terminal competes primarily with nearby terminals owned by Shell Oil Products U.S. and ConocoPhillips. Central Florida Pipeline We own and operate a liquids terminal in Tampa, Florida, a liquids terminal in Taft, Florida (near Orlando, Florida) and an intrastate common carrier pipeline system that serves customers' product storage and transportation 15 <PAGE> needs in Central Florida. The Tampa terminal contains 31 above-ground storage tanks consisting of approximately 1.4 million barrels of storage capacity and is connected to two ship dock facilities in the Port of Tampa that unload refined products from barges and ocean-going vessels into the terminal. The facility also has a truck rack that can load in excess of 200 trucks per day and a railroad terminal. The Tampa terminal provides storage for gasoline, diesel fuel and jet fuel for further movement into either trucks through five truck-loading racks or into the Central Florida pipeline system. The Tampa terminal also provides storage for chemicals, predominantly used to treat citrus crops, delivered to the terminal by vessel or rail car and loaded onto trucks through five truck-loading racks. The Taft terminal contains 22 above-ground storage tanks consisting of approximately 670,000 barrels of storage capacity, providing storage for gasoline and diesel fuel for further movement into trucks through 11 truck-loading racks. The Central Florida pipeline system consists of a 110-mile, 16-inch diameter pipeline that transports gasoline and an 85-mile, 10-inch diameter pipeline that transports diesel fuel and jet fuel from Tampa to Orlando, with an intermediate delivery point on the 10-inch pipeline at Intercession City, Florida. In addition to being connected to our Tampa terminal, the pipeline system is connected to terminals owned and operated by TransMontaigne, Citgo, BP, and Marathon Ashland Petroleum. The control room for the pipeline is located at the Tampa terminal. The 10-inch diameter pipeline is connected to our Taft terminal and is also the sole pipeline supplying jet fuel to the Orlando International Airport in Orlando, Florida. In 2004, the pipeline transported approximately 103,000 barrels per day of refined products, with the product mix being approximately 68% gasoline, 14% diesel fuel, and 18% jet fuel. Markets. The estimated total refined petroleum product demand in the State of Florida is approximately 800,000 barrels per day. Gasoline is, by far, the largest component of that demand at approximately 545,000 barrels per day. The total refined petroleum products demand for the Central Florida region of the state, which includes the Tampa and Orlando markets, is estimated to be approximately 350,000 barrels per day, or 44% of the consumption of refined products in the state. Our market share is approximately 140,000 barrels per day, or 40% of the Central Florida market. The balance of the market is supplied primarily by trucking firms and marine transportation firms. Most of the jet fuel used at Orlando International Airport is moved through our Tampa terminal and the Central Florida pipeline system. The market in Central Florida is seasonal, with demand peaks in March and April during spring break and again in the summer vacation season, and is also heavily influenced by tourism, with Disney World and other amusement parks located in Orlando. Supply. The vast majority of refined petroleum products consumed in Florida is supplied via marine vessels from major refining centers in the Gulf Coast of Louisiana and Mississippi and refineries in the Caribbean basin. A lesser amount of refined products is being supplied by refineries in Alabama and by Texas Gulf Coast refineries via marine vessels and through pipeline networks that extend to Bainbridge, Georgia. The supply into Florida is generally transported by ocean-going vessels to the larger metropolitan ports, such as Tampa, Port Everglades near Miami, and Jacksonville. Individual markets are then supplied from terminals at these ports and other smaller ports, predominately by trucks, except the Central Florida region, which is served by a combination of trucks and pipelines. Competition. With respect to the terminal operations at Tampa, the most significant competitors are proprietary terminals owned and operated by major oil companies, such as Marathon Ashland Petroleum, BP and Citgo, located along the Port of Tampa, and the ChevronTexaco and Motiva terminals in Port Tampa. These terminals generally support the storage requirements of their parent or affiliated companies' refining and marketing operations and provide a mechanism for an oil company to enter into exchange contracts with third parties to serve its storage needs in markets where the oil company may not have terminal assets. Due to the high capital costs of tank construction in Tampa and state environmental regulation of terminal operations, we believe it is unlikely that new competing terminals will be constructed in the foreseeable future. With respect to the Central Florida pipeline system, the most significant competitors are trucking firms and marine transportation firms. Trucking transportation is more competitive in serving markets close to the marine terminals on the east and west coasts of Florida. We are utilizing tariff incentives to attract volumes to the pipeline that might otherwise enter the Orlando market area by truck from Tampa or by marine vessel into Cape Canaveral. 16 <PAGE> Federal regulation of marine vessels, including the requirement, under the Jones Act, that United States-flagged vessels contain double-hulls, is a significant factor in reducing the fleet of vessels available to transport refined petroleum products. Marine vessel owners are phasing in the requirement based on the age of the vessel and some older vessels are being redeployed into use in other jurisdictions rather than being retrofitted with a double-hull for use in the United States. We believe it is unlikely that a new pipeline system comparable in size and scope to our Central Florida Pipeline operations will be constructed, due to the high cost of pipeline construction and environmental and right-of-way permitting in Florida. However, the possibility of such a pipeline being built is a continuing competitive factor. North System Our North System is an approximate 1,600-mile interstate common carrier pipeline system used to deliver natural gas liquids and refined petroleum products. Additionally, we include our 50% ownership interest in Heartland Pipeline Company as part of our North System operations. ConocoPhillips owns the remaining 50% of Heartland Pipeline Company. Natural gas liquids are typically extracted from natural gas in liquid form under low temperature and high pressure conditions. Natural gas liquids products and related uses are as follows: Product Use ----------- ----------------------------------- Propane Residential heating, industrial and agricultural uses, petrochemical feedstock Isobutane Further processing Natural gasoline Further processing or blending into gasoline motor fuel Ethane/Propane Mix Feedstock for petrochemical plants or peak-shaving facilities Normal butane Feedstock for petrochemical plants or blending into gasoline motor fuel Our North System extends from south central Kansas to the Chicago area. South central Kansas is a major hub for producing, gathering, storing, fractionating and transporting natural gas liquids. Our North System's primary pipelines are comprised of approximately 1,400 miles of 8-inch and 10-inch diameter pipelines and include: o two pipelines that originate at Bushton, Kansas and continue to a major storage and terminal area in Des Moines, Iowa; o a third pipeline, that extends from Bushton to the Kansas City, Missouri area; and o a fourth pipeline that extends from Des Moines to the Chicago area. Through interconnections with other major liquids pipelines, our North System's pipeline system connects mid-continent producing areas to markets in the Midwest and eastern United States. We also have defined sole carrier rights to use capacity on an extensive pipeline system owned by Magellan Midstream Partners, L.P. that interconnects with our North System. This capacity lease agreement, which requires us to pay approximately $2.2 million per year, is in place until February 2013 and contains a five-year renewal option. In addition to our capacity lease agreement with Magellan, we also have a reversal agreement with Magellan to help provide for the transport of summer-time surplus butanes from Chicago area refineries to storage facilities at Bushton. We have an annual minimum joint tariff commitment of $0.6 million to Magellan for this agreement. Our North System has approximately 5.6 million barrels of storage capacity, which includes caverns, steel tanks, pipeline line-fill and leased storage capacity. This storage capacity provides operating efficiencies and flexibility in meeting seasonal demands of shippers and provides propane storage for our truck-loading terminals. The Heartland pipeline system was completed in 1990 and is owned by the Heartland Pipeline Company. We own a 50% equity interest in Heartland. The pipeline comprises one of our North System's main line sections that originate at Bushton, Kansas and terminates at a storage and terminal area in Des Moines, Iowa. We operate the Heartland pipeline, and ConocoPhillips operates Heartland's Des Moines, Iowa terminal and serves as the managing partner of Heartland. Heartland leases to ConocoPhillips Inc. 100% of the Heartland terminal capacity at Des Moines, Iowa for $1.0 million per year on a year-to-year basis. The Heartland pipeline lease fee, payable to us for 17 <PAGE> reserved pipeline capacity, is paid monthly, with an annual adjustment. The 2005 lease fee will be approximately $1.1 million. In addition, our North System has seven propane truck-loading terminals at various points in three states along the pipeline system and one multi-product complex at Morris, Illinois, in the Chicago area. Propane, normal butane and natural gasoline can be loaded at our Morris terminal. Markets. Our North System currently serves approximately 50 shippers in the upper Midwest market, including both users and wholesale marketers of natural gas liquids. These shippers include all three major refineries in the Chicago area. Wholesale marketers of natural gas liquids primarily make direct large volume sales to major end-users, such as propane marketers, refineries, petrochemical plants and industrial concerns. Market demand for natural gas liquids varies in respect to the different end uses to which natural gas liquids products may be applied. Demand for transportation services is influenced not only by demand for natural gas liquids but also by the available supply of natural gas liquids. Heartland provides transportation of refined petroleum products from refineries in the Kansas and Oklahoma areas to a BP terminal in Council Bluffs, Iowa, a ConocoPhillips terminal in Lincoln, Nebraska and Heartland's Des Moines terminal. The demand for, and supply of, refined petroleum products in the geographic regions served by the Heartland pipeline system directly affect the volume of refined petroleum products transported by Heartland. Supply. Natural gas liquids extracted or fractionated at the Bushton gas processing plant have historically accounted for a significant portion (approximately 40-50%) of the natural gas liquids transported through our North System. Other sources of natural gas liquids transported in our North System include large oil companies, marketers, end-users and natural gas processors that use interconnecting pipelines to transport hydrocarbons. Refined petroleum products transported by Heartland on our North System are supplied primarily from the National Cooperative Refinery Association crude oil refinery in McPherson, Kansas and the ConocoPhillips crude oil refinery in Ponca City, Oklahoma. During the first quarter of 2003, and again in the first quarter of 2004, the North System experienced a general decline in throughput volumes due to a lack of product supplies caused by shippers (primarily propane shippers) reducing their inventory levels at the close of the winter season. In addition to the general decline in throughput volumes, shippers were unable to get all of their product out of the system, as a significant volume was required to be held as line-fill. Following numerous discussions and meetings with our shippers in an attempt to remedy this situation, including a plan to require shippers to carry a minimum line-fill in our system, the consensus was for us to purchase product to be used as line-fill and pass the carrying cost on to the shippers through a cost of service filing with the FERC. A cost of service filing was made with the FERC to be effective on June 1, 2004, raising our tariff rates by $0.12 per barrel on product transported north of the Bushton/Conway, Kansas area. This rate went into effect without protest or intervention. Competition. Our North System competes with other natural gas liquids pipelines and to a lesser extent with rail carriers. In most cases, established pipelines are the lowest cost alternative for the transportation of natural gas liquids and refined petroleum products. Consequently, pipelines owned and operated by others represent our primary competition. With respect to the Chicago market, our North System competes with other natural gas liquids pipelines that deliver into the area and with rail car deliveries primarily from Canada. Other Midwest pipelines and area refineries compete with our North System for propane terminal deliveries. Our North System also competes indirectly with pipelines that deliver product to markets that our North System does not serve, such as the Gulf Coast market area. Heartland competes with other refined petroleum product carriers in the geographic market served. Heartland's principal competitor is Magellan Midstream Partners, L.P. Plantation Pipe Line Company We own approximately 51% of Plantation Pipe Line Company, a 3,100-mile pipeline system serving the southeastern United States. An affiliate of ExxonMobil owns the remaining 49% ownership interest. ExxonMobil is the largest shipper on the Plantation system both in terms of volumes and revenues. We operate the system pursuant to agreements with Plantation Services LLC and Plantation Pipe Line Company. Plantation serves as a common carrier of refined petroleum products to various metropolitan areas, including Birmingham, Alabama; Atlanta, Georgia; Charlotte, North Carolina; and the Washington, D.C. area. 18 <PAGE> For the year 2004, Plantation delivered an average of 620,363 barrels per day of refined petroleum products. These delivered volumes were comprised of gasoline (65%), diesel/heating oil (22%) and jet fuel (13%). Average delivery volumes for 2004 were 1.3% higher than the 612,451 barrels per day delivered during 2003. The increase was driven by regional demand growth in all transportation-related fuels: gasoline up 0.9%; low sulfur diesel up 4.9%; and jet fuel up 2.8%. Markets. Plantation ships products for approximately 40 companies to terminals throughout the southeastern United States. Plantation's principal customers are Gulf Coast refining and marketing companies, fuel wholesalers, and the United States Department of Defense. Plantation's top five shippers represent slightly over 80% of total system volumes. The eight states in which Plantation operates represent a collective pipeline demand of approximately 2.0 million barrels per day of refined products. Plantation currently has direct access to about 1.5 million barrels per day of this overall market. The remaining 0.5 million barrels per day of demand lies in markets (e.g. Nashville, Tennessee; North Augusta, South Carolina; Bainbridge, Georgia; and Selma, North Carolina) currently served by another pipeline company. These markets represent potential growth opportunities for the Plantation system. In addition, Plantation delivers jet fuel to the Atlanta, Georgia; Charlotte, North Carolina; and Washington, D.C. airports (Ronald Reagan National and Dulles). Combined jet fuel shipments to these four major airports increased 1.5% (led by a 10% increase in shipments to Ronald Reagan National) in 2004. An improving domestic economy should help improve jet fuel demand in 2005. Supply. Products shipped on Plantation originate at various Gulf Coast refineries from which major integrated oil companies and independent refineries and wholesalers ship refined petroleum products. Plantation is directly connected to and supplied by a total of nine major refineries representing over two million barrels per day of refining capacity. Competition. Plantation competes primarily with the Colonial pipeline system, which also runs from Gulf Coast refineries throughout the southeastern United States and extends into the northeastern states. Kinder Morgan Southeast Terminals LLC Kinder Morgan Southeast Terminals LLC, a wholly-owned subsidiary referred to in this report as KMST, was formed in 2003 for the purpose of acquiring and operating high-quality liquid petroleum products terminals located primarily along the Plantation/Colonial pipeline corridor in the Southeastern United States. On December 11, 2003, KMST acquired seven petroleum products terminals from ConocoPhillips and Phillips Pipe Line Company for an aggregate consideration of approximately $15.3 million, consisting of approximately $14.3 million in cash and $1.0 million in assumed liabilities. These seven terminals contain approximately 1.15 million barrels of storage capacity. The terminals are located in the following markets: Selma, North Carolina; Charlotte, North Carolina; Spartanburg, South Carolina; North Augusta, South Carolina; Doraville, Georgia; Albany, Georgia; and Birmingham, Alabama. ConocoPhillips has entered into a long-term contract to use the terminals. All seven terminals are served by Colonial Pipeline and three are also connected to Plantation. On March 9, 2004, KMST acquired seven additional refined petroleum products terminals from Exxon Mobil Corporation for an aggregate consideration of approximately $50.9 million, consisting of approximately $48.2 million in cash and $2.7 million in assumed liabilities. The terminals are located at the following locations: Newington, Virginia; Richmond, Virginia; Roanoke, Virginia; Greensboro, North Carolina; Charlotte, North Carolina; Knoxville, Tennessee; and Collins, Mississippi. The terminals have a combined storage capacity of approximately 3.2 million barrels for gasoline, jet fuel and diesel fuel. ExxonMobil has entered into a long-term contract to use the terminals. All seven of these terminals are served by Plantation and two are also connected to Colonial. On November 5, 2004, KMST acquired ownership interests in nine additional refined petroleum products terminals from Charter Terminal Company and Charter-Triad Terminals, LLC for an aggregate consideration of 19 <PAGE> approximately $75.2 million, consisting of approximately $72.4 million in cash and $2.8 million in assumed liabilities. Three terminals are located in Selma, North Carolina, and the remaining facilities are located in Greensboro and Charlotte, North Carolina; Chesapeake and Richmond, Virginia; Athens, Georgia; and North Augusta, South Carolina. The terminals have a combined storage capacity of approximately 3.2 million barrels for gasoline, jet fuel and diesel fuel. We fully own seven of the terminals and jointly own the remaining two. All of the terminals are connected to products pipelines owned by either Plantation Pipe Line Company or Colonial Pipeline Company. The acquisition increased our southeast terminal storage capacity 76% (to 7.7 million barrels) and terminal throughput 62% (to over 340,000 barrels per day). Markets. KMST acquisition and marketing activities are focused on the Southeastern United States from Mississippi through Virginia, including Tennessee and Florida. The primary marketing activity involves the receipt of petroleum products from common carrier pipelines, short-term storage in terminal tankage, and subsequent loading onto tank trucks. KMST has a physical presence in markets representing almost 80% of the pipeline-supplied demand in the Southeast and offers a competitive alternative to marketers seeking a relationship with a truly independent truck terminal service provider. Supply. Product supply is predominately from either Plantation, Colonial, or both. To the maximum extent practicable, we try to connect KMST terminals to both Plantation and Colonial. Competition. There are relatively few independent terminal operators in the Southeast. Most of the refined product terminals in this region are owned by large oil companies (BP, Motiva, Citgo, Marathon Ashland, and Chevron) who use these assets to support their own proprietary market demands as well as product exchange activity. These oil companies are not generally seeking third party throughput customers. Magellan Midstream Partners and TransMontaigne Product Services represent the other independent terminal operators in this region. Cochin Pipeline System We own 49.8% of the Cochin pipeline system, a joint venture that operates an approximate 1,900-mile, 12-inch diameter multi-product pipeline operating between Fort Saskatchewan, Alberta and Sarnia, Ontario. Effective October 1, 2004, we acquired our most recent ownership interest (5%) from subsidiaries of ConocoPhillips. An affiliate of BP owns the remaining 50.2% ownership interest and is the operator of the pipeline. The Cochin pipeline system and related storage and processing facilities consist of Canadian operations and United States operations: o the Canadian facilities are operated under the name of Cochin Pipe Lines, Ltd.; and o the United States facilities are operated under the name of Dome Pipeline Corporation. The pipeline operates on a batched basis and has an estimated system capacity of approximately 112,000 barrels per day. Its peak capacity is approximately 124,000 barrels per day. It includes 31 pump stations spaced at 60 mile intervals and five United States propane terminals. Associated underground storage is available at Fort Saskatchewan, Alberta and Windsor, Ontario. Markets. The pipeline traverses three provinces in Canada and seven states in the United States transporting high vapor pressure ethane, ethylene, propane, butane and natural gas liquids to the Midwestern United States and eastern Canadian petrochemical and fuel markets. The system operates as a National Energy Board (Canada) and Federal Energy Regulatory Commission (United States) regulated common carrier, shipping products on behalf of its owners as well as other third parties. The system is connected to the Enterprise pipeline system in Minnesota and in Iowa, and connects with our North System at Clinton, Iowa. The Cochin pipeline system has the ability to access the Canadian Eastern Delivery System via the Windsor Storage Facility Joint Venture at Windsor, Ontario. Supply. Injection into the system can occur from: o BP, EnerPro or Dow fractionation facilities at Fort Saskatchewan, Alberta; 20 <PAGE> o Provident Energy storage at five points within the provinces of Canada; or o the Enterprise West Junction, in Minnesota. Competition. The pipeline competes with railcars and Enbridge Energy Partners for natural gas liquids long-haul business from Fort Saskatchewan, Alberta and Windsor, Ontario. The pipeline's primary competition in the Chicago natural gas liquids market comes from the combination of the Alliance pipeline system, which brings unprocessed gas into the United States from Canada, and from Aux Sable, which processes and markets the natural gas liquids in the Chicago market. Cypress Pipeline Our Cypress pipeline is an interstate common carrier pipeline system originating at storage facilities in Mont Belvieu, Texas and extending 104 miles east to the Lake Charles, Louisiana area. Mont Belvieu, located approximately 20 miles east of Houston, is the largest hub for natural gas liquids gathering, transportation, fractionation and storage in the United States. Markets. The pipeline was built to service Westlake Petrochemicals Corporation in the Lake Charles, Louisiana area under a 20-year ship-or-pay agreement that expires in 2011. The contract requires a minimum volume of 30,000 barrels per day. Supply. The Cypress pipeline originates in Mont Belvieu where it is able to receive ethane and ethane/propane mix from local storage facilities. Mont Belvieu has facilities to fractionate natural gas liquids received from several pipelines into ethane and other components. Additionally, pipeline systems that transport specification natural gas liquids from major producing areas in Texas, New Mexico, Louisiana, Oklahoma and the Mid-Continent Region supply ethane and ethane/propane mix to Mont Belvieu. Competition. The pipeline's primary competition into the Lake Charles market comes from Louisiana onshore and offshore natural gas liquids. Transmix Operations Our transmix operations consist of liquid transmix processing facilities located in Richmond, Virginia; Dorsey Junction, Maryland; Indianola, Pennsylvania; Wood River, Illinois; and Colton, California. Transmix occurs when dissimilar refined petroleum products are co-mingled in the pipeline transportation process. Different products are pushed through the pipelines abutting each other, and the area where different products mix is called transmix. At our transmix processing facilities, we process and separate pipeline transmix into pipeline-quality gasoline and light distillate products. Transmix processing is performed for Duke Energy Merchants on a "for fee" basis pursuant to a long-term contract expiring in 2010, and for Colonial Pipeline Company at Dorsey Junction, Maryland. Effective September 30, 2004, Shell Trading (U.S.) Company assumed ownership of the processing rights at our transmix facilities located in Richmond, Virginia; Indianola, Pennsylvania; and Wood River, Illinois. Shell Trading purchased the eastern transmix trading business formerly owned by Duke Energy Merchants LLC, which included a transmix processing agreement effective through March 16, 2011. At these locations, Shell procures transmix supply from pipelines and other parties, pays a processing fee to us, and then sells the processed gasoline and fuel oil through their marketing and distribution networks. The arrangement includes a minimum processing volume and fee to us, as well as an opportunity to extend the processing agreement beyond the 2011 date. Our Richmond processing facility is comprised of a dock/pipeline, a 170,000-barrel tank farm, a processing plant, lab and truck rack. The facility is composed of three distillation units that operate 24 hours a day, 7 days a week providing a processing capacity of approximately 8,000 barrels per day. Both the Colonial and Plantation pipelines supply the facility, as well as deep-water barge (25 feet draft), transport truck and rail. We also own an additional 3.6-acre bulk products terminal, which is currently not in service, with a capacity of 55,000 barrels located nearby in Richmond. 21 <PAGE> Our Dorsey Junction processing facility is located near Baltimore, Maryland within Colonial's Dorsey Junction terminal facility. The 5,000-plus barrel per day processing unit began operations in February 1998. It operates 24 hours a day, 7 days a week providing dedicated transmix separation service for Colonial. Our Indianola processing facility is located near Pittsburgh, Pennsylvania and is accessible by truck, barge and pipeline. It primarily processes transmix from Buckeye, Colonial, Sun and Teppco pipelines. It has capacity to process 12,000 barrels of transmix per day and operates 24 hours per day, 7 days a week. The facility is comprised of a 500,000-barrel tank farm, a quality control laboratory, a truck-loading rack and a processing unit. The facility can ship output via the Buckeye pipeline as well as by truck. Our Wood River processing facility was constructed in 1993 on property owned by ConocoPhillips and is accessible by truck, barge and pipeline. It primarily processes transmix from both Explorer and ConocoPhillips pipelines. It has capacity to process 5,000 barrels of transmix per day. Located on approximately three acres leased from ConocoPhillips, the facility consists of one processing unit. Supporting terminal capability is provided through leased tanks in adjacent terminals. Our Colton processing facility, completed in the spring of 1998, and located adjacent to our products terminal in Colton, California, produces refined petroleum products that are delivered into our Pacific operations' pipelines for shipment to markets in Southern California and Arizona. The facility can process over 5,000 barrels per day. Markets. The Gulf and East Coast refined petroleum products distribution system, particularly the Mid-Atlantic region, provides the target market for our East Coast transmix processing operations. The Mid-Continent area and the New York Harbor are the target markets for our Pennsylvania and Illinois assets. Our West Coast transmix processing operations support the markets served by our Pacific operations. We are working to expand our Mid-Continent and West Coast markets. Supply. Transmix generated by Colonial, Plantation, Sun, Teppco, Explorer and our Pacific operations provide the vast majority of the supply. These suppliers are committed to our transmix facilities by long-term contracts. Individual shippers and terminal operators provide additional supply. Duke Energy Merchants is responsible for acquiring transmix supply at Colton, and Shell acquires transmix for processing at Indianola, Richmond and Wood River. The Dorsey Junction facility is supplied by Colonial Pipeline Company. Competition. Placid Refining is our main competitor in the Gulf Coast area. There are various processors in the Mid-Continent area, primarily ConocoPhillips, Gladieux Refining and Williams Energy Services, who compete with our expansion efforts in that market. A number of smaller organizations operate transmix processing facilities in the West and Southwest. These operations compete for supply that we envision as the basis for growth in the West and Southwest. Our Colton processing facility also competes with major oil company refineries in California. Natural Gas Pipelines Our Natural Gas Pipelines segment, which contains both interstate and intrastate pipelines, consists of natural gas sales, transportation, storage, gathering, processing and treating. Within this segment, we own approximately 14,000 miles of natural gas pipelines and associated storage and supply lines that are strategically located at the center of the North American pipeline grid. Our transportation network provides access to the major gas supply areas in the western United States, Texas and the Midwest, as well as major consumer markets. Our Natural Gas Pipeline assets include the following: o our Texas intrastate natural gas pipeline group, which operates primarily along the Texas Gulf Coast and includes the following four pipeline systems: Kinder Morgan Texas Pipeline, Kinder Morgan Tejas, Mier-Monterrey Mexico Pipeline, and the North Texas Pipeline. Kinder Morgan Texas and Kinder Morgan Tejas are the two largest systems in this group, and combined, consist of approximately 5,800 miles of intrastate natural gas pipelines with a peak transport capacity of approximately five billion cubic feet per day of natural gas and approximately 120 billion cubic feet of natural gas storage capacity (including the West Clear Lake natural gas storage facility located in Harris County, Texas, which is committed under a long term contract to Coral Energy); 22 <PAGE> o our three Rocky Mountain interstate natural gas pipeline systems: Kinder Morgan Interstate Gas Transmission LLC, Trailblazer Pipeline Company and TransColorado Gas Transmission Company. KMIGT owns a 4,562-mile natural gas pipeline system, including the Pony Express pipeline system, that extends from northwestern Wyoming east into Nebraska and Missouri and south through Colorado and Kansas. Our Trailblazer pipeline is a 436-mile pipeline that transports natural gas from Colorado to Beatrice, Nebraska. TransColorado owns a 300-mile natural gas pipeline system that extends from the Western Slope of Colorado to northwestern New Mexico. As of December 31, 2004, the combined peak transport capacity for our Rocky Mountain pipeline systems was approximately 2.5 billion cubic feet per day of natural gas, and the combined storage capacity was approximately 10.0 billion cubic feet of natural gas; o our Casper and Douglas natural gas gathering systems, which are comprised of over 1,500 miles of natural gas gathering pipelines and two facilities in Wyoming capable of processing 210 million cubic feet of natural gas per day; o our 49% interest in the Red Cedar Gathering Company, which gathers natural gas in La Plata County, Colorado and owns and operates two carbon dioxide processing plants; o our 50% interest in Coyote Gas Treating, LLC, which owns a 250 million cubic feet per day natural gas treating facility in La Plata County, Colorado; and o our 25% interest in Thunder Creek Gas Services, LLC, which gathers, transports and processes methane gas from coal beds in the Powder River Basin of Wyoming. Texas Intrastate Pipeline Group Our Kinder Morgan Tejas system was acquired on January 31, 2002 from Intergen, a joint venture owned by affiliates of the Royal Dutch Shell Group of Companies, and Bechtel Enterprises Holding, Inc. The system has become increasingly interconnected with our Kinder Morgan Texas Pipeline system, which was acquired on December 31, 1999 from KMI. These pipelines essentially operate as a single pipeline system, providing customers and suppliers with improved flexibility and reliability. The combined assets include over 5,800 miles of natural gas pipelines with a peak transport capacity of approximately five billion cubic feet per day and approximately 120 billion cubic feet of natural gas storage capacity. In addition, the system, through owned assets and contractual arrangement with third parties, has the capability to process over one billion cubic feet per day of natural gas for liquids extraction and treat approximately 250 million cubic feet per day of natural gas for carbon dioxide removal. Collectively, the system primarily serves the Texas Gulf Coast, transporting, processing and treating gas from multiple onshore and offshore supply sources to serve the Houston/Beaumont/Port Arthur, Texas industrial markets, as well as local gas distribution utilities, electric utilities and merchant power generation markets. It serves as a buyer and seller of natural gas, as well as a transporter of natural gas. The purchases and sales of natural gas are primarily priced with reference to market prices in the consuming region of its system. The difference between the purchase and sale prices is the rough equivalent of a transportation fee. Our North Texas Pipeline, a $65 million investment, was completed in August 2002. The system consists of an 86-mile, 30-inch diameter pipeline that transports natural gas from an interconnect with KMI's Natural Gas Pipeline Company of America in Lamar County, Texas to a 1,750-megawatt electric generating facility located in Forney, Texas, 15 miles east of Dallas, Texas. It has the capacity to transport 325,000 dekatherms per day of natural gas and is fully subscribed under a 30 year contract. Our Mier-Monterrey Pipeline, an $89 million investment, was completed in March 2003. The system consists of a 95-mile, 30-inch diameter natural gas pipeline that stretches from south Texas to Monterrey, Mexico and can transport up to 375,000 dekatherms per day. The pipeline connects to a 1,000-megawatt power plant complex and to the PEMEX natural gas transportation system. We have entered into a 15 year contract with Pemex Gas Y Petroquimica Basica, which has subscribed for all of the pipeline's capacity. Markets. Our Texas intrastate natural gas pipeline group's market area consumes over eight billion cubic feet per day of natural gas. Of this amount, we estimate that 75% is industrial demand (including on-site, cogeneration 23 <PAGE> facilities), about 15% is merchant generation demand and the remainder is split between local natural gas distribution and utility power demand. The industrial demand is primarily year-round load. Local natural gas distribution load peaks in the winter months and is complemented by power demand (both merchant and utility generation) which peaks in the summer months. As new merchant gas fired generation has come online and displaced traditional utility generation, we have successfully attached certain of these new generation facilities to our pipeline systems in order to maintain our share of natural gas supply for power generation. We serve the Mexico market through interconnection with the facilities of Pemex at the United States-Mexico border near Arguellas, Mexico and Monterrey, Mexico. Current deliveries through the existing interconnection near Arguellas are approximately 150,000 to 200,000 dekatherms per day of natural gas and deliveries to Monterrey generally range from 150,000 to 300,000 dekatherms per day. We primarily provide transport service to these markets on a fee for service basis, including a significant demand component, which is paid regardless of actual throughput. Revenues earned from our activities in Mexico are paid in U.S. dollar equivalent. Supply. We purchase our natural gas directly from producers attached to our system in South Texas, East Texas and along the Texas Gulf Coast. We also purchase gas at interconnects with third-party interstate and intrastate pipelines. While our intrastate group does not produce gas, it does maintain an active well connection program in order to offset natural declines in production along its system and to secure supplies for additional demand in its market area. Our intrastate system has access to both onshore and offshore sources of supply, and is well positioned to interconnect with liquefied natural gas projects currently under development by others along the Texas Gulf Coast. Gathering, Processing and Treating. Our intrastate natural gas group owns and operates various gathering systems in South and East Texas. These systems aggregate pipeline quality natural gas supplies into our main transmission pipelines, and in certain cases, aggregate natural gas that must be processed or treated at its own or third-party facilities. We own two processing plants: our Texas City Plant in Galveston County, Texas and our Galveston Bay Plant in Chambers County, Texas, which is currently idle. Combined, these plants can process 115 million cubic feet per day of natural gas for liquids extraction. In addition, we have contractual rights to process approximately 735 million cubic feet per day of natural gas at various third-party owned facilities. We also own and operate four natural gas treating plants that offer carbon dioxide and/or hydrogen sulfide removal. We can treat up to 155 million cubic feet per day of natural gas for carbon dioxide removal at our Fandango Complex in Zapata County, Texas, 50 million cubic feet per day of natural gas at our Indian Rock Plant in Upshur County, Texas and approximately 45 million cubic feet per day of natural gas at our Thompsonville Facility located in Jim Hogg County, Texas. Storage. We own the West Clear Lake natural gas storage facility located in Harris County, Texas. Under a long term contract, Coral Energy Resources, L.P. operates the facility and controls the 96 billion cubic feet of natural gas working capacity, and we provide transportation service into and out of the facility. We lease a salt dome storage facility located near Markham, Texas. The facility consists of two salt dome caverns with approximately 7.5 billion cubic feet of total natural gas storage capacity, over 4.2 billion cubic feet of working natural gas capacity and up to 500 million cubic feet per day of peak deliverability. We also lease salt dome caverns from Dow Hydrocarbon & Resources, Inc. and BP America Production Company in Brazoria County, Texas. The salt dome caverns are referred to as the Stratton Ridge Facilities and have a combined capacity of 11.8 billion cubic feet of natural gas, working natural gas capacity of 5.4 billion cubic feet and a peak day deliverability of up to 400 million cubic feet per day. Competition. The Texas intrastate natural gas market is highly competitive, with many markets connected to multiple pipeline companies. We compete with interstate and intrastate pipelines, and their shippers, for attachments to new markets and supplies and for transportation, processing and treating services. Kinder Morgan Interstate Gas Transmission LLC Kinder Morgan Interstate Gas Transmission LLC, referred to in this report as KMIGT, owns approximately 4,562 miles of transmission lines in Wyoming, Colorado, Kansas, Missouri and Nebraska. It provides transportation and storage services to KMI affiliates, third-party natural gas distribution utilities and other shippers. KMIGT also has the authority to make gas purchases and sales, as needed for system operations, pursuant to its currently 24 <PAGE> effective FERC gas tariff. Pursuant to transportation agreements and Federal Energy Regulatory Commission tariff provisions, KMIGT offers its customers firm and interruptible transportation and storage services, including no-notice transportation and park and loan services. Under KMIGT's tariffs, firm transportation and storage customers pay reservation fees each month plus a commodity charge based on the actual transported or stored volumes. In contrast, interruptible transportation and storage customers pay a commodity charge based upon actual transported and/or stored volumes. Reservation fees are based upon geographical location (KMIGT does not have seasonal rates) and the distance of the transportation service provided. Under the no-notice service, customers pay a fee for the right to use a combination of firm storage and firm transportation to effect deliveries of natural gas up to a specified volume without making specific nominations. The system is powered by 28 transmission and storage compressor stations with approximately 160,000 horsepower. The pipeline system provides storage services to its customers from its Huntsman Storage Field in Cheyenne County, Nebraska. On June 1, 2004, KMIGT implemented its Cheyenne Market Center service, which provides nominated storage and transportation service between its Huntsman Storage Field and multiple interconnecting pipelines at the Cheyenne Hub. This service is fully subscribed for a period of ten years and added an incremental withdrawal capacity of 68 million cubic feet of natural gas per day and increased the working gas capacity by 3.5 billion cubic feet. The Huntsman Storage facility now has approximately 39.5 billion cubic feet of total storage capacity, 16 billion cubic feet of working gas capacity and can withdraw up to 169 million cubic feet of natural gas per day. Markets. Markets served by KMIGT provide a stable customer base with expansion opportunities due to the system's access to growing Rocky Mountain supply sources. Markets served by KMIGT are comprised mainly of local natural gas distribution companies and interconnecting interstate pipelines in the mid-continent area. End-users of the local natural gas distribution companies typically include residential, commercial, industrial and agricultural customers. The pipelines interconnecting with KMIGT in turn deliver gas into multiple markets including some of the largest population centers in the Midwest. Natural gas demand to power pumps for crop irrigation during the summer from time-to-time exceeds heating season demand and provides KMIGT relatively consistent volumes throughout the year. Supply. Approximately 15%, by volume, of KMIGT's firm contracts expire within one year and 39% expire within one to five years. Our affiliates are responsible for approximately 21% of the total contracted firm transportation and storage capacity on KMIGT's system. Over 98% of the system's firm transport capacity is currently subscribed. Competition. KMIGT competes with other interstate and intrastate gas pipelines transporting gas from the supply sources in the Rocky Mountain and Hugoton Basins to mid-continent pipelines and market centers. Trailblazer Pipeline Company Trailblazer Pipeline Company is an Illinois partnership and its principal business is to transport natural gas in interstate commerce. It does business in the states of Wyoming, Colorado and Nebraska. Natural Gas Pipeline Company of America, a subsidiary of KMI, manages, maintains and operates Trailblazer, for which it is reimbursed at cost. Trailblazer's 436-mile natural gas pipeline system originates at an interconnection with Wyoming Interstate Company Ltd.'s pipeline system near Rockport, Colorado and runs through southeastern Wyoming to a terminus near Beatrice, Nebraska where it interconnects with Natural Gas Pipeline Company of America's and Northern Natural Gas Company's pipeline systems. Trailblazer's pipeline is the fourth and last segment of a 791-mile pipeline system known as the Trailblazer Pipeline System, which originates in Uinta County, Wyoming with Canyon Creek Compression Company, a 22,000 horsepower compressor station located at the tailgate of BP Amoco Production Company's processing plant in the Whitney Canyon Area in Wyoming (Canyon Creek's facilities are the first segment). Canyon Creek receives gas from the BP Amoco processing plant and provides transportation and compression of gas for delivery to Overthrust Pipeline Company's 88-mile, 36-inch diameter pipeline system at an interconnection in Uinta County, Wyoming (Overthrust's system is the second segment). Overthrust delivers gas to Wyoming Interstate's 269-mile, 36-inch diameter pipeline system at an inter-connection (Kanda) in Sweetwater County, Wyoming (Wyoming Interstate's system is the third segment). Wyoming Interstate's pipeline delivers gas to Trailblazer's pipeline at an 25 <PAGE> interconnection near Rockport in Weld County, Colorado. Trailblazer provides transportation services to third-party natural gas producers, marketers, gathering companies, local distribution companies and other shippers. Pursuant to transportation agreements and FERC tariff provisions, Trailblazer offers its customers firm and interruptible transportation. Under Trailblazer's tariffs, firm transportation customers pay reservation charges each month plus a commodity charge based on actual volumes transported. Interruptible transportation customers pay a commodity charge based upon actual volumes transported. Markets. Significant growth in Rocky Mountain natural gas supplies has prompted a need for additional pipeline transportation service. Trailblazer has a certificated capacity of 846 million cubic feet per day of natural gas. Supply. As of December 31, 2004, 6% of Trailblazer's firm contracts, by volume, expire before one year and 40%, by volume, expire within one to five years. Affiliated entities hold less than 1% of the total firm transportation capacity. All of the system's firm transport capacity is currently subscribed. Competition. The main competition that Trailblazer currently faces is that the gas supply in the Rocky Mountain area either stays in the area or is moved west and therefore is not transported on Trailblazer's pipeline. However, on March 24, 2004, the FERC issued a certificate approving the Cheyenne Plains pipeline project that was developed by Colorado Interstate Gas Company. This project, which commenced service in December 2004, allows for the transportation of 560,000 dekatherms per day of natural gas from Weld County, Colorado to Greensburg, Kansas and competes with Trailblazer for natural gas pipeline transportation demand from the Rocky Montitain area. In addition, Cheyenne Plains received approval from the FERC to expand its facilities to provide an additional 170,000 dekatherms per day of capacity for a total capacity of 730,000 dekatherms. The proposed expansion is anticipated to go into service in early 2006. No assurance can be given that additional competing pipelines will not be developed in the future. TransColorado Gas Transmission Company TransColorado Gas Transmission Company is a Colorado general partnership that owns a 300-mile interstate natural gas pipeline that extends form the Western Slope of Colorado to northwestern New Mexico. KMIGT manages, maintains and operates TransColorado, for which it is reimbursed at cost. We acquired all of the ownership interests in TransColorado from KMI effective November 1, 2004. The TransColorado Pipeline, which extends from approximately 20 miles southwest of Meeker, Colorado to Bloomfield, New Mexico, has 20 points of interconnection with five interstate pipelines, one intrastate pipeline, eight gathering systems, and two local distribution companies, thereby providing relatively significant flexibility in the receipt and delivery of natural gas. The pipeline system is powered by five compressor stations in mainline service having an aggregate of approximately 26,500 horsepower. Gas flowing south through the pipeline moves onto the El Paso, Transwestern and Southern Trail pipeline systems. TransColorado receives gas from two coal seam natural gas treating plants located in the San Juan Basin of Colorado and from pipeline and gathering system interconnections within the Paradox and Piceance Basins of western Colorado. TransColorado provides transportation services to third-party natural gas producers, marketers, gathering companies, local distribution companies and other shippers. Pursuant to transportation agreements and FERC tariff provisions, TransColorado offers its customers firm and interruptible transportation and interruptible park and loan services. Under TransColorado's tariffs, firm transportation customers pay reservation charges each month plus a commodity charge based on actual volumes transported. Interruptible transportation customers pay a commodity charge based upon actual volumes transported. The underlying reservation and commodity charges are assessed pursuant to a maximum recourse rate structure, which does not vary based on the distance gas is transported. TransColorado has the authority to negotiate rates with customers if it has first offered service to those customers under its reservation and commodity charge rate structure. TransColorado's revenues and volumes have historically been higher during the second and third quarters of the calendar year, resulting from two factors: winter heating market loads to the north of TransColorado and summer air conditioning market loads to the south of TransColorado. 26 <PAGE> Markets. TransColorado acts principally as a feeder pipeline system from the developing natural gas supply basins on the Western Slope of Colorado into the interstate natural gas pipelines that lead away from the Blanco Hub area of New Mexico. TransColorado is the largest transporter of natural gas from the Western Slope supply basins of Colorado and provides a competitively attractive outlet for that developing natural gas resource. In 2004, TransColorado transported an average of 518,495 dekatherms per day of natural gas from these supply basins. TransColorado provides a strategically important link between the underdeveloped gas supply resources on the Western Slope of Colorado and the greater southwestern United States marketplace. Supply. During 2004, 73% of TransColorado's transport business was with producers or their own marketing affiliates, 4% was with third-party marketers and the remaining 23% was primarily with gathering companies. Approximately 70% of TransColorado's transport business in 2004 was conducted with its three largest customers. All of TransColorado's pipeline capacity is committed under firm transportation contracts that extend at least through year-end 2007. TransColorado's pipeline capacity is 65% subscribed during 2007 through 2011 and TransColorado is actively pursuing contract extensions and or replacement contracts to increase firm subscription levels beyond 2007. On October 6, 2004, TransColorado announced an approximate $20 million expansion project to add 300,000 dekatherms per day of incremental natural gas transportation capacity. As a result of this expansion, natural gas on the northern portion of TransColorado's pipeline will be able to flow northward as well as southward. The expansion is supported by a long-term contract with an undisclosed shipper and includes commitments for up to 280,000 dekatherms per day of natural gas. The contract runs through 2015 with an option for a 5-year extension. Competition. TransColorado competes with other transporters of natural gas in each of the natural gas supply basins it serves. These competitors include both interstate and intrastate natural gas pipelines and natural gas gathering systems. TransColorado is the most recent interstate pipeline entrant into each of the competitive supply markets of the Paradox, Piceance and San Juan Basins of western Colorado. Notwithstanding this fact, we believe that TransColorado generally is looked upon favorably by shippers because it provides distinct advantages of larger system capacity and more direct access to market outlets than its competitors. TransColorado's shippers compete for market share with shippers drawing upon gas production facilities within the New Mexico portion of the San Juan Basin. TransColorado has phased its past construction and expansion efforts to coincide with the ability of the interstate pipeline grid at Blanco, New Mexico to accommodate greater natural gas volumes. The overall San Juan Basin gas production base had been a perennial factor restricting the growth pace of TransColorado's transport from the central Rockies natural gas supply basins. Natural gas production from the San Juan Basin peaked during the first quarter of 2000 and has since declined on an overall basis by 10%. TransColorado's transport concurrently ramped up over that period such that TransColorado now enjoys a growing share of the outlet from the San Juan Basin to the southwestern United States marketplace. Historically, the competition faced by TransColorado with respect to its natural gas transportation services has generally been based upon the price differential between the San Juan and Rocky Mountain basins. The Kern River Gas Transmission expansion project, placed in service in May 2003, has had the effect of reducing that price differential. However, given the increased number of direct connections to production facilities in the Piceance and Paradox basins and the aggressive gas supply development in each of those basins, we believe that TransColorado's transport business will be less susceptible to changes in the price differential in the future. Casper and Douglas Natural Gas Gathering and Processing Systems We own and operate our Casper and Douglas natural gas gathering and processing facilities. The Douglas gathering system is comprised of approximately 1,500 miles of 4-inch to 16-inch diameter pipe that gathers approximately 26 million cubic feet per day of natural gas from 650 active receipt points. Douglas Gathering has an aggregate 20,650 horsepower of compression situated at 17 field compressor stations. Gathered volumes are processed at our Douglas plant, located in Douglas, Wyoming. Residue gas is delivered into KMIGT and recovered liquids are injected in ConocoPhillips Petroleum's natural gas liquids pipeline for transport to Borger, Texas. 27 <PAGE> The Casper gathering system is comprised of approximately 32 miles of 4-inch to 8-inch diameter pipeline gathering approximately four million cubic feet per day of natural gas from four active receipt points. Gathered volumes are delivered directly into KMIGT. Current gathering capacity is contingent upon available capacity on KMIGT and the Casper Plant's 50 to 80 million cubic feet per day processing capacity. We believe that Casper-Douglas' unique combination of percentage-of-proceeds, sliding scale percent-of-proceeds and keep whole plus fee processing agreements helps to reduce our exposure to commodity price volatility. Markets. Casper and Douglas are processing plants servicing gas streams flowing into KMIGT. Competition. There are three other natural gas gathering and processing alternatives available to conventional natural gas producers in the Greater Powder River Basin. However, Casper and Douglas are the only two plants in the region that provide straddle processing of natural gas streams flowing into KMIGT upstream of our two plant facilities. The other regional facilities include the Hilight (80 million cubic feet per day) and Kitty (17 million cubic feet per day) plants owned and operated by Western Gas Resources, and the Sage Creek Processors (50 million cubic feet per day) plant owned and operated by Merit Energy. Red Cedar Gathering Company We own a 49% equity interest in the Red Cedar Gathering Company, a joint venture organized in August 1994, referred to in this report as Red Cedar. The Southern Ute Indian Tribe owns the remaining 51%. Red Cedar owns and operates natural gas gathering, compression and treating facilities in the Ignacio Blanco Field in La Plata County, Colorado. The Ignacio Blanco Field lies within the Colorado portion of the San Juan Basin, most of which is located within the exterior boundaries of the Southern Ute Indian Tribe Reservation. Red Cedar gathers coal seam and conventional natural gas at wellheads and several central delivery points, for treating, compression and delivery into any one of four major interstate natural gas pipeline systems and an intrastate pipeline. Red Cedar's gas gathering system currently consists of over 900 miles of gathering pipeline connecting more than 700 producing wells, 82,000 horsepower of compression at 22 field compressor stations and two carbon dioxide treating plants. A majority of the natural gas on the system moves through 8-inch to 16-inch diameter pipe. The capacity and throughput of the Red Cedar system as currently configured is approximately 750 million cubic feet per day of natural gas. Coyote Gas Treating, LLC We own a 50% equity interest in Coyote Gas Treating, LLC, referred to in this report as Coyote Gulch. Coyote Gulch is a joint venture that was organized in December 1996. Enterprise Field Services LLC owns the remaining 50%. The sole asset owned by the joint venture is a 250 million cubic feet per day natural gas treating facility located in La Plata County, Colorado. We are the managing partner of Coyote Gas Treating, LLC. The inlet gas stream treated by Coyote Gulch contains an average carbon dioxide content of between 12% and 13%. The plant treats the gas down to a carbon dioxide concentration of 2% in order to meet interstate natural gas pipeline quality specifications, and then compresses the natural gas into the TransColorado Gas Transmission pipeline for transport to the Blanco, New Mexico-San Juan Basin Hub. Effective January 1, 2002, Coyote Gulch entered into a five-year operating lease agreement with Red Cedar. Under the terms of the lease, Red Cedar operates the facility and is responsible for all operating and maintenance expense and capital costs. In place of the treating fees that were previously received by Coyote Gulch from Red Cedar, Red Cedar is required to make monthly lease payments. Thunder Creek Gas Services, LLC We own a 25% equity interest in Thunder Creek Gas Services, LLC, referred to in this report as Thunder Creek. Thunder Creek is a joint venture that was organized in September 1998. Devon Energy owns the remaining 75%. Thunder Creek provides gathering, compression and treating services to a number of coal seam gas producers in the Powder River Basin. Throughput volumes include both coal seam and conventional plant residue gas. Thunder 28 <PAGE> Creek is independently operated from offices located in Denver, Colorado with field offices in Glenrock and Gillette, Wyoming. Thunder Creek's operations are a combination of mainline and low pressure gathering assets. The mainline assets include 125 miles of 24-inch diameter mainline pipeline, 308 miles of 4-inch to 12-inch diameter high and low pressure laterals, 19,620 horsepower of mainline compression and carbon dioxide removal facilities consisting of a 240 million cubic feet per day carbon dioxide treating plant complete with dehydration. The mainline assets receive gas from 41 receipt points and can deliver treated gas to seven delivery points including Colorado Interstate Gas, Wyoming Interstate Gas Company, KMIGT and three power plants. The low pressure gathering assets include five systems consisting of 185 miles of 4-inch to 14-inch diameter gathering pipeline and 40,852 horsepower of field compression. Gas is gathered from 79 receipt points and delivered to the mainline at seven primary locations. CO2 Our CO2 segment consists of Kinder Morgan CO2 Company, L.P. and its consolidated affiliates, referred to in this report as KMCO2. Carbon dioxide is used in enhanced oil recovery projects as a flooding medium for recovering crude oil from mature oil fields. Our carbon dioxide pipelines and related assets allow us to market a complete package of carbon dioxide supply, transportation and technical expertise to the customer. Together, our CO2 business segment produces, transports and markets carbon dioxide for use in enhanced oil recovery operations and owns interests in other related assets in the continental United States, through the following: o our interests in carbon dioxide reserves, including an approximate 45% interest in the McElmo Dome unit and an approximate 11% interest in the Bravo Dome unit; o our carbon dioxide pipelines, including: o our Central Basin pipeline, a 321-mile carbon dioxide pipeline system located in the Permian Basin of West Texas between Denver City, Texas and McCamey, Texas; o our Centerline pipeline, a 113-mile carbon dioxide pipeline located in the Permian Basin of West Texas between Denver City, Texas and Snyder, Texas; and o our interests in other carbon dioxide pipelines, including an approximate 98% interest in the Canyon Reef Carriers pipeline, a 50% interest in the Cortez pipeline, a 13% undivided interest in the Bravo pipeline system and an approximate 69% interest in the Pecos pipeline; o our interests in oil-producing fields, including an approximate 97% working interest in the SACROC unit, an approximate 50% working interest in the Yates unit, a 22% net profits interest in the H.T. Boyd unit and lesser interests in the Sharon Ridge unit, the Reinecke unit and the MidCross unit, all of which are located in the Permian Basin of West Texas; o our interests in gasoline plants, including an approximate 22% working interest and an additional 26% net profits interest in the Snyder gasoline plant, a 51% ownership interest in the Diamond M gas plant and a 100% ownership interest in the North Snyder plant, all of which are located in the Permian Basin of West Texas; and o our 450-mile Wink crude oil pipeline system located in West Texas and used to transport crude oil from the Permian Basin to Western Refining Company, L.P.'s crude oil refinery located in El Paso, Texas. Carbon Dioxide Reserves We own approximately 45% of, and operate, the McElmo Dome unit, which contains more than 10 trillion cubic feet of carbon dioxide. Deliverability and compression capacity exceeds one billion cubic feet per day. The McElmo Dome unit produces from the Leadville formation at approximately 8,000 feet with 49 wells that produce at individual rates of up to 53 million cubic feet per day. 29 <PAGE> We also own approximately 11% of Bravo Dome unit, which holds reserves of approximately two trillion cubic feet of carbon dioxide. The Bravo dome produces approximately 307 million cubic feet per day, with production coming from more than 350 wells in the Tubb Sandstone at 2,300 feet. Markets. Our principal market for carbon dioxide is for injection into mature oil fields in the Permian Basin, where industry demand is expected to be comparable to historical demand for the next several years. We are exploring additional potential markets, including enhanced oil recovery targets in the North Sea, California, Mexico and coal bed methane production in the San Juan Basin of New Mexico. Competition. Our primary competitors for the sale of carbon dioxide include suppliers that have an ownership interest in McElmo Dome, Bravo Dome and Sheep Mountain carbon dioxide reserves, and Petro-Source Carbon Company, which gathers waste carbon dioxide from natural gas production in the Val Verde Basin of West Texas. There is no assurance that new carbon dioxide sources will not be discovered or developed, which could compete with us or that new methodologies for enhanced oil recovery will not replace carbon dioxide flooding. Carbon Dioxide Pipelines Placed in service in 1985, our Central Basin pipeline consists of approximately 143 miles of 16-inch to 20-inch diameter pipe and 178 miles of 4-inch to 12-inch lateral supply lines located in the Permian Basin between Denver City, Texas and McCamey, Texas with a throughput capacity of 650 million cubic feet per day. At its origination point in Denver City, our Central Basin pipeline interconnects with all three major carbon dioxide supply pipelines from Colorado and New Mexico, namely the Cortez pipeline (operated by KMCO2) and the Bravo and Sheep Mountain pipelines (operated by Occidental and Trinity CO2, respectively). Central Basin's mainline terminates near McCamey where it interconnects with the Canyon Reef Carriers pipeline and the Pecos pipeline. The tariffs charged by the Central Basin pipeline are not regulated. Our Centerline pipeline consists of approximately 113 miles of 16-inch diameter pipe located in the Permian Basin between Denver City, Texas and Snyder, Texas. The pipeline has a capacity of 300 million cubic feet per day. We constructed this pipeline and placed it in service in May 2003. The tariffs charged by the Centerline pipeline are not regulated. As a result of our 50% ownership interest in Cortez Pipeline Company, we own a 50% interest in and operate the 502-mile, 30-inch diameter Cortez pipeline. The pipeline carries carbon dioxide from the McElmo Dome source reservoir in Cortez, Colorado to the Denver City, Texas hub. The Cortez pipeline currently transports nearly one billion cubic feet of carbon dioxide per day, including approximately 90% of the carbon dioxide transported downstream on our Central Basin pipeline and our Centerline pipeline. We own a 13% undivided interest in the 218-mile, 20-inch diameter Bravo pipeline, which delivers to the Denver City hub and has a capacity of more than 350 million cubic feet per day. Major delivery points along the line include the Slaughter field in Cochran and Hockley Counties, Texas, and the Wasson field in Yoakum County, Texas. Tariffs on the Cortez and Bravo pipelines are not regulated. In addition, we own approximately 98% of the Canyon Reef Carriers pipeline and approximately 69% of the Pecos pipeline. The Canyon Reef Carriers pipeline extends 138 miles from McCamey, Texas, to the SACROC unit. The pipeline has a 16-inch diameter, a capacity of approximately 290 million cubic feet per day and makes deliveries to the SACROC, Sharon Ridge, Cogdell and Reinecke units. The Pecos pipeline is a 25-mile, 8-inch diameter pipeline that runs from McCamey to Iraan, Texas. We acquired an additional 65% ownership interest in the pipeline on November 1, 2003 from a subsidiary of Marathon Oil Company and are currently delivering through it approximately 70 million cubic feet per day of carbon dioxide. Markets. The principal market for transportation on our carbon dioxide pipelines is to customers using carbon dixoide for enhanced recovery operations in mature oil fields in the Permian Basin, where industry demand is expected to be comparable to historical demand for the next several years. Competition. Our ownership interests in the Central Basin, Cortez and Bravo pipelines are in direct competition with other carbon dioxide pipelines. We also compete with other interest owners in McElmo Dome and Bravo 30 <PAGE> Dome for transportation of carbon dioxide to the Denver City, Texas market area. Oil Reserves The SACROC unit is one of the largest and oldest oil fields in the United States using carbon dioxide flooding technology. The field is comprised of approximately 56,000 acres located in the Permian Basin in Scurry County, Texas. SACROC was discovered in 1948 and has produced over 1.27 billion barrels of oil since inception. We have continued the development of the carbon dioxide project initiated by the previous owners and have reversed the decline in production through increased carbon dioxide injection. Effective June 1, 2003, we increased our interest in SACROC to approximately 97% by acquiring MKM Partners, L.P.'s 12.75% ownership interest. MKM Partners, L.P. was an oil and gas joint venture formed on January 1, 2001 and owned 15% by KMCO2 and 85% by subsidiaries of Marathon Oil Company. The joint venture's assets consisted of a 12.75% interest in the SACROC field unit and a 49.9% interest in the Yates field unit. MKM Partners, L.P. was dissolved effective June 30, 2003, and its net assets were distributed to its partners in accordance with its partnership agreement. As of December 2004, the SACROC unit had 332 producing wells, and the purchased carbon dioxide injection rate was 339 million cubic feet per day, up from an average of 317 million cubic feet per day as of December 2003. The oil production rate as of December 2004 was approximately 33,000 barrels of oil per day, up from approximately 23,000 barrels of oil per day as of December 2003. The Yates unit is also one of the largest oil fields ever discovered in the United States. It is estimated that it originally held more than five billion barrels of oil, of which about 28% has been produced. The field, discovered in 1926, is comprised of approximately 26,000 acres located about 90 miles south of Midland, Texas. Effective November 1, 2003, we increased our interest in Yates and became operator of the field by acquiring an additional 42.5% ownership interest from subsidiaries of Marathon Oil Company. We also acquired the crude oil gathering lines and equipment surrounding the Yates field. We now own a nearly 50% ownership interest in the Yates field unit. As of December 2003, the Yates unit was producing about 18,000 barrels of oil per day. Our plan has been to increase the production life of Yates by combining horizontal drilling with carbon dioxide flooding to ensure a relatively steady production profile over the next several years. We are implementing our plan and as of December 2004, the Yates unit was producing approximately 22,000 barrels of oil per day. Unlike our operations at SACROC, where we use carbon dioxide and water to drive oil to the producing wells, we plan on using carbon dioxide injection to replace nitrogen injection at Yates in order to enhance the gravity drainage process, as well as to maintain reservoir pressure. The differences in geology and reservoir mechanics between the two fields mean that substantially less capital will be needed to develop the reserves at Yates than is required at SACROC. The following table sets forth productive wells, service wells and drilling wells in the oil and gas fields in which we own interests as of December 31, 2004: Productive Wells (a) ServiceWells (b) Drilling Wells (c) --------------------- ----------------- ------------------ Gross Net Gross Net Gross Net --------- --------- ------- -------- -------- -------- Crude Oil... 2,509 1,520 975 723 2 2 Natural Gas. 7 3 - - - - --------- --------- ------- -------- -------- -------- Total Wells. 2,516 1,523 975 723 2 2 ========= ========= ======= ======== ======== ======== ___________ (a) Includes active wells and wells temporarily shut-in. As of December 31, 2004, we did not operate any gross wells with multiple completions. (b) Consists of injection, water supply and disposal wells. (c) Consists of development wells in the process of being drilled as of December 31, 2004. 31 <PAGE> The oil and gas producing fields in which we own interests are located in the Permian Basin area of West Texas. The following table reflects our net productive and dry wells that were completed in each of the three years ended December 31, 2004, 2003 and 2002: 2004 2003 2002 ------- ------ ------- Productive Development....... 31 69 41 Exploratory....... - - - Dry Development....... - - - Exploratory....... - - - ------- ------ ------- Total Wells........ 31 69 41 ======= ====== ======= _________ Notes: The above table includes wells that were completed during each year regardless of the year in which drilling was initiated, and does not include any wells where drilling operations were not completed as of the end of the applicable year. Also, the table includes our previous 15% equity interest in MKM Partners, L.P. MKM Partners, L.P was dissolved on June 30, 2003. Development wells include wells drilled in the proved area of an oil or gas resevoir. The following table reflects the developed and undeveloped oil and gas acreage that we held as of December 31, 2004: Gross Net ----------- ----------- Developed Acres..... 61,928 58,438 Undeveloped Acres... 7,839 7,227 ----------- ----------- Total.............. 69,767 65,665 =========== =========== See Note 19 to our consolidated financial statements included in this report for additional information with respect to our oil and gas producing activities. Gas Plant Interests We operate and own an approximate 22% working interest plus an additional 26% of the net profits of the Snyder gasoline plant, 51% of the Diamond M gas plant and 100% of the North Snyder plant. The Snyder gasoline plant processes gas produced from the SACROC unit and neighboring carbon dioxide projects, specifically the Sharon Ridge and Cogdell units, all of which are located in the Permian Basin area of West Texas. The Diamond M and the North Snyder plants contract with the Snyder plant to process gas. Production of natural gas liquids at the Snyder gasoline plant has increased from approximately 9,076 barrels per day as of December 2003 to approximately 13,375 barrels per day as of December 2004. Crude Oil Pipeline Effective August 31, 2004, we acquired all of the partnership interests in Kaston Pipeline Company, L.P., which we renamed Kinder Morgan Wink Pipeline, L.P. The acquisition included a 450-mile crude oil pipeline system, consisting of four mainline sections, numerous gathering systems and truck off-loading stations. The mainline sections are all located within the State of Texas, and the 20-inch diameter segment that runs from Wink to El Paso has a total capacity of 115,000 barrels of crude oil per day. As part of the transaction, we entered into a long-term throughput agreement with Western Refining Company, L.P. to transport crude oil into Western's 107,000 barrel per day refinery in El Paso. The acquisition allows us to better manage crude oil deliveries from our oil field interests in West Texas. Terminals Our Terminals segment includes the operations of our coal and dry-bulk material services, including all transload, engineering and other in-plant services, as well as all of the operations of our petroleum and petrochemical-related liquids terminal facilities. Combined, the segment is composed of approximately 75 owned or 32 <PAGE> operated liquids and bulk terminal facilities, and more than 55 rail transloading and materials handling facilities located throughout the United States. Our bulk terminal operations primarily involve bulk material handling services; however, we also provide terminal engineering and design services and in-plant services covering material handling, maintenance and repair services, rail car switching services, ship agency and miscellaneous marine services. As part of our bulk terminal operations, we own or operate 18 petroleum coke or coal terminals in the United States. Petroleum coke is a by-product of the refining process and has characteristics similar to coal. Petroleum coke supply in the United States has increased in the last several years due to the increased use of coking units by domestic refineries. Petroleum coke is used in domestic utility and industrial steam generation facilities and is exported to foreign markets. Most of our customers are large integrated oil companies that choose to outsource the storage and loading of petroleum coke for a fee. In 2004, we handled approximately 6.5 million tons of petroleum coke and approximately 27.2 million tons of coal. Combined, our dry-bulk and material transloading facilities handled approximately 67.7 million tons of coal, petroleum coke and other dry-bulk materials in 2004, and our transloading operations handled approximately 75,000 rail cars. Our liquids terminal operations primarily store refined petroleum products, petrochemicals, industrial chemicals, and vegetable oil products, in aboveground storage tanks and transfer products to and from pipelines, tank trucks, tank barges, and tank rail cars. Combined, our liquids terminal facilities possess liquids storage capacity of approximately 36.7 million barrels, and in 2004, these terminals handled approximately 556 million barrels of clean petroleum, petrochemical and vegetable oil products for approximately 250 different customers. We group our bulk and liquids terminal operations into nine regions. This structure allows management to organize and evaluate segment performance and to help make operating decisions and allocate resources. The following is a listing of our nine regions and a summary of the competition faced by our Terminals segment. Terminals Segment - Regions o Midwest o Northeast o Mid-Atlantic o Southeast o Lower Mississippi River o Gulf Coast o West Coast o Materials Services o Ferro Alloys Midwest Region o Argo o Chicago o Cincinnati River o Cincinnati Bulk o Queen City o Dravosburg o Milwaukee o Dakota o Pinney Dock o Owensboro Gateway o Evansville o Ghent o Louisville o Nebraska City o Omaha o St. Joe The Midwest region includes facilities that service industry in the Chicago area and provide products to end-user markets in high population areas along the Ohio River. The facilities handle a wide variety of liquid products, including clean petroleum products, asphalt and residual oil, commodity chemicals, special chemicals and food grade liquids. The services provided at these facilities include receiving and discharging products via pipelines, vessels, tank cars and tank trucks; storing productrs; transferring products; performing specialty handling services (heating, cooling, nitrogen, etc.); and performing drumming services. The region includes two facilities in the Chicago area: one facility is in Argo, Illinois, approximately 14 miles southwest of downtown Chicago. The other facility is located in the Port of Chicago along the Calumet River. The Argo facility is a large throughput fuel ethanol facility and a major break bulk facility for large chemical manufacturers and distributors. It has approximately 2.4 million barrels of capacity in tankage ranging from 50,000 gallons to 80,000 barrels. The Argo terminal is situated along the Chicago sanitary and ship channel, and has three barge docks. The facility is connected to TEPPCO and Westshore pipelines, and has a direct connection to Midway Airport. The Canadian National railroad services this facility. The Port of Chicago facility handles a wide variety of liquids chemicals with a working capacity of approximately 741,000 barrels in tanks ranging from 12,000 gallons to 55,000 barrels. The facility provides access to a full slate of transportation options, including a deep water barge/ship berth on Lake Calumet, and offers services including truck loading and off-loading, iso-container 33 <PAGE> handling and drumming. There are two ship docks and four barge docks, and the facility is served by the Norfolk Southern railroad. The Midwest Region also includes two facilities along the Ohio River in Cincinnati, Ohio. The total storage is approximately 905,000 barrels in tankage ranging from 120 barrels to 96,000 barrels. There are three barge docks, and the NNU and CSX railroads provide rail service. The facilities provide storage for asphalt, heavy oils, and commodity and specialty chemicals. They also offer warehouse services and serve dry bulk handling needs, including salt, coal, soda ash, and agricultural commodities. We also own a bulk terminal located in Dravosburg, Pennsylvania, just south of Pittsburgh along the Monongahela River. There are approximately 242,000 barrels of storage in tanks ranging from 1,200 barrels to 38,000 barrels. There are two barge docks and NS railroad provides rail service. The facility primarily stores asphalt, distillates, wax and other commodities, and offers handling services. Our Midwest region also includes our Milwaukee and Dakota dry-bulk commodity facilities, located in Milwaukee, Wisconsin and St. Paul, Minnesota, respectively. The Milwaukee terminal is located on 34 acres of property leased from the Port of Milwaukee. Its major cargoes are coal and bulk de-icing salt. The Dakota terminal is on 55 acres in St. Paul and primarily handles salt and grain products. In the fourth quarter of 2004, we completed the construction of a new cement loading facility at the Dakota terminal. The project's cost was approximately $20 million, and the facility covers nearly nine acres and includes an unloading system, seven storage silos, a loading and weighing system, and electrical and compressed air systems to move the cement. Included among the remaining Midwest terminals are our Pinney Dock and Owensboro Gateway terminals. Our Pinney Dock terminal is located in Ashtabula, Ohio along Lake Erie. It handles iron ore, titanium ore, magnetite and other aggregates. Pinney Dock has six docks with 15,000 feet of vessel berthing space, 200 acres of outside storage space, 400,000 feet of warehouse space and two 45-ton gantry cranes. The Owensboro Gateway terminal, located near Owensboro, Kentucky, is one of the nation's largest storage and handling points for bulk aluminum. The facility also handles various other bulk materials, as well as a barge scrapping facility. As a result of our acquisition of Kinder Morgan River Terminals LLC, formerly Global Material Services LLC, in October 2004, we added to our Midwest network of terminals, acquiring terminals located in Evansville, Indiana; Ghent, Kentucky; Louisville, Kentucky; Nebraska City, Nebraska; Omaha, Nebraska; and St. Joseph, Missouri. These facilities handle a wide range of products including steel, aluminum, scrap, grain, gypsum, coal, pig iron, fertilizer, silicon metals, stainless slabs, iron, feeds, and lumber. Northeast Region o Carteret o Perth Amboy o Newark o Camden The Northeast region services the northeastern part of the United States from the Port of Philadelphia to the New York Harbor. The facilities in the Northeast region handle a wide variety of liquids products ranging from petroleum products to specialty chemicals. The services provided at these facilities include storing products, and receiving and discharging products via pipelines, vessels, tank cars, tank trucks and inter-modal transfers, utilizing a wide array of automated systems for special product handling. The region includes our two liquids facilities in the New York Harbor area: one in Carteret, New Jersey and the other in Perth Amboy, New Jersey. The Carteret facility is located along the Arthur Kill River just south of New York City and has a capacity of approximately 7.7 million barrels of petroleum and petrochemical products, of which 1.1 million barrels have been added since our acquisition of the Carteret terminal in January 2001. In addition, in October 2003, we completed the construction of a new 16-inch diameter pipeline at Carteret that connects to the Buckeye pipeline system, a major products pipeline serving the East Coast. Our Carteret facility has two ship docks with a 37-foot mean low water depth and four barge docks. It is connected to the Colonial, Buckeye, Sun and Harbor pipeline systems, and the CSX and Norfolk Southern railroads service the facility. The Perth Amboy facility is also located along the Arthur Kill River and has a capacity of approximately 2.3 million barrels of petroleum and petrochemical products. Tank sizes range from 2,000 barrels to 300,000 barrels. The Perth Amboy terminal provides chemical and petroleum storage and handling, as well as dry-bulk handling of salt and aggregates. 34 <PAGE> In addition to providing product movement via vessel, truck and rail, Perth Amboy has direct access to the Buckeye and Colonial pipelines. The facility has one ship dock and one barge dock, and is connected to the CSX and Norfolk Southern railroads. Our two New Jersey facilities offer a viable alternative for moving petroleum products between the refineries and terminals throughout the New York Harbor and both are New York Mercantile Exchange delivery points for gasoline and heating oil. Both facilities are connected to the Intra Harbor Transfer Service, an operation that offers direct outbound pipeline connections that allow product to be moved from over 20 Harbor delivery points to destinations north and west of New York City. The Northeast region also includes the assets of our Port Newark bulk terminal located at Port Newark, New Jersey and our Camden bulk terminal, located along the Delaware River in Camden, New Jersey. Our Port Newark facility offers almost 13 acres of outdoor storage for both de-icing and industrial salt, vermiculite and other bulk products. Its assets include three floating cranes, nine wheel loaders and three track bulldozers. The facility allows us to offer ship, truck and rail storage, ship load out to trucks or rail, or truck and rail load out to ships. Our Camden facility transfers scrap metal, vermiculite and other mineral products. Mid-Atlantic Region o Pier IX o Shipyard River o Philadelphia o Chesapeake Bay o Fairless Hills o Cora o Grand Rivers o North Charleston This region includes our Pier IX Terminal located in Newport News, Virginia. The terminal originally opened in 1983 and has the capacity to transload approximately 12 million tons of coal annually. It can store 1.3 million tons of coal on its 30-acre storage site. For coal, the terminal offers blending services and rail to storage or direct transfer to ship; for other dry bulk products, the terminal offers ship to storage to rail or truck. In addition, the Pier IX Terminal operates a cement facility, which has the capacity to transload over 400,000 tons of cement annually. Since late 2002, Pier IX has operated a synfuel plant on site, and in early 2004, Pier IX began to operate a second synfuel plant on site. Volumes of synfuel produced in 2004 were 3.1 million tons. Our Pier IX Terminal exports coal to foreign markets, serves power plants on the eastern seaboard of the United States, and imports cement pursuant to a long-term contract. The Pier IX Terminal is served by the CSX Railroad, which transports coal from central Appalachian and other eastern coal basins. Cement imported to the Pier IX Terminal primarily originates in Europe. Also included in the Mid-Atlantic region is our Shipyard River Terminal, located in Charleston, South Carolina. Shipyard is able to unload, store and reload coal imported from various foreign countries. The imported coal is often a cleaner-burning, low-sulfur coal and it is used by local utilities to comply with the U.S. Clean Air Act. Shipyard River Terminal has the capacity to handle approximately 2.5 million tons of coal and petroleum coke per year and offers approximately 300,000 tons of total storage of which 50,000 tons are under roof. Situated approximately four miles north of Shipyard, is our North Charleston Terminal, which we acquired in April 2004. This facility sits on 30 acres of land and has the potential to handle dry bulk as well as liquids. In aggregate terms, the facility can store 430,000 barrels of liquids in seven tanks. Both CSX and NS have railroad service nearby. Our Philadelphia, Pennsylvania liquids terminal is located on the Delaware River and offers a storage capacity of over 1.2 million barrels. A variety of tank system configurations are available including stainless steel and pressure vessels for the storage of specialty chemicals. The storage and handling of petroleum and petroleum based products are also strong components in Philadelphia's base service. Our Chesapeake Bay bulk terminal facility located at Sparrows Point, Maryland, offers stevedoring services, storage, and rail, ground, or water transportation for products such as coal, petroleum coke, iron and steel slag, and other mineral products. It offers both warehouse and approximately 100 acres of open storage. Effective December 1, 2004, we acquired substantially all of the assets used to operate the major port distribution facility located at the Fairless Industrial Park in Bucks County, Pennsylvania. Opened in 1997 and 35 <PAGE> recognized as a major steel distribution facility, the terminal is referred to as our Kinder Morgan Fairless Hills Terminal. It is located on the bend of the Delaware River below Trenton, New Jersey and is the largest port on the East Coast for the handling of semi-finished steel slabs. The port operations at Fairless Hills also include the handling of other types of steel and specialized cargo that caters to the construction industry and service centers that use steel sheet and plate. The port has four ship berths with a total length of 2,200 feet and a maximum draft of 38.5 feet. It contains two mobile harbor cranes and is served by connections to two Class I rail lines: CSX and Norfolk Southern. The region also includes two large coal terminals: our Cora terminal and our Grand Rivers terminal. Our Cora terminal is a high-speed, rail-to-barge coal transfer and storage facility. Built in 1980, the terminal is located on approximately 480 acres of land along the upper Mississippi River near Cora, Illinois, about 80 miles south of St. Louis, Missouri. The terminal has a throughput capacity of about 15 million tons per year and is currently equipped to store up to one million tons of coal. This storage capacity provides customers the flexibility to coordinate their supplies of coal with the demand at power plants. Our Cora terminal sits on the mainline of the Union Pacific Railroad and is strategically positioned to receive coal shipments from the western United States. Our Grand Rivers terminal is a coal transloading and storage facility located along the Tennessee River just above the Kentucky Dam. The terminal is operated on land under easements with an initial expiration of July 2014 and has current annual throughput capacity of approximately 12 million tons with a storage capacity of approximately one million tons. Grand Rivers provides easy access to the Ohio-Mississippi River network and the Tennessee-Tombigbee River system. The Paducah & Louisville Railroad, a short line railroad, serves Grand Rivers with connections to seven Class I rail lines including the Union Pacific, CSX, Illinois Central and Burlington Northern Santa Fe. Our Cora and Grand Rivers terminals handle low sulfur coal originating in Wyoming, Colorado, and Utah, as well as coal that originates in the mines of southern Illinois and western Kentucky. However, since many shippers, particularly in the East, are using western coal or a mixture of western coal and other coals as a means of meeting environmental restrictions, we anticipate that growth in volume through the terminals will be primarily due to increased use of western low sulfur coal originating in Wyoming, Colorado and Utah. Coal continues to be the fuel of choice for electric generation, accounting for more than 50% of United States electric generation feedstock. Forecasts of overall coal usage and power plant usage for the next 20 years show an increase of about 1.5% per year. Current domestic supplies are predicted to last for several hundred years. Most coal transloaded through our coal terminals is destined for use in coal-fired electric generation. We believe that obligations to comply with the Clean Air Act Amendments of 1990 will cause shippers to increase the use of cleaner burning low sulfur coal from the western United States and from foreign sources. Approximately 80% of the coal loaded through our Cora and Grand Rivers terminals is low sulfur coal originating from mines located in the western United States, including the Hanna and Powder River basins in Wyoming, western Colorado and Utah. In 2004, four major customers accounted for approximately 90% of all the coal loaded through our Cora Terminal. Southeast Region o Tampaplex o Port Sutton o Port Manatee o Hartford Street o Elizabeth River o Nassau o Blackpoint This region includes our Kinder Morgan Tampaplex terminal, a marine terminal acquired in December 2003 and located in Tampa, Florida. The terminal sits on a 114-acre site and serves as a storage and receipt point for imported ammonia, as well as an export location for dry bulk products, including fertilizer and animal feed. The terminal also includes an inland bulk storage warehouse facility used for overflow cargoes from our Port Sutton import terminal, which is also located in Tampa. Port Sutton sits on 16 acres of land and offers 200,000 tons of covered storage. Primary products handled in 2004 included fertilizers, salt, ores, and liquid chemicals. Also in the Tampa Bay area are our Port Manatee and Hartford Street terminals. Port Manatee has four warehouses which can store 130,000 tons of bulk products. Products handled at Port Manatee include fertilizers, ores and other general cargo. At our 36 <PAGE> Hartford Street terminal, anhydrous ammonia and fertilizers are handled and stored in two warehouses with an aggregate capacity of 23,000 net tons. The Southeast region also includes our Elizabeth River bulk terminal, located in Chesapeake, Virginia, and our Nassau bulk terminal, located in Fernandina Beach, Florida. The Elizabeth River terminal offers over 500,000 square feet of covered storage and approximately ten acres of outdoor storage for products such as fertilizers, ores and minerals and various feeds and grains. Nassau offers approximately 180,000 square feet of warehouse storage and ten acres of container yard storage, and provides stevedoring services and containerized cargo services for various forest products. Lower Mississippi River (Louisiana) Region o Harvey o St. Gabriel o IMT o Gramercy o Barge Canal Dock o BR Liquid Dock o Chalmette o Amory Bulk o Belle Helene o Ft. Smith Warehouse o W. Memphis Reload o W. Memphis Terminal o Decatur o Vicksburg o Delisle o Ft. Smith Terminal o Globalplex o Great Lakes Carbon o Guntersville o Helena o Memphis Terminal o Pine Bluff o Port Arthur o P.C.S. The region consists of various bulk and liquid terminal facilities and related assets located primarily on the southern edge of the lower Mississippi River. These terminals serve customers in the alumina, cement, salt, soda ash, ilmenite, fertilizer, ore and other industries seeking specialists who can build, own and operate terminals. Two of the region's largest liquids facilities in South Louisiana are: our Port of New Orleans facility located in Harvey, Louisiana, and our St. Gabriel terminal, located near a major petrochemical complex in Geismar, Louisiana. The New Orleans facility handles a variety of liquids products such as chemicals, vegetable oils, animal fats, alcohols and oil field products. It has approximately three million barrels of total tanks ranging in sizes from 416 barrels to 200,000 barrels. There are three ship docks and one barge dock, and the Union Pacific railroad provides rail service. The terminal can be accessed by vessel, barge, tank truck, or rail, and also provides ancillary services including drumming, packaging, warehousing, and cold storage services. Our St. Gabriel facility is located approximately 75 miles north of the New Orleans facility on the left descending bank of the Mississippi River near the town of St. Gabriel, Louisiana. The facility has approximately 340,000 barrels of tank capacity and the tanks vary in sizes ranging from 1,500 barrels to 80,000 barrels. There are three local pipeline connections at the facility which enable the movement of products from the facility to the petrochemical plants in Geismar, Louisiana. The region also includes our 66 2/3% ownership interest in the International Marine Terminals Partnership. IMT operates a bulk commodity transfer terminal facility located in Port Sulphur, Louisiana. In 2004, the facility handled approximately 11.9 million tons of iron ore, coal, petroleum coke and barite. The Port Sulphur location is a multi-purpose import and export facility that utilizes land and a dock facility. It contains storage capacity of approximately 50 acres that can handle 1.3 million tons of coal and/or petroleum coke. An additional 100 acres is currently undeveloped. The Lower Mississippi Region also has in-plant operations, where we staff and operate the loading and unloading equipment for specific customers. For example, at our Chalmette, Louisiana facility, we load barges with petroleum coke; at our Gramercy bulk terminal, located in Mt. Airy, Louisiana, we provide rail switching services and we transfer alumina from railcars to barges. Gulf Coast Region o Pasadena o Galena Park This region includes our Houston, Texas terminal complex, located in Pasadena and Galena Park, Texas, along the Houston Ship Channel. Recognized as a distribution hub for Houston's refineries situated on or near the Houston Ship Channel, the Pasadena and Galena Park terminals are the western Gulf Coast refining community's central interchange point. The complex has approximately 17.7 million barrels of capacity and is connected via pipeline to 14 refineries, four petrochemical plants and ten major outbound pipelines. 37 <PAGE> Since our acquisition of the terminal complex in January 2001, we have added more than one million barrels of new storage capacity, as refinery outputs along the Gulf Coast have continued to increase. We have also upgraded our pipeline manifold connection with the Colonial pipeline system, added pipeline connections to new refineries and expanded our truck rack. In addition, the facilities have four ship docks and seven barge docks for inbound and outbound movement of products. The terminals are served by the Union Pacific railroad. West Region o Benicia o LAXT o Longview o Portland o Vancouver We own or operate five bulk terminals located primarily on the West Coast. These terminals serve customers in the alumina, petroleum coke, salt, soda ash, fertilizer, and other dry bulk product industries. The West region includes our Portland Bulk Terminal #4 facility and our Benicia Coke terminal. Portland Bulk Terminal #4 is located in Portland, Oregon and exports approximately two million tons of soda ash per year to markets in southeast Asia. It has an annual capacity of approximately 3.6 million tons. The Benicia Coke terminal, located in Benicia, California, takes fluid bed green petroleum coke from railcars to storage silos and from storage to ship. It has an annual capacity of approximately 350,000 tons. Also included in the West region is the Los Angeles Export Terminal, where operations primary consist of loading vessels carrying coal and petroleum coke. LAXT, which is served by the Union Pacific railroad, has two million tons of outdoor storage space and 100,000 tons of covered storage space. Materials Services (rail transloading) Region o Transloading (55) o Brooklyn Junction o Moundsville o New Johnsonville This region primarily includes the rail-transloading operations owned by Kinder Morgan Materials Services LLC, referred to in this report as KMMS. KMMS operates approximately 55 rail transloading facilities, of which 47 are located east of the Mississippi River. The CSX, Norfolk Southern, Union Pacific, Kansas City Southern and A&W railroads provide rail service for these terminal facilities. Approximately 50% of the products handled by KMMS are liquids, including an entire spectrum of liquid chemicals, and 50% are dry bulk products. Many of the facilities are equipped for bi-modal operation (rail-to-truck, and truck-to-rail). KMMS also designs and builds transloading facilities, performs inventory management services, and provides value-added services such as blending, heating and sparging. Ferro Alloys Region o Chicago o Decatur o Houston o Industry o Mingo Junction o Netherlands The terminal operations included in our Ferro Alloys region were acquired as part of our acquisition of Kinder Morgan River Terminals LLC in October 2004. The region includes six terminal facilities or locations that specialize in the handling of ferro alloys, pig iron and other bulk supplies for the metals industries. Each terminal provides general commodity or alloy services as needed by local markets. Engineering and Other This segment includes the engineering operations of RCI Holdings, Inc., a major engineering and construction management company. RCI is a wholly-owned subsidiary that specializes in providing design and construction services for dry bulk material handling terminals. Their offices are located in Metairie, Louisiana, and Columbus, Ohio. 38 <PAGE> Competition We are one of the largest independent operators of liquids and bulk terminals in North America. Our primary competitors are Magellan, Kaneb, IMTT, Vopak, Oil Tanking, TransMontaigne, and Savage Industries. Our petroleum coke and other bulk terminals compete with numerous independent terminal operators, other terminals owned by oil companies and other industrials opting not to outsource terminal services. Many of our other bulk terminals were constructed pursuant to long-term contracts for specific customers. As a result, we believe other terminal operators would face a significant disadvantage in competing for this business. Two new coal terminals that compete with our Cora terminal and our Grand Rivers terminal were completed in 2003. While our Cora and Grand Rivers terminals are modern high capacity coal terminals, in 2004, some volume was diverted to the new terminals by the Tennessee Valley Authority in order to promote increased competition. Our Pier IX terminal competes primarily with two modern coal terminals located in the same Virginian port complex as our Pier IX terminal. Major Customers Our total operating revenues are derived from a wide customer base. For each of the years ended December 31, 2004, 2003 and 2002, only one customer accounted for more than 10% of our total consolidated revenues. Total transactions with CenterPoint Energy accounted for 14.3% of our total consolidated revenues during 2004, 16.8% of our total consolidated revenues during 2003 and 15.6% of our total consolidated revenues during 2002. The high percentage of our total revenues attributable to CenterPoint Energy directly relates to the growth of our Natural Gas Pipelines segment, especially since our acquisition of Kinder Morgan Tejas on January 31, 2002. Due to this acquisition and the subsequent formation of our Texas intrastate natural gas group, we have realized significant increases in the volumes of natural gas we buy and sell within the State of Texas. As a result, both our total consolidated revenues and our total consolidated purchases (cost of sales) have increased considerably since the beginning of 2002 due to the inclusion of the cost of gas in both financial statement line items. These higher revenues and higher purchased gas cost do not necessarily translate into increased margins in comparison to those situations in which we charge to transport gas owned by others. We do not believe that a loss of revenues from any single customer would have a material adverse effect on our business, financial position, results of operations or cash flows. Regulation Interstate Common Carrier Regulation Some of our pipelines are interstate common carrier pipelines, subject to regulation by the Federal Energy Regulatory Commission under the Interstate Commerce Act. The ICA requires that we maintain our tariffs on file with the FERC, which tariffs set forth the rates we charge for providing transportation services on our interstate common carrier pipelines as well as the rules and regulations governing these services. Petroleum products pipelines may change their rates within prescribed ceiling levels that are tied to an inflation index. Shippers may protest rate increases made within the ceiling levels, but such protests must show that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline's increase in costs from the previous year. A pipeline must, as a general rule, utilize the indexing methodology to change its rates. The FERC, however, uses cost-of-service ratemaking, market-based rates and settlement rates as alternatives to the indexing approach in certain specified circumstances. During the first quarter of 2003, the FERC made a significant positive adjustment to the index which petroleum products pipelines use to adjust their regulated tariffs for inflation. The old index used percent growth in the producer price index for finished goods, and then subtracted one percent. The new index eliminated the one percent reduction. As a result, we filed for indexed rate adjustments on a number of our petroleum products pipelines and realized benefits from the new index beginning in the second quarter of 2003. Rate adjustments pursuant to the index were made on a number of pipeline systems in 2004. 39 <PAGE> The ICA requires, among other things, that such rates on interstate common carrier pipelines be "just and reasonable" and nondiscriminatory. The ICA permits interested persons to challenge newly proposed or changed rates and authorizes the FERC to suspend the effectiveness of such rates for a period of up to seven months and to investigate such rates. If, upon completion of an investigation, the FERC finds that the new or changed rate is unlawful, it is authorized to require the carrier to refund the revenues in excess of the prior tariff collected during the pendency of the investigation. The FERC may also investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained during the two years prior to the filing of a complaint. On October 24, 1992, Congress passed the Energy Policy Act of 1992. The Energy Policy Act deemed petroleum products pipeline tariff rates that were in effect for the 365-day period ending on the date of enactment or that were in effect on the 365th day preceding enactment and had not been subject to complaint, protest or investigation during the 365-day period to be just and reasonable or "grandfathered" under the ICA. The Energy Policy Act also limited the circumstances under which a complaint can be made against such grandfathered rates. The rates we charge for transportation service on our North System and Cypress Pipeline were not suspended or subject to protest or complaint during the relevant 365-day period established by the Energy Policy Act. For this reason, we believe these rates should be grandfathered under the Energy Policy Act. Certain rates on our Pacific operations' pipeline system were subject to protest during the 365-day period established by the Energy Policy Act. Accordingly, certain of the Pacific pipelines' rates have been, and continue to be, subject to complaints with the FERC, as is more fully described in Note 16 to our consolidated financial statements included elsewhere in this report. Both the performance of and rates charged by companies performing interstate natural gas transportation and storage services are regulated by the FERC under the Natural Gas Act and, to a lesser extent, the Natural Gas Policy Act. Beginning in the mid-1980's, the FERC initiated a number of regulatory changes intended to create a more competitive environment in the natural gas marketplace. Among the most important of these changes were: o Order No. 436 (1985) requiring open-access, nondiscriminatory transportation of natural gas; o Order No. 497 (1988) which set forth new standards and guidelines imposing certain constraints on the interaction between interstate natural gas pipelines and their marketing affiliates and imposing certain disclosure requirements regarding that interaction; and o Order No. 636 (1992) which required interstate natural gas pipelines that perform open-access transportation under blanket certificates to "unbundle" or separate their traditional merchant sales services from their transportation and storage services and to provide comparable transportation and storage services with respect to all natural gas supplies whether purchased from the pipeline or from other merchants such as marketers or producers. Natural gas pipelines must now separately state the applicable rates for each unbundled service they provide (i.e., for the natural gas commodity, transportation and storage). Order 636 contains a number of procedures designed to increase competition in the interstate natural gas industry, including: o requiring the unbundling of sales services from other services; o permitting holders of firm capacity on interstate natural gas pipelines to release all or a part of their capacity for resale by the pipeline; and o the issuance of blanket sales certificates to interstate pipelines for unbundled services. Order 636 has been affirmed in all material respects upon judicial review, and our own FERC orders approving our unbundling plans are final and not subject to any pending judicial review. 40 <PAGE> On November 25, 2003, the Federal Energy Regulatory Commission issued Order No. 2004, adopting revised Standards of Conduct that apply uniformly to interstate natural gas pipelines and public utilities. In light of the changing structure of the energy industry, these Standards of Conduct govern relationships between regulated interstate natural gas pipelines and all of their energy affiliates. These new Standards of Conduct were designed to eliminate the loophole in the previous regulations that did not cover an interstate natural gas pipeline's relationship with energy affiliates that are not marketers. The rule is designed to prevent interstate natural gas pipelines from giving an undue preference to any of their energy affiliates and to ensure that transmission is provided on a nondiscriminatory basis. In addition, unlike the prior regulations, these requirements apply even if the energy affiliate is not a customer of its affiliated interstate pipeline. The effective date of Order No. 2004 was September 22, 2004. Our interstate natural gas pipelines have implemented compliance with these Standards of Conduct. Please refer to Note 16 to our consolidated financial statements included elsewhere in this report for additional information regarding FERC Order No. 2004 and other Standards of Conduct Rulemaking. California Public Utilities Commission The intrastate common carrier operations of our Pacific operations' pipelines in California are subject to regulation by the California Public Utilities Commission under a "depreciated book plant" methodology, which is based on an original cost measure of investment. Intrastate tariffs filed by us with the CPUC have been established on the basis of revenues, expenses and investments allocated as applicable to the California intrastate portion of our Pacific operations' business. Tariff rates with respect to intrastate pipeline service in California are subject to challenge by complaint by interested parties or by independent action of the CPUC. A variety of factors can affect the rates of return permitted by the CPUC, and certain other issues similar to those which have arisen with respect to our FERC regulated rates could also arise with respect to our intrastate rates. Certain of our Pacific operations' pipeline rates have been, and continue to be, subject to complaints with the CPUC, as is more fully described in Note 16 to our consolidated financial statements. Safety Regulation Our interstate pipelines are subject to regulation by the United States Department of Transportation and our intrastate pipelines and other operations are subject to comparable state regulations with respect to their design, installation, testing, construction, operation, replacement and management. We must permit access to and copying of records, and make certain reports and provide information as required by the Secretary of Transportation. Comparable regulation exists in some states in which we conduct pipeline operations. In addition, our truck and terminal loading facilities are subject to U.S. DOT regulations dealing with the transportation of hazardous materials by motor vehicles and rail cars. We believe that we are in substantial compliance with U.S. DOT and comparable state regulations. The Pipeline Safety Improvement Act of 2002 was signed into law on December 17, 2002, governing the areas of testing, education, training and communication. The Act requires pipeline companies to perform integrity tests on natural gas transmission pipelines that exist in high population density areas that are designated as High Consequence Areas. Pipeline companies are required to perform the integrity tests within ten years of the date of enactment and must perform subsequent integrity tests on a seven year cycle. At least 50% of the highest risk segments must be tested within five years of the enactment date. The risk ratings are based on numerous factors, including the population density in the geographic regions served by a particular pipeline, as well as the age and condition of the pipeline and its protective coating. Testing consists of hydrostatic testing, internal electronic testing, or direct assessment of the piping. In addition to the pipeline integrity tests, pipeline companies must implement a qualification program to make certain that employees are properly trained, and the U.S. DOT has approved our qualification program. We believe that we are in substantial compliance with this law's requirements and have integrated appropriate aspects of this pipeline safety law into our Operator Qualification Program, which is already in place and functioning. A similar integrity management rule for refined petroleum products pipelines became effective May 29, 2001. All baseline assessments for products pipelines must be completed by March 31, 2008. Certain of our products pipelines and natural gas pipelines have been issued orders and civil penalties by the U.S. DOT's Office of Pipeline Safety concerning alleged violations of certain federal regulations concerning our pipeline Integrity Management Program. However, we dispute some of the findings, disagree that civil penalties are 41 <PAGE> appropriate for them, and have requested an administrative hearing on these matters according to the U.S. DOT regulations. Information on these matters is more fully described in Note 16 to our consolidated financial statements. On March 25, 2003, the U.S. DOT issued their final rules on Hazardous Materials: Security Requirements for Offerors and Transporters of Hazardous Materials. We believe that we are in substantial compliance with these rules and have made revisions to our Facility Security Plan to remain consistent with the requirements of these rules. We are also subject to the requirements of the Federal Occupational Safety and Health Act and other comparable federal and state statutes. We believe that we are in substantial compliance with Federal OSHA requirements, including general industry standards, recordkeeping requirements and monitoring of occupational exposure to hazardous substances. In general, we expect to increase expenditures in the future to comply with higher industry and regulatory safety standards. Some of these changes, such as U.S. DOT implementation of additional hydrostatic testing requirements, could significantly increase the amount of these expenditures. Such expenditures cannot be accurately estimated at this time. State and Local Regulation Our activities are subject to various state and local laws and regulations, as well as orders of regulatory bodies, governing a wide variety of matters, including: o marketing; o production; o pricing; o pollution; o protection of the environment; and o safety. Environmental Matters Our operations are subject to federal, state and local, and some foreign laws and regulations governing the release of regulated materials into the environment or otherwise relating to environmental protection or human health or safety. We believe that our operations are in substantial compliance with applicable environmental laws and regulations. Any failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of remedial requirements, issuance of injunction as to future compliance or other mandatory or consensual measures. We have an ongoing environmental compliance program. However, risks of accidental leaks or spills are associated with the transportation and storage of natural gas liquids, refined petroleum products, natural gas and carbon dioxide, the handling and storage of liquid and bulk materials and the other activities conducted by us. There can be no assurance that we will not incur significant costs and liabilities relating to claims for damages to property, the environment, natural resources, or persons resulting from the operation of our businesses. Moreover, it is possible that other developments, such as increasingly strict environmental laws and regulations and enforcement policies thereunder, could result in increased costs and liabilities to us. Environmental laws and regulations have changed substantially and rapidly over the last 35 years, and we anticipate that there will be continuing changes. One trend in environmental regulation is to increase reporting obligations and place more restrictions and limitations on activities, such as emissions of pollutants, generation and disposal of wastes and use, storage and handling of chemical substances that may impact human health and safety or the environment. Increasingly strict environmental restrictions and limitations have resulted in increased operating costs for us and other similar businesses throughout the United States. It is possible that the costs of compliance 42 <PAGE> with environmental laws and regulations may continue to increase. We will attempt to anticipate future regulatory requirements that might be imposed and to plan accordingly, but there can be no assurance that we will identify and properly anticipate each such charge, or that our efforts will prevent material costs, if any, from arising. We are currently involved in environmentally related legal proceedings and clean up activities. Although no assurance can be given, we believe that the ultimate resolution of all these environmental matters will not have a material adverse effect on our business, financial position or results of operations. We have accrued an environmental reserve in the amount of $40.9 million as of December 31, 2004. Our reserve estimates range in value from approximately $40.9 million to approximately $77.6 million, and we have recorded a liability equal to the low end of the range. For additional information related to environmental matters, see Note 16 to our consolidated financial statements included elsewhere in this report. Solid Waste We own numerous properties that have been used for many years for the production of crude oil, natural gas and carbon dioxide, the transportation and storage of refined petroleum products and natural gas liquids and the handling and storage of coal and other liquid and bulk materials. Virtually all of these properties were owned by others before us. Solid waste disposal practices within the petroleum industry have changed over the years with the passage and implementation of various environmental laws and regulations. Hydrocarbons and other solid wastes may have been disposed of in, on or under various properties owned by us during the operating history of the facilities located on such properties. Virtuallly all of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other solid wastes was not under our control. In such cases, hydrocarbons and other solid wastes could migrate from the facilities and have an adverse effect on soils and groundwater. We maintain a reserve to account for the costs of cleanup at sites known to have surface or subsurface contamination requiring response action. We generate both hazardous and nonhazardous solid wastes that are subject to the requirements of the Federal Resource Conservation and Recovery Act and comparable state statutes. From time to time, state regulators and the United States Environmental Protection Agency consider the adoption of stricter disposal standards for nonhazardous waste. Furthermore, it is possible that some wastes that are currently classified as nonhazardous, which could include wastes currently generated during pipeline or liquids or bulk terminal operations, may in the future be designated as "hazardous wastes." Hazardous wastes are subject to more rigorous and costly disposal requirements than nonhazardous wastes. Such changes in the regulations may result in additional capital expenditures or operating expenses for us. Superfund The Comprehensive Environmental Response, Compensation and Liability Act, also known as the "Superfund" law or "CERCLA," and analogous state laws, impose joint and several liability, without regard to fault or the legality of the original conduct, on certain classes of "potentially responsible persons" for releases of "hazardous substances" into the environment. These persons include the owner or operator of a site and companies that disposed of or arranged for the disposal of the hazardous substances found at the site. CERCLA authorizes the U.S. EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur, in addition to compensation for natural resource damages, if any. Although "petroleum" is excluded from CERCLA's definition of a "hazardous substance," in the course of our ordinary operations, we have and will generate materials that may fall within the definition of "hazardous substance." By operation of law, if we are determined to be a potentially responsible person, we may be responsible under CERCLA for all or part of the costs required to clean up sites at which such materials are present, in addition to compensation for natural resource damages, if any. Clean Air Act Our operations are subject to the Clean Air Act and analogous state statutes. We believe that the operations of our pipelines, storage facilities and terminals are in substantial compliance with such statutes. 43 <PAGE> Numerous amendments to the Clean Air Act were adopted in 1990. These amendments contain lengthy, complex provisions that may result in the imposition over the next several years of certain pollution control requirements with respect to air emissions from the operations of our pipelines, treating facilities, storage facilities and terminals. Depending on the nature of those requirements and any additional requirements that may be imposed by state and local regulatory authorities, we may be required to incur certain capital expenditures over the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals and addressing other air emission-related issues. Due to the broad scope and complexity of the issues involved and the resultant complexity and nature of the regulations, full development and implementation of many Clean Air Act regulations have been delayed. Until such time as the new Clean Air Act requirements are implemented, we are unable to fully estimate the effect on earnings or operations or the amount and timing of such required capital expenditures. At this time, however, we do not believe that we will be materially adversely affected by any such requirements. Clean Water Act Our operations can result in the discharge of pollutants. The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws impose restrictions and controls regarding the discharge of pollutants into state waters or waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by applicable federal or state authorities. The Oil Pollution Act was enacted in 1990 and amends provisions of the Clean Water Act as they pertain to prevention and response to oil spills. Spill prevention control and countermeasure requirements of the Clean Water Act and some state laws require diking and similar structures to help prevent contamination of navigable waters in the event of an overflow or release. We believe we are in substantial compliance with these laws. EPA Fuel Specifications/Gasoline Volatility Restrictions In order to control air pollution in the United States, the U.S. EPA has adopted regulations that require the vapor pressure of motor gasoline sold in the United States to be reduced from May through mid-September of each year. These regulations mandated vapor pressure reductions beginning in 1989, with more stringent restrictions beginning in 1992. States may impose additional volatility restrictions. The regulations have had a substantial effect on the market price and demand for normal butane, and to some extent isobutane, in the United States. Gasoline manufacturers use butanes in the production of motor gasolines. Since normal butane is highly volatile, it is now less desirable for use in blended gasolines sold during the summer months. Although the U.S. EPA regulations have reduced demand and may have contributed to a significant decrease in prices for normal butane, low normal butane prices have not impacted our pipeline business in the same way they would impact a business with commodity price risk. The U.S. EPA regulations have presented the opportunity for additional transportation services on portions of our liquid pipeline systems, for example, our North System. In the summer of 1991, our North System began long-haul transportation of refinery grade normal butane produced in the Chicago area to the Bushton, Kansas area for storage and subsequent transportation north from Bushton during the winter gasoline blending season. That service continues, and we also provide transportation and storage of butane from the Chicago area back to Bushton during the summer season. Methyl Tertiary-Butyl Ether Methyl tertiary-butyl ether (MTBE) is used as an additive in gasoline. It is manufactured by chemically combining a portion of petrochemical production with purchased methanol. Due to environmental and health concerns, California mandated the elimination of MTBE from gasoline by January 1, 2004. Furthermore, both the United States House of Representatives and the United States Senate have introduced legislation that would gradually phase out the use of MTBE as a gasoline blendstock and bar the use of MTBE within four years of enactment. We cannot provide assurances regarding the likelihood of the passage of such legislation. In California, MTBE-blended gasoline has been replaced by an ethanol blend. However, ethanol cannot be shipped through pipelines and therefore, we have realized some reduction in California gasoline volumes transported by our Pacific operations' pipelines. However, the conversion from MTBE to ethanol in California has resulted in 44 <PAGE> an increase in ethanol blending services at many of our refined petroleum product terminal facilities, and the fees we earn for new ethanol-related services at our terminals more than offsets the reduction in pipeline transportation fees. Furthermore, we have aggressively pursued additional ethanol opportunities. Our role in conjunction with ethanol is proving beneficial to our various business segments as follows: o our Products Pipelines' terminals are blending ethanol because unlike MTBE, it cannot flow through pipelines; o our Natural Gas Pipelines segment is delivering natural gas through our pipelines to service new ethanol plants that are being constructed in the Midwest (natural gas is the feedstock for ethanol plants); and o our Terminals segment is entering into liquid storage agreements for ethanol around the country, in such areas as Houston, Nebraska and on the East Coast. Risk Factors Like all businesses, we face various obstacles, including escalating employee health and benefit costs, environmental issues and rising legal fees. Regulatory challenges to our pipeline transportation rates, including the current case involving our Pacific operations' pipelines, and possible policy changes and/or reparation and refund payments ordered by governmental regulatory entities could negatively affect our future financial performance. Further, we are well-aware of the general uncertainty associated with the current world economic and political environments in which we exist and we recognize that we are not immune to the fact that our financial performance is impacted by overall marketplace spending and demand. We are continuing to assess the effect that terrorism would have on our businesses and in response, we have increased security at our assets. Recent federal legislation provides an insurance framework that should cause current insurers to continue to provide sabotage and terrorism coverage under standard property insurance policies. Nonetheless, there is no assurance that adequate sabotage and terrorism insurance will be available at reasonable rates throughout 2005. Currently, we do not believe that the increased cost associated with these measures will have a material effect on our operating results. Some of our specifically identified risk factors are as follows: Pending Federal Energy Regulatory Commission and California Public Utilities Commission proceedings seek substantial refunds and reductions in tariff rates on some of our pipelines. If the proceedings are determined adversely, they could have a material adverse impact on us. Regulators and shippers on our pipelines have rights to challenge the rates we charge under certain circumstances prescribed by applicable regulations. Some shippers on our pipelines have filed complaints with the Federal Energy Regulatory Commission and California Public Utilities Commission that seek substantial refunds for alleged overcharges during the years in question and prospective reductions in the tariff rates on our Pacific operations' pipeline system. The FERC complaints, separately docketed in two different proceedings, predominantly attacked the interstate pipeline tariff rates of our Pacific operations' pipeline system, contending that the rates were not just and reasonable under the Interstate Commerce Act and should not be entitled to "grandfathered" status under the Energy Policy Act. Hearings on the second of these two proceedings began in October 2001. On June 24, 2003, a non-binding, phase one initial decision was issued by an administrative law judge hearing a FERC case on the rates charged by our Pacific operations' interstate portion of its pipelines. In his phase one initial decision, the administrative law judge recommended that the FERC "ungrandfather" our Pacific operations' interstate rates and found most of our Pacific operations' rates at issue to be unjust and unreasonable. On March 26, 2004, the FERC issued an order on the phase one initial decision that reversed the initial decision by finding that our Pacific operations' rates for its North and Oregon Lines should remain "grandfathered" and amended the initial decision by finding that SFPP's West Line rates (i) to Yuma and Tucson, Arizona and to our CALNEV Pipeline, as of 1995, and (ii) to Phoenix, Arizona, as of 1997, should no longer be "grandfathered" and are not just and reasonable. If these rates are "ungrandfathered," they could be lowered prospectively and complaining shippers could be entitled to reparations for prior periods. 45 <PAGE> On September 9, 2004, a non-binding, phase two initial decision was issued by an administrative law judge hearing the FERC case on the rates charged by our Pacific operations' interstate portion of its pipelines. If affirmed by the FERC, the phase two initial decision would establish the basis for prospective rates and the calculation of reparations for complaining shippers with respect to our Pacific operations' West Line and East Line. However, as with the phase one initial decision, the phase two initial decision has no force or effect and must be fully reviewed by the FERC, which may accept, reject or modify the decision. A FERC order on phase two of the case is not expected before the third quarter of 2005. Furthermore, any such order may be subject to further FERC review, review by the United States Court of Appeals for the District of Columbia Circuit, or both. We estimated, as of December 31, 2003, that shippers' claims for reparations totaled approximately $154 million and that prospective rate reductions would have an aggregate average annual impact of approximately $45 million. As the timing for implementation of rate reductions and the payment of reparations is extended, total estimated reparations and the interest accruing on the reparations increase. For each calendar quarter of delay in the implementation of rate reductions sought, we estimate that reparations and accrued interest accumulates by approximately $9 million. We now assume that any potential rate reductions will be implemented no earlier than the third quarter of 2005 and that reparations and accrued interest thereon will be paid no earlier than the third quarter of 2006; however, the timing, and nature, of any rate reductions and reparations that may be ordered will likely be affected by the FERC's income tax allowance inquiry in Docket No. PL05-5 and the FERC's disposition of issues remanded by the D.C. Circuit in the BP West Coast decision. If the phase two initial decision were to be largely adopted by the FERC, the estimated reparations and rate reductions would be larger than noted above; however, we continue to estimate the combined annual impact of the rate reductions and the capital costs associated with financing the payment of reparations sought by shippers and accrued interest thereon to be approximately 15 cents of distributable cash flow per unit. We believe, however, that the ultimate resolution of these complaints will be for amounts substantially less than the amounts sought. For more information on our Pacific operations' regulatory proceedings, see Note 16 to our consolidated financial statements included elsewhere in this report. The complaints filed before the CPUC challenge the rates charged for intrastate transportation of refined petroleum products through our Pacific operations' pipeline system in California. After the CPUC dismissed the initial complaint and subsequently granted a limited rehearing on April 10, 2000, the complainants filed a new complaint with the CPUC asserting the intrastate rates were not just and reasonable. Proposed rulemaking by the Federal Energy Regulatory Commission or other regulatory agencies having jurisdiction could adversely impact our income and operations. New laws or regulations or different interpretations of existing laws or regulations applicable to our assets could have a negative impact on our business, financial condition and results of operations. Increased regulatory requirements relating to the integrity of our pipelines will require us to spend additional money to comply with these requirements. Through our regulated pipeline subsidiaries, we are subject to extensive laws and regulations related to pipeline integrity. For example, federal legislation signed into law in December 2002 includes guidelines for the U.S. DOT and pipeline companies in the areas of testing, education, training and communication. Compliance with existing and recently enacted regulations requires significant expenditures. Additional laws and regulations that may be enacted in the future, such as U.S. DOT implementation of additional hydrostatic testing requirements, could significantly increase the amount of these expenditures. Our rapid growth may cause difficulties integrating new operations, and we may not be able to achieve the expected benefits from any future acquisitions. Part of our business strategy includes acquiring additional businesses that will allow us to increase distributions to our unitholders. If we do not successfully integrate acquisitions, we may not realize anticipated operating advantages and cost savings. The integration of companies that have previously operated separately involves a number of risks, including: o demands on management related to the increase in our size after an acquisition; o the diversion of our management's attention from the management of daily operations; o difficulties in implementing or unanticipated costs of accounting, estimating, reporting and other systems; 46 <PAGE> o difficulties in the assimilation and retention of employees; and o potential adverse effects on operating results. We may not be able to maintain the levels of operating efficiency that acquired companies have achieved or might achieve separately. Successful integration of each of their operations will depend upon our ability to manage those operations and to eliminate redundant and excess costs. Because of difficulties in combining operations, we may not be able to achieve the cost savings and other size-related benefits that we hoped to achieve after these acquisitions, which would harm our financial condition and results of operations. Our acquisition strategy requires access to new capital. Tightened credit markets or more expensive capital would impair our ability to grow. Part of our business strategy includes acquiring additional businesses that will allow us to increase distributions to our unitholders. During the period from December 31, 1996 to December 31, 2004, we made a significant number of acquisitions that increased our asset base over 34 times and increased our net income over 69 times. We regularly consider and enter into discussions regarding potential acquisitions and are currently contemplating potential acquisitions. These transactions can be effected quickly, may occur at any time and may be significant in size relative to our existing assets and operations. We may need new capital to finance these acquisitions. Limitations on our access to capital will impair our ability to execute this strategy. We normally fund acquisitions with short term debt and repay such debt through equity and long-term debt offerings. An inability to access the capital markets may result in a substantial increase in our leverage and have a detrimental impact on our credit profile. One of the factors that increases our attractiveness to investors, and as a result may make it easier for us to access the capital markets, is the fact that distributions to our partners are not subject to the double taxation that shareholders in corporations may experience with respect to dividends that they receive. The Jobs and Growth Tax Relief Reconciliation Act of 2003 generally reduced the maximum tax rate on dividends paid by corporations to individuals to 15% in 2003 and, for taxpayers in the 10% and 15% ordinary income tax brackets, to 5% in 2003 through 2007 and to zero in 2008. This legislation also reduced the maximum tax rate for an individual to 35% and the maximum tax rate applicable to net long term capital gains of an individual to 15%. This legislation may cause some investments in corporations to be more attractive to individual investors than they used to be when compared to an investment in partnerships, thereby exerting downward pressure on the market price of our common units and potentially making it more difficult for us to access the capital markets. Environmental regulation could result in increased operating and capital costs for us. Our business operations are subject to federal, state and local laws and regulations relating to environmental protection. If an accidental leak, release or spill of liquid petroleum products, chemicals or other products occurs from our pipelines or at our storage facilities, we may have to pay a significant amount to clean up the leak, release or spill or pay for government penalties, liability to government agencies for natural resource damage, personal injury or property damage to private parties or significant business interruption. The resulting costs and liabilities could negatively affect our level of cash flow. In addition, emission controls required under the Federal Clean Air Act and other similar federal and state laws could require significant capital expenditures at our facilities. The impact on us of Environmental Protection Agency standards or future environmental measures could increase our costs significantly if environmental laws and regulations become stricter. In addition, our oil and gas exploration and production activities are subject to certain federal, state and local laws and regulations relating to environmental quality and pollution control. These laws and regulations increase the costs of these activities and may prevent or delay the commencement or continuance of a given operation. Specifically, we are subject to laws and regulations regarding the acquisition of permits before drilling, restrictions on drilling activities in restricted areas, emissions into the environment, water discharges, and storage and disposition of hazardous wastes. In addition, legislation has been enacted which requires well and facility sites to be abandoned and reclaimed to the satisfaction of state authorities. The costs of environmental regulation are already significant, and additional or more stringent regulation could increase these costs or could otherwise negatively affect our business. Our future success depends in part upon our ability to develop additional oil and gas reserves that are economically recoverable. The rate of production from oil and natural gas properties declines as reserves are depleted. Without successful development activities, the reserves and revenues of our CO2 business segment will 47 <PAGE> decline. We may not be able to develop or acquire additional reserves at an acceptable cost or have necessary financing for these activities in the future. The development of oil and gas properties involves risks that may result in a total loss of investment. The business of developing and operating oil and gas properties involves a high degree of business and financial risk that even a combination of experience, knowledge and careful evaluation may not be able to overcome. Acquisition and completion decisions generally are based on subjective judgments and assumptions that are speculative. It is impossible to predict with certainty the production potential of a particular property or well. Furthermore, a successful completion of a well does not ensure a profitable return on the investment. A variety of geological, operational, or market-related factors, including, but not limited to, unusual or unexpected geological formations, pressures, equipment failures or accidents, fires, explosions, blowouts, cratering, pollution and other environmental risks, shortages or delays in the availability of drilling rigs and the delivery of equipment, loss of circulation of drilling fluids or other conditions may substantially delay or prevent completion of any well, or otherwise prevent a property or well from being profitable. A productive well may become uneconomic in the event water or other deleterious substances are encountered, which impair or prevent the production of oil and/or gas from the well. In addition, production from any well may be unmarketable if it is contaminated with water or other deleterious substances. The volatility of natural gas and oil prices could have a material adverse effect on our business. The revenues, profitability and future growth of our CO2 business segment and the carrying value of our oil and gas properties depend to a large degree on prevailing oil and gas prices. Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in the supply and demand for oil and gas, uncertainties within the market and a variety of other factors beyond our control. These factors include, weather conditions in the United States; the condition of the United States economy; the activities of the Organization of Petroleum Exporting Countries; governmental regulation; political stability in the Middle East and elsewhere; the foreign supply of oil and gas; the price of foreign imports; and the availability of alternative fuel sources. A sharp decline in the price of natural gas or oil prices would result in a commensurate reduction in our revenues, income and cash flows from the production of oil and gas and could have a material adverse effect on the carrying value of our proved reserves. In the event prices fall substantially, we may not be able to realize a profit from our production and would operate at a loss. In recent decades, there have been periods of both worldwide overproduction and underproduction of hydrocarbons and periods of both increased and relaxed energy conservation efforts. Such conditions have resulted in periods of excess supply of, and reduced demand for, crude oil on a worldwide basis and for natural gas on a domestic basis. These periods have been followed by periods of short supply of, and increased demand for, crude oil and natural gas. The excess or short supply of crude oil has placed pressures on prices and has resulted in dramatic price fluctuations even during relatively short periods of seasonal market demand. Our use of hedging arrangements could result in financial losses or reduce our income. We currently engage in hedging arrangements to reduce our exposure to fluctuations in the prices of oil and natural gas. These hedging arrangements expose us to risk of financial loss in some circumstances, including when production is less than expected; the counter-party to the hedging contract defaults on its contract obligations; or there is a change in the expected differential between the underlying price in the hedging agreement and the actual prices received. In addition, these hedging arrangements may limit the benefit we would otherwise receive from increases in prices for oil and natural gas. Competition could ultimately lead to lower levels of profits and lower cash flow. We face competition from other pipelines and terminals in the same markets as our assets, as well as from other means of transporting and storing energy products. For a description of the competitive factors facing our business, please see Items 1 and 2 "Business and Properties" in this report for more information. We do not own approximately 97.5% of the land on which our pipelines are constructed and we are subject to the possibility of increased costs to retain necessary land use. We obtain the right to construct and operate the pipelines on other people's land for a period of time. If we were to lose these rights or be required to relocate our pipelines, our business could be affected negatively. 48 <PAGE> Southern Pacific Transportation Company has allowed us to construct and operate a significant portion of our Pacific operations' pipeline system on railroad rights-of-way. Southern Pacific Transportation Company and its predecessors were given the right to construct their railroad tracks under federal statutes enacted in 1871 and 1875. The 1871 statute was thought to be an outright grant of ownership that would continue until the land ceased to be used for railroad purposes. Two United States Circuit Courts, however, ruled in 1979 and 1980 that railroad rights-of-way granted under laws similar to the 1871 statute provide only the right to use the surface of the land for railroad purposes without any right to the underground portion. If a court were to rule that the 1871 statute does not permit the use of the underground portion for the operation of a pipeline, we may be required to obtain permission from the landowners in order to continue to maintain the pipelines. Approximately 10% of our pipeline assets are located in the ground underneath railroad rights-of-way. Whether we have the power of eminent domain for our pipelines varies from state to state depending upon the type of pipeline--petroleum liquids, natural gas or carbon dioxide--and the laws of the particular state. Our inability to exercise the power of eminent domain could negatively affect our business if we were to lose the right to use or occupy the property on which our pipelines are located. For the year ended December 31, 2004, all of our right-of-way related expenses totaled $16.7 million. We could be treated as a corporation for United States income tax purposes. Our treatment as a corporation would substantially reduce the cash distributions on the common units that we distribute quarterly. The anticipated benefit of an investment in our common units depends largely on the treatment of us as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service on this or any other matter affecting us. Current law requires us to derive at least 90% of our annual gross income from specific activities to continue to be treated as a partnership for federal income tax purposes. We may not find it possible, regardless of our efforts, to meet this income requirement or may inadvertently fail to meet this income requirement. Current law may change so as to cause us to be treated as a corporation for federal income tax purposes without regard to our sources of income or otherwise subject us to entity-level taxation. If we were to be treated as a corporation for federal income tax purposes, we would pay federal income tax on our income at the corporate tax rate, which is currently a maximum of 35% and would pay state income taxes at varying rates. Under current law, distributions to unitholders would generally be taxed as a corporate distribution. Because a tax would be imposed upon us as a corporation, the cash available for distribution to a unitholder would be substantially reduced. Treatment of us as a corporation would cause a substantial reduction in the value of our units. In addition, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available for distribution to our unitholders would be reduced. Our debt instruments may limit our financial flexibility and increase our financing costs. The instruments governing our debt contain restrictive covenants that may prevent us from engaging in certain transactions that we deem beneficial and that may be beneficial to us. The agreements governing our debt generally require us to comply with various affirmative and negative covenants, including the maintenance of certain financial ratios and restrictions on: o incurring additional debt; o entering into mergers, consolidations and sales of assets; o granting liens; and o entering into sale-leaseback transactions. The instruments governing any future debt may contain similar or more restrictive restrictions. Our ability to respond to changes in business and economic conditions and to obtain additional financing, if needed, may be restricted. 49 <PAGE> If interest rates increase, our earnings could be adversely affected. As of December 31, 2004, we had approximately $2.6 billion of debt, excluding market value of interest rate swaps, subject to variable interest rates. This amount included $2.2 billion of long-term fixed rate debt converted to floating rate debt through the use of interest rate swaps. Should interest rates increase significantly, our earnings could be adversely affected. The distressed financial condition of some of our customers could have an adverse impact on us in the event these customers are unable to pay us for the services we provide. Some of our customers are experiencing severe financial problems, and other customers may experience severe financial problems in the future. The bankruptcy of one or more of them, or some other similar proceeding or liquidity constraint might make it unlikely that we would be able to collect all or a significant portion of amounts owed by the distressed entity or entities. In addition, such events might force such customers to reduce or curtail their future use of our products and services, which could have a material adverse effect on our results of operations and financial condition. In addition, some of our customers are experiencing, or may experience in the future, severe financial problems that have had a significant impact on their creditworthiness. We are working to implement, to the extent allowable under applicable contracts, tariffs and regulations, prepayments and other security requirements, such as letters of credit, to enhance our credit position relating to amounts owed from these customers. We cannot provide assurance that one or more of our financially distressed customers will not default on their obligations to us or that such a default or defaults will not have a material adverse effect on our business, financial position, future results of operations or future cash flows. The interests of KMI may differ from our interest and the interests of our unitholders. KMI indirectly owns all of the stock of our general partner and elects all of its directors. Our general partner owns all of KMR's voting shares and elects all of its directors. Furthermore, some of KMR's directors and officers are also directors and officers of KMI and our general partner and have fiduciary duties to manage the businesses of KMI in a manner that may not be in the best interest of our unitholders. KMI has a number of interests that differ from the interests of our unitholders. As a result, there is a risk that important business decisions will not be made in the best interests of our unitholders. Our partnership agreement and the KMR limited liability company agreement restrict or eliminate a number of the fiduciary duties that would otherwise be owed by our general partner and/or its delegate to our unitholders. Modifications of state law standards of fiduciary duties may significantly limit the ability of our unitholders to successfully challenge the actions of our general partner in the event of a breach of fiduciary duties. These state law standards include the duties of care and loyalty. The duty of loyalty, in the absence of a provision in the limited partnership agreement to the contrary, would generally prohibit our general partner from taking any action or engaging in any transaction as to which it has a conflict of interest. Our limited partnership agreement contains provisions that prohibit limited partners from advancing claims that otherwise might raise issues as to compliance with fiduciary duties or applicable law. For example, that agreement provides that the general partner may take into account the interests of parties other than us in resolving conflicts of interest. It also provides that in the absence of bad faith by the general partner, the resolution of a conflict by the general partner will not be a breach of any duty. The provisions relating to the general partner apply equally to KMR as its delegate. It is not necessary for a limited partner to sign our limited partnership agreement in order for the limited partnership agreement to be enforceable against that person. Other We do not have any employees. KMGP Services Company, Inc. and Kinder Morgan, Inc. employ all persons necessary for the operation of our business. Generally we reimburse KMGP Services Company, Inc. and Kinder Morgan, Inc. for the services of their employees. As of December 31, 2004, KMGP Services Company, Inc. and Kinder Morgan, Inc. had, in the aggregate, approximately 6,072 employees. Approximately 1,206 hourly personnel at certain terminals and pipelines are represented by labor unions under collective bargaining agreements that expire between 2005 and 2009. KMGP Services Company, Inc. and Kinder Morgan, Inc. consider relations with their employees to be good. For more information on our related party transactions, see Note 12 of the notes to our consolidated financial statements included elsewhere in this report. 50 <PAGE> Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of such property. In many instances, lands over which rights-of-way have been obtained are subject to prior liens which have not been subordinated to the right-of-way grants. In some cases, not all of the apparent record owners have joined in the right-of-way grants, but in substantially all such cases, signatures of the owners of majority interests have been obtained. Permits have been obtained from public authorities to cross over or under, or to lay facilities in or along, water courses, county roads, municipal streets and state highways, and in some instances, such permits are revocable at the election of the grantor, or, the pipeline may be required to move its facilities at its own expense. Permits have also been obtained from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor's election. Some such permits require annual or other periodic payments. In a few minor cases, property for pipeline purposes was purchased in fee. We believe that we have generally satisfactory title to the properties we own and use in our businesses, subject to liens for current taxes, liens incident to minor encumbrances, and easements and restrictions which do not materially detract from the value of such property or the interests in those properties or the use of such properties in our businesses. We generally do not own the land on which our pipelines are constructed. Instead, we obtain the right to construct and operate the pipelines on other people's land for a period of time. Amounts we have spent during 2004, 2003 and 2002 on research and development activities were not material. (d) Financial Information about Geographic Areas The amount of our assets and operations that are located outside of the continental United States of America are not material. (e) Available Information We make available free of charge on or through our Internet website, at http://www.kindermorgan.com, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission. Item 3. Legal Proceedings. See Note 16 of the notes to our consolidated financial statements included elsewhere in this report. Item 4. Submission of Matters to a Vote of Security Holders. There were no matters submitted to a vote of our unitholders during the fourth quarter of 2004. 51 <PAGE> PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities. The following table sets forth, for the periods indicated, the high and low sale prices per common unit, as reported on the New York Stock Exchange, the principal market in which our common units are traded, the amount of cash distributions declared per common and Class B unit, and the fractional i-unit distribution declared per i-unit. Price Range ----------=----- Cash i-unit High Low Distributions Distributions ------ --------- ------------- ------------- 2004 First Quarter $49.12 $43.50 $0.6900 0.017412 Second Quarter 45.39 37.65 0.7100 0.018039 Third Quarter 46.85 40.60 0.7300 0.017892 Fourth Quarter 47.70 42.75 0.7400 0.017651 2003 First Quarter $37.23 $33.51 $0.6400 0.018488 Second Quarter 40.34 35.00 0.6500 0.017138 Third Quarter 43.06 38.65 0.6600 0.016844 Fourth Quarter 49.95 42.63 0.6800 0.015885 All of the information is for distributions declared with respect to that quarter. The declared distributions were paid within 45 days after the end of the quarter. We currently expect that we will continue to pay comparable cash and i-unit distributions in the future assuming no adverse change in our operations, economic conditions and other factors. However, we can give no assurance that future distributions will continue at such levels. As of January 31, 2005, there were approximately 153,000 beneficial owners of our common units, one holder of our Class B units and one holder of our i-units. For information on our equity compensation plans, see Item 12 "Security Ownership of Certain Beneficial Owners and Management--Equity Compensation Plan Information". We did not repurchase any units during the fourth quarter of 2004. 52 <PAGE> Item 6. Selected Financial Data The following tables set forth, for the periods and at the dates indicated, our summary historical financial and operating data. The table is derived from our consolidated financial statements and notes thereto, and should be read in conjunction with those audited financial statements. See also Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations" in this report for more information. <TABLE> <CAPTION> Year Ended December 31, ------------------------------------------------------------- 2004(4) 2003(5) 2002(6) 2001(7) 2000(8) ---------- ----------- ---------- ------------ ---------- (In thousands, except per unit data) <S> <C> <C> <C> <C> <C> Income and Cash Flow Data: Revenues.......................... $ 7,932,861 $6,624,322 $4,237,057 $2,946,676 $ 816,442 Cost of product sold.............. 5,767,169 4,880,118 2,704,295 1,657,689 124,641 Operating expense................. 581,083 459,936 427,805 396,354 182,445 Fuel and power.................... 151,480 108,112 86,413 73,188 43,216 Depreciation, depletion and amortization..................... 288,626 219,032 172,041 142,077 82,630 General and administrative........ 170,507 150,435 122,205 113,540 67,949 ----------- ---------- ---------- ---------- ---------- Operating income.................. 973,996 806,689 724,298 563,828 315,561 Earnings from equity investments.. 83,190 92,199 89,258 84,834 71,603 Amortization of excess cost of equity investments............... (5,575) (5,575) (5,575) (9,011) (8,195) Interest expense.................. (196,172) (182,777) (178,279) (175,930) (97,102) Interest income and other, net.... (4,135) (33) (6,042) (5,005) 10,415 Income tax provision.............. (19,726) (16,631) (15,283) (16,373) (13,934) ----------- ---------- ---------- ---------- ----------- Income before cumulative effect of a change in accounting principle. 831,578 693,872 608,377 442,343 278,348 Cumulative effect of a change in accounting principle.......... -- 3,465 -- -- -- ----------- ---------- ---------- ---------- ----------- Net income........................ $ 831,578 $ 697,337 $ 608,377 $ 442,343 $ 278,348 General Partner's interest in net income....................... 395,092 326,524 270,816 202,095 109,470 Limited Partners' interest in net income....................... $ 436,486 $ 370,813 $ 337,561 $ 240,248 $ 168,878 Basic and Diluted Limited Partners' Net Income per unit: Income before cumulative effect of a change in accounting principle(1)..................... $ 2.22 $ 1.98 $ 1.96 $ 1.56 $ 1.34 Cumulative effect of a change in accounting principle.......... -- 0.02 -- -- -- ----------- ---------- ---------- ---------- ----------- Net income........................ $ 2.22 $ 2.00 $ 1.96 $ 1.56 $ 1.34 Per unit cash distribution declared(2)...................... $ 2.87 $ 2.63 $ 2.435 $ 2.15 $ 1.712 Additions to property, plant and equipment.................... $ 747,262 $ 576,979 $ 542,235 $ 295,088 $ 125,523 Balance Sheet Data (at end of period): Net property, plant and equipment. $ 8,168,680 $7,091,558 $6,244,242 $5,082,612 $3,306,305 Total assets...................... $10,552,942 $9,139,182 $8,353,576 $6,732,666 $4,625,210 Long-term debt(3)................. $ 4,722,410 $4,316,678 $3,659,533 $2,237,015 $1,255,453 Partners' capital................. $ 3,896,520 $3,510,927 $3,415,929 $3,159,034 $2,117,067 </TABLE> __________ (1) Represents income before cumulative effect of a change in accounting principle per unit adjusted for the two-for-one split of units on August 31, 2001. Basic Limited Partners' income per unit before cumulative effect of a change in accounting principle was computed by dividing the interest of our unitholders in income before cumulative effect of a change in accounting principle 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. (2) Represents the amount of cash distributions declared with respect to that year. Amounts have been adjusted for the two-for-one split of common units that occurred on August 31, 2001. (3) Excludes market value of interest rate swaps. (4) Includes results of operations for the seven refined petroleum products terminals acquired from ExxonMobil, Kinder Morgan Wink Pipeline, L.P., an additional 5% interest in the Cochin Pipeline System, Kinder Morgan River Terminals LLC & Consolidated Subsidiaries, TransColorado Gas Transmission Company, interests in nine refined petroleum products terminals acquired from Charter Terminal Company and Charter-Triad Terminals, LLC, and the Kinder Morgan Fairless 53 <PAGE> Hills terminal since effective dates of acquisition. We acquired the seven refined petroleum products terminals from ExxonMobil effective March 9, 2004. We acquired Kinder Morgan Wink Pipeline, L.P. effective August 31, 2004. The additional interest in Cochin was acquired effective October 1, 2004. We acquired Kinder Morgan River Terminals LLC & Consolidated Subsidiaries effective October 6, 2004. We acquired TransColorado effective November 1, 2004, the interests in the nine Charter Terminal Company and Charter-Triad Terminals, LLC refined petroleum products terminals effective November 5, 2004, and the Kinder Morgan Fairless Hills terminal effective December 1, 2004. (5) Includes results of operations for the bulk terminal operations acquired from M.J. Rudolph Corporation, the additional 12.75% interest in the SACROC unit, the five refined petroleum products terminals acquired from Shell, the additional 42.5% interest in the Yates field unit, the crude oil gathering operations surrounding the Yates field unit, an additional 65% interest in the Pecos Carbon Dioxide Company, the remaining approximate 32% interest in MidTex Gas Storage Company, LLP, the seven refined petroleum products terminals acquired from ConocoPhillips and two bulk terminal facilities located in Tampa, Florida since dates of acquisition. We acquired certain bulk terminal operations from M.J. Rudolph effective January 1, 2003. The additional 12.75% interest in SACROC was acquired effective June 1, 2003. The five refined petroleum products terminals were acquired effective October 1, 2003. The additional 42.5% interest in the Yates field unit, the Yates gathering system and the additional 65% interest in Pecos Carbon Dioxide Company were acquired effective November 1, 2003. The additional 32% ownership interest in MidTex was acquired November 1, 2003. The seven refined petroleum products terminals were acquired December 11, 2003, and the two bulk terminal facilities located in Tampa, Florida were acquired effective December 10 and 23, 2003. (6) Includes results of operations for the additional 10% interest in the Cochin Pipeline System, Kinder Morgan Materials Services LLC (formerly Laser Materials Services LLC), the 66 2/3% interest in International Marine Terminals, Tejas Gas, LLC, Milwaukee Bagging Operations, the remaining 33 1/3% interest in Trailblazer Pipeline Company, the Owensboro Gateway Terminal and IC Terminal Holdings Company and Consolidated Subsidiaries since dates of acquisitions. The additional interest in Cochin was acquired effective December 31, 2001. Kinder Morgan Materials Services LLC was acquired effective January 1, 2002. We acquired a 33 1/3% interest in International Marine Terminals effective January 1, 2002 and an additional 33 1/3% interest effective February 1, 2002. Tejas Gas, LLC was acquired effective January 31, 2002. The Milwaukee Bagging Operations were acquired effective May 1, 2002. The remaining interest in Trailblazer was acquired effective May 6, 2002. The Owensboro Gateway Terminal and IC Terminal Holdings Company and Subsidiaries were acquired effective September 1, 2002. (7) Includes results of operations for the remaining 50% interest in the Colton Processing Facility, Kinder Morgan Texas Pipeline, Casper and Douglas gas gathering assets, 50% interest in Coyote Gas Treating, LLC, 25% interest in Thunder Creek Gas Services, LLC, Central Florida Pipeline LLC, Kinder Morgan Liquids Terminals LLC, Pinney Dock & Transport LLC, CALNEV Pipe Line LLC, 34.8% interest in the Cochin Pipeline System, Vopak terminal LLCs, Boswell terminal assets, Stolt-Nielsen terminal assets and additional gasoline and gas plant interests since dates of acquisition. The remaining interest in the Colton Processing Facility, Kinder Morgan Texas Pipeline, Casper and Douglas gas gathering assets and our interests in Coyote and Thunder Creek were acquired effective December 31, 2000. Central Florida and Kinder Morgan Liquids Terminals LLC were acquired January 1, 2001. Pinney Dock was acquired March 1, 2001. CALNEV was acquired March 30, 2001. Our second investment in Cochin, representing a 2.3% interest, was made effective June 20, 2001. Vopak terminal LLCs were acquired July 10, 2001. Boswell terminals were acquired August 31, 2001. Stolt-Nielsen terminals were acquired effective November 8 and 29, 2001, and our additional interests in the Snyder Gasoline Plant and the Diamond M Gas Plant were acquired effective November 14, 2001. (8) Includes results of operations for Kinder Morgan Interstate Gas Transmission, 66 2/3% interest in Trailblazer, 49% interest in Red Cedar, Milwaukee Bulk Terminals, Dakota Bulk Terminal, remaining 80% interest in Kinder Morgan CO2 Company, L.P., Devon Energy carbon dioxide properties, Kinder Morgan Transmix Company, LLC, a 32.5% interest in Cochin Pipeline System and Delta Terminal Services LLC since dates of acquisition. Kinder Morgan Interstate Gas Transmission, Trailblazer assets, and our 49% interest in Red Cedar were acquired effective December 31, 1999. Milwaukee Bulk Terminals, Inc. and Dakota Bulk Terminal, Inc. were acquired effective January 1, 2000. The remaining 80% interest in Kinder Morgan CO2 Company, L.P. was acquired April 1, 2000. The Devon Energy carbon dioxide properties were acquired June 1, 2000. Kinder Morgan Transmix Company, LLC was acquired effective October 25, 2000. Our 32.5% interest in Cochin was acquired effective November 3, 2000, and Delta Terminal Services LLC was acquired effective December 1, 2000. 54 <PAGE> Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. The following discussion and analysis of our financial condition and results of operations provides you with a narrative on our financial results. It contains a discussion and analysis of the results of operations for each segment of our business, followed by a discussion and analysis of our financial condition. The following discussion and analysis is based on our consolidated financial statements, which are included elsewhere in this report and were prepared in accordance with accounting principles generally accepted in the United States of America. You should read the following discussion and analysis in conjunction with our consolidated financial statements. Additional sections in this report which should be helpful to your reading of our discussion and analysis include the following: o a description of our business strategy and management philosophy, found in Items 1 and 2 "Business and Properties-Business Strategy"; o a description of developments during 2004, found in Items 1 and 2 "Business and Properties-Recent Developments"; and o a description of risk factors affecting us and our business, found in Items 1 and 2 "Business and Properties-Risk Factors." Critical Accounting Policies and Estimates Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities and our disclosure of contingent assets and liabilities at the date of our financial statements. We evaluate these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. In preparing our financial statements and related disclosures, we must use estimates in determining the economic useful lives of our assets, the fair values used to determine possible asset impairment charges, provisions for uncollectible accounts receivable, exposures under contractual indemnifications and various other recorded or disclosed amounts. However, we believe that certain accounting policies are of more significance in our financial statement preparation process than others, which policies are discussed following. Environmental Matters With respect to our environmental exposure, we utilize both internal staff and external experts to assist us in identifying environmental issues and in estimating the costs and timing of remediation efforts. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in our income in the period in which they are reasonably determinable. We routinely conduct reviews of potential environmental issues and claims that could impact our assets or operations. In December 2004, we recognized a $0.2 million increase in environmental expenses and an associated $0.1 million increase in deferred income tax expense resulting from changes to previous estimates. The adjustment included an $18.9 million increase in our estimated environmental receivables and reimbursables and a $19.1 million increase in our overall accrued environmental and related claim liabilities. We included the additional $0.2 million environmental expense within "Other, net" in our accompanying consolidated statement of income for 2004. The $0.3 million expense item, including taxes, is the net impact of a $30.6 increase in expense in our Products Pipelines business segment, a $7.6 55 <PAGE> million decrease in expense in our Natural Gas Pipelines segment, a $4.1 million decrease in expense in our CO2 segment, and an $18.6 million decrease in expense in our Terminals business segment. In December 2002, we recognized a $0.3 million reduction in environmental expense and in our overall accrued environmental liability, and we included this amount within "Other, net" in our accompanying consolidated statement of income for 2002. The $0.3 million reduction in environmental expense resulted from a $15.7 million increase in expense in our Products Pipelines business segment and a $16.0 million decrease in expense in our Terminals business segment. For more information on our environmental disclosures, see Note 16 to our consolidated financial statements included elsewhere in this report. Legal Matters We are subject to litigation and regulatory proceedings as the result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. We expense legal costs as incurred and all recorded legal liabilities are revised as better information becomes available. SFPP, L.P. is the subsidiary limited partnership that owns our Pacific operations, excluding CALNEV Pipe Line LLC and related terminals acquired from GATX Corporation. Tariffs charged by SFPP are subject to certain proceedings at the Federal Energy Regulatory Commission involving shippers' complaints regarding the interstate rates, as well as practices and the jurisdictional nature of certain facilities and services, on our Pacific operations' pipeline systems. Generally, the interstate rates on our Pacific operations' pipeline systems are "grandfathered" under the Energy Policy Act of 1992 unless "substantially changed circumstances" are found to exist. To the extent "substantially changed circumstances" are found to exist, our Pacific operations may be subject to substantial exposure under these FERC complaints. We estimated, as of December 31, 2003, that shippers' claims for reparations totaled approximately $154 million and that prospective rate reductions would have an aggregate average annual impact of approximately $45 million. As the timing for implementation of rate reductions and the payment of reparations is extended, total estimated reparations and the interest accruing on the reparations increase. For each calendar quarter of delay in the implementation of rate reductions sought, we estimate that reparations and accrued interest accumulates by approximately $9 million. We now assume that any potential rate reductions will be implemented no earlier than the third quarter of 2005 and that reparations and accrued interest thereon will be paid no earlier than the third quarter of 2006; however, the timing, and nature, of any rate reductions and reparations that may be ordered will likely be affected by the FERC's income tax allowance inquiry in Docket No. PL05-5 and the FERC's disposition of issues remanded by the D.C. Circuit in the BP West Coast decision. If the phase two initial decision were to be largely adopted by the FERC, the estimated reparations and rate reductions would be larger than noted above; however, we continue to estimate the combined annual impact of the rate reductions and the capital costs associated with financing the payment of reparations sought by shippers and accrued interest thereon to be approximately 15 cents of distributable cash flow per unit. We believe, however, that the ultimate resolution of these complaints will be for amounts substantially less than the amounts sought. For more information on our Pacific operations' regulatory proceedings, see Note 16 to our consolidated financial statements included elsewhere in this report. Intangible Assets Effective January 1, 2002, we adopted Statement of Financial Accounting Standards No. 141, "Business Combinations" and Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets." These accounting pronouncements introduced the concept of indefinite life intangible assets and required us to prospectively cease amortizing all of our intangible assets having indefinite useful economic lives, including goodwill. Such assets are not to be amortized until their lives are determined to be finite. These rules also impact future period net income by an amount equal to the discontinued goodwill amortization offset by goodwill impairment charges, if any, and adjusted for any differences between the old and new rules for defining intangible assets on future business combinations. Additionally, a recognized intangible asset with an indefinite useful life 56 <PAGE> must be tested for impairment annually or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value. We completed this initial transition impairment test in June 2002 and determined that our goodwill was not impaired as of January 1, 2002. We have selected an impairment measurement test date of January 1 of each year and we have determined that our goodwill was not impaired as of January 1, 2005. As of January 1, 2005, our goodwill was $732.8 million. Estimated Net Recoverable Quantities of Oil and Gas We use the successful efforts method of accounting for our oil and gas producing activities. The successful efforts method inherently relies on the estimation of proved reserves, both developed and undeveloped. The existence and the estimated amount of proved reserves affect, among other things, whether certain costs are capitalized or expensed, the amount and timing of costs depleted or amortized into income and the presentation of supplemental information on oil and gas producing activities. The expected future cash flows to be generated by oil and gas producing properties used in testing for impairment of such properties also rely in part on estimates of net recoverable quantities of oil and gas. Our estimation of net recoverable quantities of oil and gas is a highly technical process performed primarily by in-house reservoir engineers and geoscience professionals. Independent oil and gas consultants have reviewed the estimates of proved reserves of crude oil, natural gas and natural gas liquids that we have attributed to our net interest in oil and gas properties as of December 31, 2004. Proved reserves are the estimated quantities of oil and gas that geologic and engineering data demonstrates with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Estimates of proved reserves may change, either positively and negatively, as additional information becomes available and as a contractual, economic and political conditions change. Results of Operations <TABLE> <CAPTION> Year Ended December 31, ------------------------------------ 2004 2003 2002 ---------- ---------- ---------- (In thousands) <S> <C> <C> <C> Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments Products Pipelines................................ $ 444,865 $ 441,600 $ 411,604 Natural Gas Pipelines............................. 418,261 373,350 325,454 CO2............................................... 357,636 203,599 132,196 Terminals......................................... 281,738 240,776 224,963 ----------- ----------- ----------- Segment earnings before depreciation, depletion and amortization of excess cost of equity investments(a)................................ 1,502,500 1,259,325 1,094,217 Depreciation, depletion and amortization expense.. (288,626) (219,032) (172,041) Amortization of excess cost of investments........ (5,575) (5,575) (5,575) Interest and corporate administrative expenses(b). (376,721) (337,381) (308,224) ----------- ----------- ----------- Net income...................................... $ 831,578 $ 697,337 $ 608,377 =========== =========== =========== </TABLE> - ---------- (a) Includes revenues, earnings from equity investments, income taxes, allocable interest income and other, net, less operating expenses. 2004 amounts include environmental expense adjustments resulting in a $30,611expense to our Products Pipelines business segment, a $7,602 reduction in expense to our Natural Gas Pipelines business segment, a $4,126 reduction in expense to our CO2 business segment and an $18,571 reduction in expense to our Terminals business segment. 2002 amounts include environmental expense adjustments resulting in a $15,700 expense to our Products Pipelines business segment and a $16,000 reduction in expense to our Terminals business segment. (b) Includes unallocated interest income, interest and debt expense, general and administrative expenses, minority interest expense, loss from early extinguishment of debt (2004 only) and cumulative effect adjustment from a change in accounting principle (2003 only). In 2004, we earned net income of $831.6 million ($2.22 per diluted unit) on revenues of $7,932.9 million, compared to net income of $697.3 million ($2.00 per diluted unit) on revenues of $6,624.3 million in 2003, and net income of $608.4 million ($1.96 per diluted unit) on revenues of $4,237.1 million in 2002. We benefited from a growing demand for energy products, overall higher energy prices and our management's continued commitment to its business strategy, designed to increase financial performance through a combination of internal asset expansions and external acquisitions. In 2003, we benefited from a cumulative effect adjustment of $3.4 million related to a change in accounting for asset retirement obligations pursuant to our adoption of Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" on January 1, 2003. Our 2003 income before the cumulative effect adjustment totaled $693.9 million ($1.98 per diluted unit). For more information on this cumulative effect adjustment from a change in accounting principle, see Note 4 to our consolidated financial statements, included elsewhere in this report. Because our partnership agreement requires us to distribute 100% of our available cash to our partners on a quarterly basis (available cash consists primarily of all our cash receipts, less cash disbursements and changes in reserves), we consider each period's earnings before all non-cash depreciation, depletion and amortization expenses, including amortization of excess cost of equity investments, to be an important measure of our success in maximizing returns to our partners. In each of the years 2004 and 2003, all four of our reportable business segments reported year-over-year increases in earnings before depreciation, depletion and amortization, with the strongest growth coming from our CO2 (carbon dioxide) and Natural Gas Pipelines business segments. The year-over-year increases in our segment earnings before depreciation, depletion and amortization in 2004 and 2003 were attributable both to internal growth and to contributions from acquired assets; more specifically: 57 <PAGE> o higher earnings from our CO2 segment, where we benifited from higher oil and gas prices, acquisitions of additional oil reserve interests and related assets, and internal capital spending that both increased and expanded asset infrastructure in order to accommodate growing customer demand within the Permian Basin area of West Texas; o higher earnings from our Natural Gas Pipelines segment, largely due to improved margins on natural gas sales activities, higher natural gas operational sales, and the further optimization of the large natural gas sourcing and transportation operations we conduct within the State of Texas; o higher earnings from our Products Pipelines segment, mainly due to higher revenues from refined product terminal operations, higher deliveries of refined petroleum products and natural gas liquids resulting from increased military and industrial demand, and the acquisition of our Southeast terminal operations, which consist of 23 refined petroleum products terminals that were acquired since December 2003; and o higher earnings from our Terminals segment, primarily due to higher revenues earned by transporting and storing petroleum and petrochemical-related liquids, transloading higher volumes of dry-bulk material products, completed expansion projects at existing liquids and bulk terminal facilities, and the terminal acquisitions we have made since the end of 2002. We declared a record cash distribution of $0.74 per unit for the fourth quarter of 2004 (an annualized rate of $2.96). This distribution was 9% higher than the $0.68 per unit distribution we made for the fourth quarter of 2003, and 18% higher than the $0.625 per unit distribution we made for the fourth quarter of 2002. We expect to declare cash distributions of at least $3.13 per unit for 2005; however, no assurance can be given that we will be able to achieve this level of distribution. Our general partner and our common and Class B unitholders receive quarterly distributions in cash, while KMR, the sole owner of our i-units, receives quarterly distributions in additional i-units. The value of the quarterly per-share distribution of i-units is based on the value of the quarterly per-share cash distribution made to our common and Class B unitholders. Products Pipelines <TABLE> <CAPTION> Year Ended December 31, --------------------------------------------- 2004 2003 2002 ------------- ------------- ------------ (In thousands, except operating statistics) <S> <C> <C> <C> Revenues.................................................. $ 645,249 $ 585,376 $ 576,542 Operating expenses(a)..................................... (191,425) (169,526) (169,782) Earnings from equity investments.......................... 29,050 30,948 28,998 Interest income and Other, net- income (expense)(b)....... (25,934) 6,471 (14,000) Income taxes.............................................. $ (12,075) (11,669) (10,154) ------------ ------------- ------------ Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity 444,865 441,600 411,604 investments................................................. Depreciation, depletion and amortization expense.......... (71,263) (67,345) (64,388) Amortization of excess cost of equity investments......... (3,281) (3,281) (3,281) ------------ ------------- ------------ Segment earnings........................................ $ 370,321 $ 370,974 $ 343,935 ============ ============ ============ Gasoline (MMBbl).......................................... 459.1 451.0 465.2 Diesel fuel (MMBbl)....................................... 161.7 161.4 152.7 Jet fuel (MMBbl).......................................... 117.8 111.3 115.1 ------------ ------------ ------------ Total refined product volumes (MMBbl)................... 738.6 723.7 733.0 Natural gas liquids (MMBbl)............................... 43.9 42.2 44.4 ------------ ------------ ------------ Total delivery volumes (MMBbl)(c)....................... 782.5 765.9 777.4 ============ ============ ============ </TABLE> - ---------- (a) Includes costs of sales, operations and maintenance expenses, fuel and power expenses and taxes, other than income taxes. (b) Includes expense of $30,611 and $15,700 in 2004 and 2002, respectively, associated with environmental expense adjustments. (c) Includes Pacific, Plantation, North System, CALNEV, Central Florida, Cypress and Heartland pipeline volumes. 58 <PAGE> Our Products Pipelines segment's primary businesses include transporting refined petroleum products and natural gas liquids through pipelines and operating high-quality liquid petroleum products terminals and transmix processing facilities. The segment reported earnings before depreciation, depletion and amortization of $444.9 million on revenues of $645.2 million in 2004. This compared to earnings before depreciation, depletion and amortization of $441.6 million on revenues of $585.4 million in 2003 and earnings before depreciation, depletion and amortization of $411.6 million on revenues of $576.5 million in 2002. As noted in the table above, the segment's 2004 and 2002 earnings included charges of $30.6 million and $15.7 million, respectively, from the adjustment of our environmental liabilities referred to in "Critical Accounting Policies and Estimates--Environmental Matters." Excluding these environmental charges, segment earnings before depreciation, depletion and amortization totaled $475.5 million in 2004 and $427.3 million in 2002. The $33.9 million (8%) increase in earnings before depreciation, depletion and amortization in 2004 compared to 2003 (excluding the 2004 environmental charge) was driven primarily by higher earnings from our Southeast terminals, our Pacific operations, earnings from our proportionate ownership interest in the Cochin pipeline system, and to a lesser extent by higher earnings from our West Coast terminal operations, our Central Florida and Cypress pipelines, and our transmix operations. Our Southeast terminals, which include the operations of 23 refined products terminals located in the southeastern United States that we acquired in December 2003, March 2004, and November 2004, reported earnings before depreciation, depletion and amortization of $14.0 million in 2004. Our Pacific operations reported a $9.5 million (4%) increase in earnings before depreciation, depletion and amortization in 2004, compared to the prior year. The increase was primarily due to incremental fees earned from ethanol-related services, higher refined product delivery revenues, and incremental revenues related to the refined products terminal operations we acquired from Shell Oil Products in October 2003. Effective October 1, 2004, we acquired an additional undivided 5% interest in the Cochin pipeline system for approximately $10.9 million and we now own approximately 49.8% of Cochin, an approximate 1,900-mile pipeline that transports natural gas liquids to the Midwestern United States and eastern Canada petrochemical and fuel markets. Cochin's earnings before depreciation, depletion and amortization increased $8.9 million (64%) in 2004 compared to 2003. The increase was primarily driven by higher revenues from pipeline throughput deliveries as well as our additional ownership interest. Earnings before depreciation, depletion and amortization from our West Coast terminals increased $2.8 million (7%) in 2004 compared to 2003. The increase was largely attributable to higher fees from ethanol blending services, primarily driven by revenue increases across all service activities performed at our Carson, California and our connected Los Angeles Harbor product terminals. The increases in segment earnings before depreciation, depletion and amortization in 2004 compared to 2003 were partly offset by lower earnings from our CALNEV Pipeline and North System natural gas liquids pipeline. CALNEV and the North System reported decreases of $2.4 million (5%) and $2.1 million (8%), respectively, in earnings before depreciation, depletion and amortization in 2004 versus 2003. For CALNEV, the decrease was driven by higher 2004 fuel and power expenses, higher operating expenses, and lower miscellaneous revenues. For our North System, the decrease was primarily due to higher 2004 leased storage expenses, due to higher fees, and lower transport revenues, related to a 6% decrease in 2004 throughput delivery volumes. The decline in North System delivery volumes was primarily due to a lack of propane supplies in February through April of 2004, caused by shippers reducing line-fill and storage volume to lower levels than last year. In April 2004, we filed a plan with the Federal Energy Regulatory Commission to provide a line-fill service, which we expect will mitigate the supply problems we experienced on our North System in the first half of 2004. Pursuant to this plan, we purchased $23.0 million of line-fill during 2004. The $14.3 million (3%) increase in segment earnings before depreciation, depletion and amortization in 2003 compared to 2002 (excluding the 2002 environmental charge) resulted from higher earnings from our Pacific operations, North System, CALNEV Pipeline, transmix operations, Central Florida Pipeline, our approximate 51% ownership interest in Plantation Pipe Line Company and our West Coast terminal operations. Earnings in 2003 were positively impacted by higher revenues, mainly from fees for ethanol blending services at our Pacific operations and West Coast terminals, and from higher product delivery revenues related to overall strong demand for diesel fuel. The overall increase was partially offset by lower earnings before depreciation, depletion and 59 <PAGE> amortization from both our proportionate interest in the Cochin pipeline system and our Cypress Pipeline, mainly due to lower operating revenues. In addition, due to the continued process of converting from methyl tertiary-butyl ether (MTBE) to ethanol in the State of California, we realized a small reduction in California gasoline volumes. Since the end of 2002, MTBE-blended gasoline is being replaced by an ethanol blend, and ethanol is not shipped in our pipelines; however, fees that we earn from ethanol-related services at our terminals positively contribute to our earnings. As of December 31, 2003, we had ethanol blending facilities in place at all of our California terminals necessary to serve all of our customers. The $59.8 million (10%) increase in segment revenues in 2004 compared to 2003 was driven by $23.2 million of incremental revenues attributable to the acquisition of our Southeast terminals. In addition, revenues from our Pacific operations increased $16.6 million (5%) and revenues from our proportionate share of Cochin increased $13.1 million (53%). Our Pacific operations' year-over-year increase was due to both the higher terminal revenues, discussed above, and higher transport revenues, due largely to an almost 2% increase in mainline delivery volumes. Cochin's increase in revenues was mainly due to a 30% increase in delivery volumes and to higher average tariff rates. The increase in delivery volumes in 2004 versus 2003 was partly related to lower product inventory levels in western Canada in the first half of 2003, caused by a drop in propane production. The drop in propane production was a reaction to lower profit margins from the extraction and sale of natural gas liquids caused by a rise in natural gas prices since the end of 2002. Revenues from our Central Florida Pipeline increased $2.7 million (8%) in 2004 compared to 2003. The increase was due to an almost 8% increase in product delivery volumes. Combined, the segment benefited from a 2% increase in the volume of refined products delivered during 2004 compared to 2003. Combining all of the segment's operations, total throughput delivery of refined petroleum products, consisting of gasoline, diesel fuel and jet fuel, increased 2% in 2004 compared to 2003. Jet fuel delivery volumes, boosted by strong military and solid commercial demand, were up nearly 6% in 2004 compared to 2003, and gasoline delivery volumes increased 2%. Deliveries of diesel fuel were essentially flat across both 2004 and 2003, but both gasoline and diesel volumes were impacted in the fourth quarter of 2004 by the shut-down of a refinery connected to the Plantation Pipeline following Hurricane Ivan. The $8.9 million (2%) increase in segment revenues in 2003 compared to 2002 was driven by a $7.1 million (2%) increase in combined revenues from our Pacific operations and West Coast terminals, largely due to increased terminal services. Revenues from our North System increased $3.9 million (11%) in 2003 versus 2002. Although throughput deliveries on our North System dropped by 4% in 2003, we benefited from a 15% increase in average tariff rates as a result of an increased cost of service tariff agreement filed with the Federal Energy Regulatory Commission in May 2003. Revenues from our CALNEV Pipeline increased $2.9 million (6%) in 2003 versus 2002, due to higher revenues from both refined product deliveries and fees associated with ethanol blending operations. CALNEV benefited from a 5% increase in the average tariff per barrel transported, due mostly to an increase in transportation of longer-haul, higher margin barrels. Revenues from our combined transmix operations increased $1.6 million (6%) in 2003 compared to 2002, primarily due to higher processing volumes at our transmix facilities located in Richmond, Virginia and Indianola, Pennsylvania. Revenues from our Central Florida Pipeline operations also increased by $1.6 million (5%) in 2003 versus 2002, due to higher storage revenues at our liquids terminal located in Tampa, Florida and to higher refined product delivery revenues associated with a 2% increase in delivery volumes. The overall increase in segment revenues in 2003 compared to 2002 was offset by a $7.5 million (23%) decrease in revenues from our investment in the Cochin pipeline system and a $1.1 million (16%) decrease in revenues earned from our Cypress Pipeline. In addition to the impact of lower propane production described above, Cochin's 2003 earnings and revenues were negatively impacted by a pipeline rupture and fire in July 2003 that led to the shut down of the system for 29 days during the third quarter. The year-to-year drop in Cypress' revenues was due to lower throughput volumes and to customers catching up on liquids volumes earned but not delivered in prior periods. For the segment as a whole, total throughput delivery of refined petroleum products decreased 1% in 2003 compared to 2002. The decrease resulted from the 2003 transition from MTBE-blended gasoline to ethanol-blended gasoline, and the fact that ethanol cannot be transported via pipeline but must instead be blended at terminals. Our combined diesel and jet fuel deliveries, however, increased 2% in 2003 versus 2002, mainly due to a 6% increase in diesel delivery volumes and to improvement in jet fuel delivery volumes in the fourth quarter of 2003. 60 <PAGE> The segment's operating expenses increased $21.9 million (13%) in 2004 compared to 2003. The increase was mainly due to incremental expenses of $9.3 million from our Southeast terminals and to a $3.8 million (5%) increase in expenses from our Pacific operations, largely the result of higher 2004 fuel and power expenses associated with higher utility rates and higher delivery volumes. The segment also reported $1.6 million year-over-year increases in expenses in 2004 from each of the Cochin Pipeline, North System, CALNEV Pipeline and Plantation Pipeline. Cochin's increase was related to higher expenses associated with the increased delivery volumes and our additional ownership interest. The North System's increase was primarily due to higher natural gas liquids storage expenses. CALNEV's increase was mostly due to higher fuel and power expenses due to favorable credit adjustments to electricity access and surcharge reserves taken in the first nine months of 2003. Plantation's increase was primarily related to higher 2004 labor, testing and maintenance expenses. The segment's operating expenses remained relatively flat in 2003, compared to 2002. Earnings from our Products Pipelines' equity investments were $29.1 million in 2004, $30.9 million in 2003 and $29.0 million in 2002. Earnings from equity investments consist primarily of earnings from our approximate 51% ownership interest in Plantation Pipe Line Company and our 50% ownership interest in Heartland Pipeline Company, both accounted for under the equity method of accounting. The $1.8 million (6%) decrease in equity earnings in 2004 compared to 2003 was mainly due to a $2.4 million (8%) decrease in equity earnings from Plantation, mainly due to a $3.2 million expense recorded in the first quarter of 2004 for our share of an environmental litigation settlement reached between Plantation and various plaintiffs. In 2005, we expect to recover the cost of the settlement under various insurance policies. The $1.9 million (7%) increase in equity earnings in 2003 versus 2002 was primarily due to a $1.5 million (5%) increase in equity earnings related to our ownership interest in Plantation. The increase resulted primarily from higher litigation settlement costs recognized during the fourth quarter of 2002, partially offset by lower earnings from product deliveries in 2003. Excluding the 2004 and 2002 environmental charges, interest and other income items decreased $1.8 million in 2004 versus 2003, and increased $4.8 million in 2003 versus 2002. Both changes were largely due to higher gains realized from sales of property, plant and equipment by our Pacific operations during 2003. Non-cash depreciation, depletion and amortization charges, including amortization of excess cost of investments, were $74.5 million, $70.6 million and $67.7 million in each of the years ended December 31, 2004, 2003 and 2002, respectively. The $3.9 million (6%) increase in 2004 versus 2003 was primarily due to incremental depreciation charges from our Southeast terminals and to higher depreciation expenses from our Pacific operations. The $2.9 million (4%) increase in 2003 versus 2002 was driven by higher property and plant depreciation expenses from our Pacific operations, CALNEV Pipeline and West Coast terminals. Excluding the incremental depreciation expenses related to the acquisition of our Southeast terminals, the year-over-year increases in depreciation expenses in both 2004 and 2003 related to the capital spending we have made since the end of 2002 in order to strengthen and enhance our business operations on the West Coast. For 2005, we currently expect that our Products Pipelines segment will report earnings before depreciation, depletion and amortization expense of approximately $535 million, a 13% increase over 2004 (excluding the 2004 environmental charge). The earnings increase is expected to be driven by continued improvement in gasoline and jet fuel delivery volumes, planned capital improvements and expansions (including our Pacific operations' North Line expansion completed in December 2004), and a full year of operations from products terminals acquired in March and November 2004. 61 <PAGE> Natural Gas Pipelines <TABLE> <CAPTION> Year Ended December 31, 2004 2003 2002 ----------- ----------- ----------- (In thousands, except operating statistics) <S> <C> <C> <C> Revenues.................................................. $ 6,252,921 $ 5,316,853 $ 3,086,187 Operating expenses(a)..................................... (5,862,159) (4,967,531) (2,784,278) Earnings from equity investments.......................... 19,960 24,012 23,887 Other, net - income(b).................................... 9,434 1,082 36 Income taxes.............................................. (1,895) (1,066) (378) ----------- ----------- ----------- Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments............................................ 418,261 373,350 325,454 Depreciation, depletion and amortization expense.......... (53,112) (53,785) (48,411) Amortization of excess cost of equity investments......... (277) (277) (277) ----------- ----------- ----------- Segment earnings........................................ $ 364,872 $ 319,288 $ 276,766 =========== =========== =========== Natural gas transport volumes (Trillion Btus)(c).......... 1,353.0 1,364.1 1,261.1 =========== =========== =========== Natural gas sales volumes (Trillion Btus)(d).............. 992.4 906.0 882.8 =========== =========== =========== </TABLE> - ---------- (a) Includes natural gas purchases and other costs of sales, operations and maintenance expenses, fuel and power expenses and taxes, other than income taxes. (b) Includes income of $7,602 in 2004 associated with environmental expense adjustments. (c) Includes Kinder Morgan Interstate Gas Transmission, Texas intrastate natural gas pipeline group, Trailblazer and TransColorado pipeline volumes. TransColorado annual volumes are included for all three years (acquisition date November 1, 2004). (d) Represents Texas intrastate natural gas pipeline group. Kinder Morgan Tejas sales volumes are included for all three years (acquisition date January 31, 2002). Our Natural Gas Pipelines segment's primary businesses involve marketing, transporting and storing natural gas through both intrastate and interstate pipeline systems. In 2004, the segment reported earnings before depreciation, depletion and amortization of $418.3 million on revenues of $6,252.9 million. This compared to earnings before depreciation, depletion and amortization of $373.4 million on revenues of $5,316.9 million in 2003 and earnings before depreciation, depletion and amortization of $325.5 million on revenues of $3,086.2 million in 2002. As noted in the table above, the segment's 2004 earnings include a $7.6 million increase from the adjustment of our environmental liabilities referred to in "Critical Accounting Policies and Estimates--Environmental Matters." Excluding this environmental adjustment, segment earnings before depreciation, depletion and amortization increased $37.3 million (10%) in 2004 compared to 2003. This increase, along with the $47.9 million (15%) increase in earnings before depreciation, depletion and amortization in 2003 versus 2002, was primarily attributable to higher earnings from our Texas intrastate natural gas pipeline group, which includes the operations of the following four natural gas pipeline systems: Kinder Morgan Tejas, Kinder Morgan Texas Pipeline, North Texas Pipeline and Mier-Monterrey Mexico Pipeline. The year-over-year increases in earnings before depreciation, depletion and amortization from our Texas intrastate natural gas pipeline group were mainly due to improved margins and higher volumes from natural gas sales activities, strong returns from capital investments made since the end of 2002, and incremental earnings from value added services, including storage, blending and other services. Since our acquisition of Kinder Morgan Tejas on January 31, 2002, we have increased the interconnection capability between its system and Kinder Morgan Texas Pipeline, improved system processes and controls and further refined the management of risk associated with the sale and transmission of natural gas. Kinder Morgan Tejas' operations include a 3,400-mile intrastate natural gas pipeline system that has access to a number of natural gas supply basins in the State of Texas; Kinder Morgan Texas Pipeline's operations include approximately 2,500 miles of pipelines, supply and gathering lines, laterals and related facilities principally located in the Texas Gulf Coast area. These two systems comprise the major components of our Texas intrastate group and together reported a $41.1 million (24%) increase in earnings before depreciation, depletion and amortization in 2004 compared to 2003. In 2003, the two systems combined reported a $30.7 million (22%) increase in earnings before depreciation, depletion and amortization compared to 2002. 62 <PAGE> Furthermore, we have continued to grow internally and have developed and built new natural gas pipeline systems to transport gas from expanding production areas and to serve new market areas. Contributions from the two remaining Texas intrastate systems, our North Texas Pipeline, completed in August 2002, and our Mier-Monterrey Pipeline, completed in March 2003, accounted for $3.5 million (9%) of the segment's total increase in earnings before depreciation, depletion and amortization in 2004 compared to 2003, and $14.9 million (31%) of the segment's total increase in earnings before depreciation, depletion and amortization in 2003 compared to 2002. The increases were driven by higher transportation revenues linked to growing demand for natural gas in both Texas and the Monterrey, Mexico region. Our Rocky Mountain interstate natural gas pipeline operations consist of the following three natural gas pipeline systems: Kinder Morgan Interstate Gas Transmission, Trailblazer Pipeline and TransColorado Pipeline. We acquired TransColorado Gas Transmission Company from KMI effective November 1, 2004. The TransColorado system includes a 300-mile interstate natural gas pipeline that originates in the Piceance Basin of western Colorado and runs to the Blanco Hub in northwest New Mexico. All three pipelines charge a transportation fee for gas transmission service and have the authority to initiate natural gas sales primarily for operational purposes, but none engage in significant gas purchases for resale. Operational natural gas sales are primarily made possible by collection of fuel in kind pursuant to each pipeline's natural gas transportation tariff. Together, our Rocky Mountain pipelines reported a $3.8 million (3%) decrease in earnings before depreciation, depletion and amortization in 2004 compared to 2003. The decrease was due to lower earnings from our Trailblazer Pipeline, mainly due to lower revenues as a result of timing on imbalance cashouts and lower transportation revenues. The decreases in transportation revenues were due to lower tariff rates that became effective January 1, 2004, pursuant to a rate case settlement. In 2003, KMIGT and Trailblazer accounted for $4.6 million (10%) of the segment's total increase in earnings before depreciation, depletion and amortization compared to 2002. The increase in 2003 over 2002 was mainly due to the benefits resulting from an expansion of our Trailblazer Pipeline system. In May 2002, we completed a fully-subscribed, $48 million expansion project on the Trailblazer system that expanded its transportation capacity by 324,000 dekatherms of natural gas per day. The expansion increased capacity on the pipeline by approximately 60% and provided new firm long-term transportation service. As a result, Trailblazer realized a 12% increase in natural gas transportation volumes in 2003 compared to 2002. In each of the years 2004 and 2003, the segment reported significant increases in both revenues and operating expenses when compared to the year-earlier period. Revenues earned by our Natural Gas Pipelines segment increased $936.0 million (18%) in 2004 versus 2003, and $2,230.7 million (72%) in 2003 versus 2002. Operating expenses, including natural gas purchase costs, increased $894.6 million (18%) in 2004 compared to 2003, and $2,183.3 million (78%) in 2003 compared to 2002. The year-over-year increases in revenues and operating expenses were primarily attributable to the internal growth and integration of our Kinder Morgan Tejas and Kinder Morgan Texas Pipeline systems since the end of 2002. Both pipeline systems buy and sell significant volumes of natural gas, which is also transported on their pipelines, and our objective is to match purchases and sales, thus locking-in the equivalent of a transportation fee. We manage remaining price risk by the use of energy financial instruments. Combined, the two systems reported increases in natural gas sales revenues of $912.2 million (19%) in 2004 compared to 2003, and $2,117.6 million (78%) in 2003 compared to 2002. Both increases were due to higher average sale prices and higher sales volumes; the increase in 2004 compared to 2003 resulted from an almost 9% increase in average gas prices (from $5.32 per dekatherm in 2003 to $5.78 per dekatherm in 2004) and an almost 10% increase in gas sales volumes. Revenues from our recently acquired TransColorado Pipeline totaled $6.7 million in 2004. Kinder Morgan Tejas and Kinder Morgan Texas Pipeline together reported combined increases in costs of sales of $870.7 million (18%) in 2004 compared to 2003, and $2,123.3 million (80%) in 2003 compared to 2002. Both increases were due to higher average costs of natural gas sold and higher volumes of gas purchased for sale; the increase in 2004 compared to 2003 resulted from an 8% increase in the average price of purchased gas (from $5.22 per dekatherm in 2003 to $5.66 per dekatherm in 2004) and a 9% increase in gas purchase volumes. Due to the offsetting nature of gas sales and cost of gas sold, we believe that earnings before depreciation, depletion and amortization or a similar measure of margin, defined as revenues less cost of gas sold, is a better comparative performance indicator than revenues because the mix of utility volumes between sales and transportation service affects revenues but not margin. 63 <PAGE> We account for the segment's investments in Red Cedar Gas Gathering Company, Coyote Gas Treating, LLC and Thunder Creek Gas Services, LLC under the equity method of accounting. In 2004, equity earnings from these three investees decreased $4.1 million (17%) compared to 2003. The decrease was chiefly due to lower earnings from our 49% investment in Red Cedar, mainly due to higher operational sales of natural gas by Red Cedar in 2003. Earnings from equity investments were relatively flat across 2003 and 2002; higher earnings in 2003 from our 25% investment in Thunder Creek were largely offset by lower earnings from our investment in Red Cedar. The segment's non-cash depreciation, depletion and amortization charges, including amortization of excess cost of investments decreased a slight $0.7 million (1%) in 2004 compared to 2003, primarily due to lower year-to-year depreciation expense on our Trailblazer Pipeline. The decrease was due to the rate case settlement which became effective January 1, 2004. The $5.4 million (11%) increase in depreciation, depletion and amortization charges in 2003 over 2002 was primarily due to incremental depreciation charges related to the completed North Texas and Mier-Monterrey pipeline systems. For 2005, we currently expect that our Natural Gas Pipelines segment will report earnings before depreciation, depletion and amortization expense of approximately $439 million, a 7% increase over 2004 (excluding the 2004 environmental expense adjustment). The earnings increase is expected to be driven by additional earnings realized from the sale of natural gas at higher margins, increases in storage and transportation services, the benefits of reaching new markets and customers by planned capital spending, and a full year of operations from our TransColorado Pipeline. CO2 <TABLE> <CAPTION> Year Ended December 31, 2004 2003 2002 --------- -------- -------- (In thousands, except operating statistics) <S> <C> <C> <C> Revenues....................................... $ 492,834 $248,535 $146,280 Operating expenses(a).......................... (173,382) (82,055) (50,524) Earnings from equity investments............... 34,179 37,198 36,328 Other, net - income (expense)(b)............... 4,152 (40) 112 Income taxes................................... (147) (39) - --------- -------- -------- Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments........... 357,636 203,599 132,196 Depreciation, depletion and amortization expense(c).................................... (121,361) (60,827) (29,196) Amortization of excess cost of equity investments................................... (2,017) (2,017) (2,017) --------- -------- -------- Segment earnings............................. $ 234,258 $140,755 $100,983 ========= ======== ======== Carbon dioxide delivery volumes (Bcf)(d)......... 640.8 504.7 431.7 ========= ======== ======== SACROC oil production (MBbl/d)(e)................ 28.3 20.2 13.0 ========= ======== ======== Yates oil production (MBbl/d)(e)................. 19.5 18.9 18.3 ========= ======== ======== Natural gas liquids sales volumes (MBbl/d)(f).... 7.7 3.7 2.1 ========= ======== ======== Realized weighted average oil price per Bbl(g)(h) $ 25.72 $ 23.73 $ 22.45 ========= ======== ======== Realized weighted average natural gas liquids price per Bbl(h)(i).............................. $ 31.33 $ 21.77 $ 24.60 ========= ======== ======== </TABLE> - ---------- (a) Includes costs of sales, operations and maintenance expenses, fuel and power expenses and taxes, other than income taxes. (b) Includes income of $4,126 in 2004 associated with environmental reserve adjustments. (c) Includes expenses associated with oil and gas production activities and gas processing activities in the amount of $105,890 for 2004, $49,039 for 2003, and $19,337 for 2002. Includes expenses associated with sales and transportation services activities in the amount of $15,471 for 2004, $11,788 for 2003, and $9,859 for 2002. (d) Includes Cortez, Central Basin, Canyon Reef Carriers, Centerline and Pecos pipeline volumes. (e) Represents 100% of the production from the field. (f) Net to Kinder Morgan. (g) Includes all Kinder Morgan crude oil production properties. (h) Hedge gains/losses for oil and natural gas liquids are included with crude oil. (i) Includes production attributable to leasehold ownership and production attributable to our ownership in processing plants and third party processing agreements. 64 <PAGE> Our CO2 segment consists of Kinder Morgan CO2 Company, L.P. and its consolidated affiliates. The segment's primary businesses involve the production, transportation and marketing of carbon dioxide, commonly called CO2, and the production and marketing of crude oil and natural gas. In 2004, our CO2 segment reported earnings before depreciation, depletion and amortization of $357.6 million on revenues of $492.8 million. This compared to earnings before depreciation, depletion and amortization of $203.6 million on revenues of $248.5 million in 2003 and earnings before depreciation, depletion and amortization of $132.2 million on revenues of $146.3 million in 2002. As noted in the table above, the segment's 2004 earnings include a $4.1 million increase from the adjustment of our environmental liabilities referred to in "Critical Accounting Policies and Estimates--Environmental Matters." Excluding the increase from this environmental adjustment, segment earnings before depreciation, depletion and amortization increased $149.9 million (74%) in 2004 compared to 2003. This increase, along with the $71.4 million (54%) increase in earnings before depreciation, depletion and amortization in 2003 over 2002, was driven by higher earnings from oil and gas producing activities and gas processing activities, higher deliveries of carbon dioxide, and strategic acquisitions of additional working interests in the SACROC and Yates oil field units since the end of 2002. Excluding earnings attributable to the 2004 environmental liability adjustment, our CO2 segment's oil and gas producing activities and gas processing activities reported earnings before depreciation, depletion and amortization of $220.4 million in 2004, $103.6 million in 2003 and $51.5 million in 2002. These increases of $116.8 million (113%) and $52.1 million (101%) from 2003 to 2004 and from 2002 to 2003, respectively, were primarily attributable to increased oil production volumes, increases in the realized weighted average price of oil per barrel, and acquisitions of additional ownership interests in oil producing properties. These acquisitions included the following: o effective June 1, 2003, we acquired MKM Partners, L.P.'s 12.75% ownership interest in the SACROC oil field unit for $23.3 million in cash and the assumption of $1.9 million of liabilities. This transaction increased our ownership interest in the SACROC unit to approximately 97%; and o effective November 1, 2003, we acquired certain assets in the Permian Basin of West Texas from a subsidiary of Marathon Oil Corporation for $230.2 million in cash and the assumption of $29.7 million of liabilities. The assets acquired included Marathon's approximate 42.5% interest in the Yates oil field unit, the crude oil gathering system surrounding the Yates field unit and Marathon's 65% ownership interest in the Pecos Carbon Dioxide Pipeline Company. This transaction increased our ownership interest in the Yates oil field unit to nearly 50% and allowed us to become operator of the field. Excluding earnings attributable to the 2004 environmental liability adjustment, our CO2 segment's carbon dioxide sales and carbon dioxide and crude oil transportation activities reported earnings before depreciation, depletion and amortization of $133.1 million in 2004, $100.0 million in 2003 and $80.7 million in 2002. The increase of $33.1 million (33%) in 2004 compared to 2003 was driven by higher revenues from carbon dioxide sales and deliveries, mainly due to higher average carbon dioxide sale prices and higher transportation volumes related to infrastructure expansions at the SACROC and Yates oil field units. The increase of $19.3 million (24%) in earnings before depreciation, depletion and amortization in 2003 compared to 2002 was chiefly due to higher revenues from carbon dioxide pipeline delivery volumes, including the operations of our Centerline carbon dioxide pipeline, which was completed and began operations in May 2003. Capacity and deliverability of carbon dioxide in and around the Permian Basin has expanded since the end of 2002 in order to accommodate growing customer demand. In 2004, capital expenditures for our CO2 business segment totaled $302.9 million, 11% higher than the $272.2 million of capital expenditures made during 2003, and 86% higher than the $163.2 million of expenditures in 2002. The year-over-year increases largely represented incremental spending for new well and injection compression facilities at the SACROC and, to a much lesser extent, Yates oil field units in order to enhance oil recovery from carbon dioxide injection. In 2004, we also benefited from the acquisition of the Kinder Morgan Wink Pipeline, a 450-mile crude oil pipeline located in West Texas. Effective August 31, 2004, we acquired all of the partnership interests in Kinder Morgan Wink Pipeline, L.P. for $89.9 million in cash and the assumption of $10.4 million in liabilities. The 65 <PAGE> acquisition of the pipeline and associated storage facilities allows us to better manage crude oil deliveries from our oil field interests in West Texas. The Wink Pipeline contributed $6.0 million in earnings before depreciation, depletion and amortization during the last four months of 2004. Revenues earned by our CO2 business segment increased $244.3 million (98%) in 2004 compared to 2003, and $102.2 million (70%) in 2003 compared to 2002. The increases were mainly due to higher crude oil and gasoline plant product sales revenues, driven by higher oil production volumes, higher average crude oil and gasoline product prices, and the additional working interest in the Yates oil field that we acquired in November 2003. Combined, the assets we acquired on November 1, 2003 contributed incremental revenues of approximately $96.3 million in 2004. Daily oil production at the SACROC and Yates field units, both located in the Permian Basin of West Texas, increased 40% and 3%, respectively, in 2004 compared to 2003, and 55% and 3%, respectively, in 2003 compared to 2002. We also benefited from increases of 8% and 44%, respectively, in our realized weighted average price of oil and natural gas liquids per barrel in 2004 compared to 2003, and a 6% increase in our realized weighted average price of oil per barrel in 2003 compared to 2002. As a result of our carbon dioxide and oil reserve ownership interests, we are exposed to commodity price risk associated with physical crude oil and carbon dioxide sales that have pricing tied to crude oil prices, but the risk is mitigated by our long-term hedging strategy that is intended to generate more stable realized prices. For more information on our hedging activities, see Note 14 to our consolidated financial statements, included elsewhere in this report. Additionally, in both 2004 and 2003, we realized higher revenues from carbon dioxide transportation services. The year-over-year increases were mainly due to higher transportation volumes, due to continued strong demand for carbon dioxide throughout the Permian Basin. Combined deliveries of carbon dioxide on our Central Basin Pipeline, our majority-owned Canyon Reef Carriers and Pecos Pipelines, our Centerline Pipeline, and our 50% owned Cortez Pipeline, which is accounted for under the equity method of accounting, increased 27% in 2004 and 17% in 2003. In 2004, we also realized higher revenues from carbon dioxide sales, due to higher average prices; however, revenues from the sales of carbon dioxide were lower in 2003 compared to 2002 due to a larger elimination of intercompany profit, in 2003, related to an increase in the volumes of our carbon dioxide utilized in our own operations. We do not recognize profits on carbon dioxide sales to ourselves. Incremental revenues earned by our Kinder Morgan Wink Pipeline totaled $7.8 million in 2004. As discussed in Note 2 to our consolidated financial statements included elsewhere in this report, the cost of carbon dioxide that is associated with enhanced recovery is capitalized as part of our development costs when it is injected. The carbon dioxide costs incurred and capitalized as development costs for our CO2 segment were $70.6 million, $45.9 million and $31.0 million for the years ended December 31, 2004, 2003 and 2002, respectively. We estimate that such costs will be approximately $44.1 million, $55.8 million and $59.2 million in 2005, 2006 and 2007, respectively. It is expected that, due to the nature of this enhanced recovery process and the characteristics of the underlying reservoir, the capitalized cost for carbon dioxide in 2007 will represent a peak and is expected to decline thereafter. In addition, as of December 31, 2004, our projected expenditures for developing our proved undeveloped reserves will be approximately $183.4 million in 2005, $121.7 million in 2006, and $68.6 million in 2007. Both the $91.3 million (111%) increase in operating expenses in 2004 versus 2003, and the $31.5 million (62%) increase in operating expenses in 2003 versus 2002, were primarily related to higher operating and maintenance expenses, higher fuel and power costs, and higher production taxes, all as a result of higher oil production volumes, higher carbon dioxide delivery volumes, and increases in oil reserve ownership interests and segment assets. Earnings from equity investments decreased $3.0 million (8%) in 2004 compared to 2003. The decrease resulted from the absence of equity earnings, in 2004, from our previous 15% ownership interest in MKM Partners, L.P. Following our June 1, 2003 acquisition of its 12.75% interest in the SACROC unit, MKM Partners was dissolved effective June 30, 2003, and the lack of equity earnings in 2004 more than offset a $2.0 million (6%) increase in equity earnings from our 50% investment in the Cortez Pipeline Company. The increase in equity earnings from Cortez was mainly due to higher carbon dioxide delivery volumes in 2004 versus 2003. The $0.9 million (2%) increase in earnings from equity investments in 2003 compared to 2002 reflects the net of a $4.1 million (14%) increase in equity earnings from our 50% investment in Cortez Pipeline Company, partially offset by a $3.2 million (39%) decrease in equity earnings from our previous 15% interest in MKM Partners, L.P. The increase in earnings 66 <PAGE> from our equity interest in Cortez was mainly due to higher carbon dioxide delivery volumes, lower average debt balances and slightly lower borrowing rates. Non-cash depreciation, depletion and amortization charges, including amortization of excess cost of equity investments, were up $60.5 million (96%) in 2004 compared to 2003 and $31.6 million (101%) in 2003 compared to 2002. The increases were primarily due to year-over-year increases in production volumes, capital investments, and acquisitions of property interests. In addition, the capital additions we have made since the end of 2002 have increased the unit-of-production depletion rates. For 2005, we currently expect that our CO2 segment will report earnings before depreciation, depletion and amortization expense of approximately $474 million, a 34% increase over 2004 (excluding the 2004 environmental expense adjustment). The earnings increase is expected to be driven by the continuing development of the SACROC and Yates oil field units. Terminals <TABLE> <CAPTION> Year Ended December 31, --------------------------------- 2004 2003 2002 --------- --------- --------- (In thousands, except operating statistics) <S> <C> <C> <C> Revenues.................................................. $ 541,857 $ 473,558 $ 428,048 Operating expenses(a)..................................... (272,766) (229,054) (213,929) Earnings from equity investments.......................... 1 41 45 Other, net - income(b).................................... 18,255 88 15,550 Income taxes(c)........................................... (5,609) (3,857) (4,751) --------- --------- --------- Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments............................................ 281,738 240,776 224,963 Depreciation, depletion and amortization expense.......... (42,890) (37,075) (30,046) Amortization of excess cost of equity investments......... - - - --------- --------- --------- Segment earnings........................................ $ 238,848 $ 203,701 $ 194,917 ========= ========= ========= Bulk transload tonnage (MMtons)(d)........................ 67.7 61.2 58.7 ========= ========= ========= Liquids leaseable capacity (MMBbl)........................ 36.8 36.2 35.3 ========= ========= ========= Liquids utilization %..................................... 96.6% 96.0% 97.0% ========= ========= ========= </TABLE> - ---------- (a) Includes costs of sales, operations and maintenance expenses, fuel and power expenses and taxes, other than income taxes. (b) Includes income of $18,651 and $16,000 in 2004 and 2002, respectively, associated with adjustments to environmental liabilities. (c) Includes expense of $80 in 2004 associated with adjustments to environmental liabilities. (d) Includes Cora, Grand Rivers and Kinder Morgan Bulk Terminals aggregate terminal throughputs; excludes operatorship of LAXT bulk terminal. Our Terminals segment includes the operations of our coal, petroleum coke, steel and other dry-bulk material terminals, as well as all the operations of our petroleum and petrochemical-related liquids terminal facilities. The segment reported earnings before depreciation, depletion and amortization of $281.7 million on revenues of $541.9 million in 2004. This compared to earnings before depreciation, depletion and amortization of $240.8 million on revenues of $473.6 million in 2003 and earnings before depreciation, depletion and amortization of $225.0 million on revenues of $428.0 million in 2002. As noted in the table above, the segment's 2004 and 2002 earnings included earnings of $18.6 million and $16.0 million, respectively, from the adjustment of our environmental liabilities referred to in "Critical Accounting Policies and Estimates--Environmental Matters." Excluding these environmental adjustments, segment earnings before depreciation, depletion and amortization increased $22.3 million (9%) in 2004 compared to 2003, and increased $31.8 million (15%) in 2003 compared to 2002. The $22.3 million increase in earnings before depreciation, depletion and amortization in 2004 over 2003 was driven by higher revenues from both our bulk and liquids terminal businesses, due to (i) higher transfer volumes of bulk products; (ii) higher demand for storage and distribution services offered for petroleum and liquid chemical 67 <PAGE> products; and (iii) additional storage and throughput capacity due to both terminal acquisitions and the completion of capital projects since the end of 2003. Combined, our bulk terminal facilities reported an almost 11% increase in total bulk tonnage volumes transloaded during 2004, as compared to 2003. In turn, completed capital expansions and betterments at our liquids facilities since the end of 2003, which included the construction of additional petroleum products storage tanks, have increased our liquids storage capacity by approximately 600,000 barrels (2%), and at the same time, we have increased our liquids utilization capacity. For terminal operations owned during both 2004 and 2003, growth in both segment earnings before depreciation, depletion and amortization charges and segment revenues were primarily attributable to record throughput at our Gulf Coast liquids terminals, and to higher coal, bulk and synfuel volumes from certain of our Mid-Atlantic terminals, which include our Chesapeake Bay, Maryland bulk terminal and our Pier IX bulk terminal located in Newport News, Virginia. Our two Gulf Coast liquids terminals, located on the Houston, Texas Ship Channel, reported a combined $3.8 million increase in earnings before depreciation, depletion and amortization in 2004 compared to 2003. The increase was driven by a $7.1 million increase in revenues resulting from higher throughput volumes, contract price escalations, additional service contracts and new pipeline connections. Our Chesapeake Bay facility reported a $2.7 million increase in earnings before depreciation, depletion and amortization in 2004 compared to 2003. The increase was driven by a $7.5 million increase in revenues, earned by providing additional stevedoring services and storage and transportation for products such as coal, petroleum coke, pig iron and steel slag. Our Pier IX terminal, which transloads both coal and cement and operates a synfuel plant on site, reported a $4.0 million increase in earnings before depreciation, depletion and amortization in 2004 compared to 2003. The increase was driven by a $6.3 million increase in revenues resulting from higher synfuel revenues and coal activity. In February 2004, Pier IX began to operate a second synfuel plant on site. Approximately half of the $31.8 million increase in earnings before depreciation, depletion and amortization in 2003 over 2002 was attributable to expansion projects at existing liquids terminals, and the remainder was attributable to contributions from the bulk and liquid terminal businesses we acquired since September 1, 2002. Terminal acquisitions completed since the fourth quarter of 2003 helped increase both segment earnings before depreciation, depletion and amortization and segment revenues in 2004 versus 2003. These acquisitions primarily consisted of the following: o the Kinder Morgan Tampaplex marine terminal and inland bulk storage warehouse facility, both located in Tampa, Florida and acquired in December 2003; o the terminals owned and operated by Kinder Morgan River Terminals LLC and its consolidated subsidiaries, acquired effective October 6, 2004; and o the Kinder Morgan Fairless Hills bulk terminal facility, acquired effective December 1, 2004. Combined, these businesses, in 2004, contributed incremental earnings before depreciation, depletion and amortization of $9.7 million and incremental revenues of $26.7 million. Excluding earnings attributable to the 2002 environmental adjustments, $15.1 million (47%) of the segment's $31.8 million increase in earnings before depreciation, depletion and amortization, and $14.9 million (33%) of the total $45.6 million (11%) increase in revenues in 2003 versus 2002 was attributable to internal growth, largely resulting from the expansion projects undertaken to increase leaseable liquids capacity at our liquids terminal facility located in Carteret, New Jersey on the New York Harbor, and at our two Gulf Coast liquids terminals. We completed the construction of five 100,000 barrel petroleum products storage tanks at our Carteret facility since the end of the third quarter of 2002. Combined, these expansion projects contributed to an almost 3% increase in our overall liquids terminals' leaseable capacity in 2003 compared to 2002, more than offsetting the slight 1% drop in our overall utilization percentage in 2003. Over half of the decline in utilization during 2003 was associated with tank maintenance. In addition to the contributions to earnings and revenues that were attributable to capital expansions, we benefited from additional liquids storage contracts, escalations in annual contract provisions at many of our liquids facilities, and higher returns from our 66 2/3% ownership interest in the International Marine Terminals Partnership. 68 <PAGE> IMT, which operates a bulk commodity transfer terminal facility located in Port Sulphur, Louisiana, reported increases of $1.5 million in earnings before depreciation, depletion and amortization, and $5.1 million in revenues in 2003 versus 2002. The increases were driven by an almost 10% increase in bulk tonnage transfer volume, primarily coal and iron ore, and by higher dockage revenues. The remaining $16.7 million (53%) of the segment's year-to-year increase in earnings before depreciation, depletion and amortization and $30.7 million (67%) of the year-to-year increase in revenues in 2003 versus 2002 was attributable to strategic acquisitions of new terminal businesses acquired since September 1, 2002, including the following: o the Owensboro Gateway Terminal, acquired effective September 1, 2002; o the St. Gabriel Terminal, acquired effective September 1, 2002; o the purchase of four floating cranes at our bulk terminal facility in Port Sulphur, Louisiana in December 2002; o the bulk terminal businesses acquired from M.J. Rudolph Corporation, effective January 1, 2003; and o the two bulk terminal businesses in Tampa, Florida, acquired in December 2003. The segment's overall increases in both earnings before depreciation, depletion and amortization and revenues in 2003 compared to 2002 included decreases of $1.8 million (24%) and $3.0 million (23%), respectively, from our Cora coal terminal facility located near Cora, Illinois. The decrease in coal revenues and earnings was primarily related to an expected decrease in coal tonnage handled under contract for the Tennessee Valley Authority. The TVA has diverted some of its business to new competing coal terminals that have come on-line since the end of 2002. Both the $43.7 million (19%) increase in operating expenses in 2004 compared to 2003 and the $15.1 million (7%) increase in operating expenses in 2003 compared to 2002, were due to the year-over-year increases in bulk tonnage transfer volumes, liquids throughput and storage capacity, and the terminal acquisitions described above. The increases were primarily reflected as higher operating, maintenance, fuel and electricity expenses, including payroll, trucking, equipment rental and docking expenses, all related to increased dry-bulk and liquids product transfers and ship conveyance activities. Income tax expenses totaled $5.5 million in 2004 (excluding the $0.1 million tax expense on earnings attributable to adjustments to the environmental liabilities recorded by taxable entities), $3.9 million in 2003 and $4.8 million in 2002. The $1.6 million (41%) increase in income tax expense in 2004 compared to 2003 was primarily due to incremental expense related to the taxable income of certain subsidiaries of Kinder Morgan River Terminals LLC. The $0.9 million (19%) decrease in income tax expense in 2003 compared to 2002 was primarily due to favorable tax adjustments related to the taxable income and tax-paying obligations of Kinder Morgan Bulk Terminals, Inc. and its consolidated subsidiaries. Non-cash depreciation, depletion and amortization charges were $42.9 million, $37.1 million and $30.0 million in each of the years ended December 31, 2004, 2003 and 2002, respectively. Both the $5.8 million (16%) increase in 2004 versus 2003 and the $7.1 million (24%) increase in 2003 versus 2002 were primarily due to property acquisitions and capital spending, and to adjustments made to the estimated remaining useful lives of depreciable property since the end of 2002. For 2005, we currently expect that our Terminals segment will report earnings before depreciation, depletion and amortization expense of approximately $288 million, a 9% increase over 2004 (excluding the 2004 environmental expense adjustment, net of taxes). The earnings increase is expected to be driven by on-going capital expansion projects, by expected increases in bulk tonnage transfer volumes, and by incremental earnings from the inclusion of a full year of operations from Kinder Morgan River Terminals LLC and the Kinder Morgan Fairless Hills terminal. 69 <PAGE> Other <TABLE> <CAPTION> Year Ended December 31, -------------------------------------- 2004 2003 2002 ----------- ----------- ----------- (In thousands - income/(expense)) <S> <C> <C> <C> General and administrative expenses............... $ (170,507) $ (150,435) $ (122,205) Unallocable interest, net......................... (194,973) (181,357) (176,460) Minority interest................................. (9,679) (9,054) (9,559) Loss from early extinguishment of debt............ (1,562) - - Cumulative effect adjustment from change in accounting principle............................. - 3,465 - ----------- ----------- ----------- Interest and corporate administrative expenses.. $ (376,721) $ (337,381) $ (308,224) =========== =========== =========== </TABLE> Items not attributable to any segment include general and administrative expenses, unallocable interest income, interest expense and minority interest. We also included both the $1.6 million loss from our early extinguishment of debt in 2004 and the $3.4 million benefit from the cumulative effect adjustment of a change in accounting for asset retirement obligations as of January 1, 2003 (discussed above), as items not attributable to any business segment. The loss from the early extinguishment of debt represented the excess of the price we paid to repurchase and retire the principal amount of $87.9 million of tax-exempt industrial revenue bonds over the bonds' carrying value. We assumed these industrial revenue bonds as part of our January 2001 acquisition of Kinder Morgan Liquids Terminals LLC. Pursuant to certain provisions that gave us the right to call and retire the bonds prior to maturity, we took advantage of the opportunity to refinance at lower rates. For more information on our early extinguishment of debt, see Note 9 to our consolidated financial statements, included elsewhere in this report. Our general and administrative expenses include such items as salaries and employee-related expenses, payroll taxes, legal fees, insurance and office supplies and rentals. Overall general and administrative expenses totaled $170.5 million in 2004, compared to $150.4 million in 2003 and $122.2 million in 2002. The $20.1 million (13%) increase in general and administrative expenses in 2004 compared to 2003 was principally due to higher employee bonus and benefit expenses, higher corporate and employee-related insurance expenses, and higher corporate service expenses, including legal, internal audit and human resources. The $28.2 million (23%) increase in general and administrative expenses in 2003 compared to 2002 was primarily due to higher legal expenses, higher employee benefit and pension costs and higher overall corporate and employee-related insurance expenses. We continue to aggressively manage our infrastructure expense and to focus on our productivity and expense controls. Interest expense, net of interest income, totaled $195.0 million in 2004, $181.4 million in 2003 and $176.5 million in 2002. Although our average borrowing rates were essentially flat across both 2003 and 2004, we incurred a $13.6 million (7%) increase in net interest charges in 2004 as a result of higher average borrowings. The increase in average borrowings was primarily due to higher capital spending related to internal expansions and improvements, and to incremental borrowings made in connection with acquisition expenditures. For more information on our capital expansion and acquisition expenditures, see "Liquidity and Capital Resources - Investing Activities". The $4.9 million (3%) increase in net interest items in 2003 compared to 2002 reflects higher average borrowings since the end of 2002, partially offset by decreases in average borrowing rates. Minority interest, which includes the 1.0101% general partner interest in our five operating limited partnerships, totaled $9.7 million in 2004, compared to $9.1 million in 2003 and $9.6 million in 2002. The $0.6 million (7%) increase in 2004 versus 2003 resulted mainly from higher overall partnership income, partly offset by our November 2003 acquisition of the remaining approximate 32% ownership interest in MidTex Gas Storage Company, LLP that we did not already own, thereby eliminating the associated minority interest. The $0.5 million (5%) decrease in 2003 compared to 2002 resulted primarily from our May 2002 acquisition of the remaining 33 1/3% ownership interest in Trailblazer Pipeline Company that we did not already own, thereby eliminating the associated minority interest. Liquidity and Capital Resources We attempt to maintain a conservative overall capital structure, with a long-term target mix of approximately 60% equity and 40% debt. The following table illustrates the sources of our invested capital (dollars in thousands). In addition to our results of operations, these balances are affected by our financing activities as discussed below: 70 <PAGE> <TABLE> <CAPTION> December 31, ---------------------------------- 2004 2003 2002 ---------- ---------- ---------- <S> <C> <C> <C> Long-term debt, excluding market value of interest $4,722,410 $4,316,678 $3,659,533 rate swaps........................................... Minority interest.................................... 45,646 40,064 42,033 Partners' capital, excluding accumulated other comprehensive loss................................... 4,353,863 3,666,737 3,461,186 ---------- ---------- ---------- Total capitalization............................... 9,121,919 8,023,479 7,162,752 Short-term debt, less cash and cash equivalents...... - (21,081) (41,088) ---------- ---------- ---------- Total invested capital............................. $9,121,919 $8,002,398 $7,121,664 ========== ========== ========== Capitalization: Long-term debt, excluding market value of interest rate swaps........................................ 51.8% 53.8% 51.1% Minority interest.................................. 0.5% 0.5% 0.6% Partners' capital, excluding accumulated other comprehensive loss................................... 47.7% 45.7% 48.3% ---------- ---------- ---------- 100.0% 100.0% 100.0% ========== ========== ========== Invested Capital: Total debt, less cash and cash equivalents and excluding market value of interest rate swaps.................................... 51.8% 53.7% 50.8% Partners' capital and minority interest, excluding accumulated other comprehensive loss ........ 48.2% 46.3% 49.2% ---------- ---------- ---------- 100.0% 100.0% 100.0% ========== ========== ========== </TABLE> We employ a centralized cash management program that essentially concentrates the cash assets of our operating partnerships and their subsidiaries in joint accounts for the purpose of providing financial flexibility and lowering the cost of borrowing. Our centralized cash management program provides that funds in excess of the daily needs of our operating partnerships and their subsidiaries are concentrated, consolidated, or otherwise made available for use by other entities within our consolidated group. We place no restrictions on the ability to move cash between entities, payment of inter-company balances or the ability to upstream dividends to parent companies. In addition, certain of our operating subsidiaries are subject to Federal Energy Regulatory Commission enacted reporting requirements for oil and natural gas pipeline companies that participate in cash management programs. FERC-regulated entities subject to these rules must, among other things, place their cash management agreements in writing, maintain current copies of the documents authorizing and supporting their cash management agreements, and file documentation establishing the cash management program with the FERC. Our primary cash requirements, in addition to normal operating expenses, are debt service, sustaining capital expenditures, expansion capital expenditures and quarterly distributions to our common unitholders, Class B unitholders and general partner. In addition to utilizing cash generated from operations, we could meet our cash requirements (other than distributions to our common unitholders, Class B unitholders and general partner) through borrowings under our credit facility, issuing short-term commercial paper, long-term notes or additional common units or issuing additional i-units to KMR. In general, we expect to fund: o cash distributions and sustaining capital expenditures with existing cash and cash flows from operating activities; o expansion capital expenditures and working capital deficits with retained cash (resulting from including i-units in the determination of cash distributions per unit but paying quarterly distributions on i-units in additional i-units rather than cash), additional borrowings, the issuance of additional common units or the issuance of additional i-units to KMR; o interest payments with cash flows from operating activities; and o debt principal payments with additional borrowings, as such debt principal payments become due, or by the issuance of additional common units or the issuance of additional i-units to KMR. As a publicly traded limited partnership, our common units are attractive primarily to individual investors, although such investors represent a small segment of the total equity capital market. We believe that some institutional investors prefer shares of KMR over our common units due to tax and other regulatory considerations. We are able to access this segment of the capital market through KMR's purchases of i-units issued by us with the proceeds from the sale of KMR shares to institutional investors. 71 <PAGE> Short-term Liquidity Our principal sources of short-term liquidity are our revolving bank credit facility, our $1.25 billion short-term commercial paper program (which is supported by our revolving bank credit facility, with the amount available for borrowing under our credit facility being reduced by our outstanding commercial paper borrowings) and cash provided by operations. In August 2004, we replaced our previous 364-day and three-year credit facilities, which had a combined borrowing capacity of $1.05 billion, with a five-year senior unsecured revolving credit facility that has a borrowing capacity of $1.25 billion. Our five-year bank facility is due August 18, 2009, and can be used for general corporate purposes and as a backup for our commercial paper program. There were no borrowings under our credit facility as of December 31, 2004. After inclusion of our outstanding commercial paper borrowings and letters of credit, the remaining available borrowing capacity under our bank facility was $733.0 million as of December 31, 2004. For the year ended December 31, 2004, we continued to generate strong cash flow from operations, and we provided for additional liquidity by maintaining a sizable amount of excess borrowing capacity related to our commercial paper program and long-term revolving credit facility. As of December 31, 2004, our outstanding short-term debt was $621.2 million. We intended and had the ability to refinance all of our short-term debt on a long-term basis under our unsecured long-term credit facility. Accordingly, such amounts have been classified as long-term debt in our accompanying consolidated balance sheet. Currently, we believe our liquidity to be adequate. For more information on our credit facility, see Note 9 to our consolidated financial statements included elsewhere in this report. Long-term Financing Transactions Debt Financing 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 premiums. All of our outstanding debt securities are unsecured obligations that rank equally with all of our other senior debt obligations. A modest amount of secured debt has been incurred by some of our subsidiaries. Our 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. On November 12, 2004, we closed a public offering of $500 million in principal amount of 5.125% senior notes due November 15, 2014 at a price to the public of 99.914%. In the offering, we received proceeds, net of underwriting discounts and commissions, of approximately $496.3 million. We used the proceeds to reduce the then outstanding balance on our commercial paper borrowings. As of December 31, 2004, our total liability balance due on the various series of our senior notes was approximately $4,189.6 million. For more information on our senior notes, see Note 9 to our consolidated financial statements included elsewhere in this report. Equity Financing On February 9, 2004, we issued, in a public offering, an additional 5,300,000 of our common units at a price of $46.80 per unit, less commissions and underwriting expenses. After commissions and underwriting expenses, we received net proceeds of $237.8 million for the issuance of these common units. We used the proceeds to reduce the borrowings under our commercial paper program. On November 10, 2004, we issued, in a public offering, an additional 5,500,000 of our common units at a price of $46.00 per unit, less commissions and underwriting expenses. On December 8, 2004, we issued an additional 575,000 units upon the exercise by the underwriters of an over-allotment option. After commissions and underwriting expenses, we received net proceeds of $268.3 million for the issuance of these 6,075,000 common units. We used the proceeds to reduce the borrowings under our commercial paper program. On March 25, 2004, KMR issued an additional 360,664 of its shares at a price of $41.59 per share, less closing fees and commissions. The net proceeds from the offering were used to buy additional i-units from us. After 72 <PAGE> closing and commission expenses, we received net proceeds of $14.9 million for the issuance of 360,664 i-units. We used the proceeds from the i-unit issuance to reduce the borrowings under our commercial paper program. On November 10, 2004, KMR issued an additional 1,300,000 of its shares at a price of $41.29 per share, less closing fees and commissions. The net proceeds from the offering were used to buy additional i-units from us. We received proceeds of $52.6 million for the issuance of 1,300,000 i-units. We used the proceeds from the i-unit issuance to reduce the borrowings under our commercial paper program. Capital Requirements for Recent Transactions During 2004, our cash outlays for the acquisitions of assets and equity investments totaled $479.9 million. With the exception of our acquisition of TransColorado, which was partially acquired by the issuance of additional common units to KMI, we utilized our commercial paper program to fund these acquisitions and then reduced our short-term borrowings with the proceeds from our February and November 2004 issuances of common units, our March and November 2004 issuances of i-units, and our November 2004 issuance of long-term senior notes. We intend to refinance the remainder of our current short-term debt and any additional short-term debt incurred during 2005 through a combination of long-term debt, equity and the issuance of additional commercial paper to replace maturing commercial paper borrowings. In February 2005, a shelf registration statement became effective that will allow us to issue up to a total of $2 billion in debt and/or equity securities. We are committed to maintaining a cost effective capital structure and we intend to finance new acquisitions using a mix of approximately 60% equity financing and 40% debt financing. For more information on our capital requirements during 2004 in regard to our acquisition expenditures, see Note 3 to our consolidated financial statements included elsewhere in this report. Summary of Off Balance Sheet Arrangements We have invested in entities that are not consolidated in our financial statements. As of December 31, 2004, our obligations with respect to these investments, as well as our obligations with respect to a letter of credit, are summarized below (in millions): <TABLE> <CAPTION> Our Our Remaining Total Total Contingent Investment Ownership Interest(s) Entity Entity Share of Entity Type Interest Ownership Assets(4) Debt Entity Debt(5) - --------------------------------- ---------- --------- -------------- --------- ------ -------------- <S> <C> <C> <C> <C> <C> <C> General 50% (1) $114 $202 $101 (2) Cortez Pipeline Company........ Partner Red Cedar Gas Gathering General 49% Southern Ute $187 $47 $47 Company.................... Partner Indian Tribe Nassau County, N/A N/A Nassau County, N/A N/A $25 Florida Ocean Highway Florida Ocean and Port Authority (3)..... Highway and Port Authority </TABLE> - --------- (1) The remaining general partner interests are owned by ExxonMobil Cortez Pipeline, Inc., an indirect wholly-owned subsidiary of Exxon Mobil Corporation and Cortez Vickers Pipeline Company, an indirect subsidiary of M.E. Zuckerman Energy Investors Incorporated. (2) We are severally liable for our percentage ownership share of the Cortez Pipeline Company debt. Further, pursuant to a Throughput and Deficiency Agreement, the partners 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 partners of Cortez Pipeline to fund cash deficiencies at Cortez Pipeline, including anticipated deficiencies and cash deficiencies relating to the repayment of principal and interest on the debt of Cortez Capital Corporation. The partners' respective parent or other companies further severally guarantee the obligations of the Cortez Pipeline owners under this agreement. 73 <PAGE> (3) Arose from our Vopak terminal acquisition in July 2001. Nassau County, Florida Ocean Highway and Port Authority is a political subdivision of the State of Florida. During 1990, Ocean Highway and Port Authority issued its Adjustable Demand Revenue Bonds in the aggregate principal amount of $38.5 million for the purpose of constructing certain port improvements located in Fernandino Beach, Nassau County, Florida. A letter of credit was issued as security for the Adjustable Demand Revenue Bonds and was guaranteed by the parent company of Nassau Terminals LLC, the operator of the port facilities. In July 2002, we acquired Nassau Terminals LLC and became guarantor under the letter of credit agreement. In December 2002, we issued a $28 million letter of credit under our credit facilities and the former letter of credit guarantee was terminated. As of December 31, 2004, the value of this letter of credit outstanding under our credit facility was $25 million. Principal payments on the bonds are made on the first of December each year and reductions are made to the letter of credit. (4) Principally property, plant and equipment. (5) Represents the portion of the entity's debt that we may be responsible for if the entity cannot satisfy the obligation. We account for our investments in the Red Cedar Gas Gathering Company and Cortez Pipeline Company under the equity method of accounting. For the year ended December 31, 2004, our share of earnings, based on our ownership percentage, before income taxes and amortization of excess investment cost was $34.2 million from Cortez Pipeline Company, and $14.7 million from Red Cedar Gas Gathering Company. Additional information regarding the nature and business purpose of these investments is included in Notes 7 and 13 to our consolidated financial statements included elsewhere in this report. Summary of Certain Contractual Obligations <TABLE> <CAPTION> Amount of Commitment Expiration per Period --------------------------------------------------------------- 1 Year After 5 Total or Less 2-3 Years 4-5 Years Years ---------- -------- -------- -------- ---------- (In thousands) <S> <C> <C> <C> <C> <C> Contractual Obligations: Commercial paper outstanding...... $ 416,900 $416,900 $ -- $ -- $ -- Other debt borrowings(a) Principal payments............... 4,305,510 204,268 297,734 252,871 3,550,637 Interest payments................ 3,502,266 275,608 519,671 481,145 2,225,842 Lease obligations(b).............. 166,418 30,678 50,160 35,465 50,115 Postretirement welfare plans(c)... 1,800 300 600 600 300 Other obligations(d).............. 94,755 15,229 25,307 21,495 32,724 ---------- -------- -------- -------- ---------- Total............................. $8,487,649 $942,983 $893,472 $791,576 $5,859,618 ========== ======== ======== ======== ========== Other commercial commitments: Standby letters of credit(e)...... $ 162,586 $132,253 $ 30,333 $ -- $ -- ========== ======== ======== ======== ========== Capital expenditures(f)........... $ 13,788 $ 13,788 - - - ========== ======== ======== ======== ========== </TABLE> - ---------- (a) Debt obligations exclude adjustments for interest rate swap agreements. (b) Represents commitments for capital leases, including interest, and operating leases. (c) Represents expected annual contributions of $0.3 million per year based on calculations of independent enrolled actuary as of December 31, 2004. (d) Consist of payments due under carbon dioxide take-or-pay contracts, carbon dioxide removal contracts and natural gas liquids joint tariff agreements. (e) The $162.6 million in letters of credit outstanding as of December 31 2004 consisted of the following: (i) a $50 million letter of credit supporting our hedging of commodity price risks; (ii) our $30.3 million guarantee under letters of credit supporting our International Marine Terminals Partnership Plaquemines, Louisiana Port, Harbor, and Terminal Revenue Bonds; (iii) a $25.9 million letter of credit supporting Nassau County, Florida Ocean Highway and Port Authority tax-exempt bonds; (iv) a $25.4 million letter of credit supporting our Kinder Morgan Liquids Terminals LLC New Jersey Economic Development Revenue Bonds; (v) a $24.1 million letter of credit supporting our Kinder Morgan Operating L.P. "B" tax-exempt bonds; (vi) a $5.4 million letter of credit supporting our Arrow Terminals, L.P. Illinois Development 74 <PAGE> Revenue Bonds; and (vii) three letters of credit totaling $1.5 million, supporting workers' compensation insurance polices and equipment rental obligations. (f) Represents commitments for the purchase of plant, property and equipment as of December 31, 2004. In our 2005 sustaining capital expenditure plan, we have budgeted $125.8 million, primarily for the purchase of plant and equipment. Sustaining capital expenditures are defined as capital expenditures which do not increase the capacity of an asset. All of our capital expenditures, with the exception of sustaining capital expenditures, are discretionary. Operating Activities Net cash provided by operating activities was $1,155.1 million in 2004, versus $768.5 million in 2003. The $386.6 million (50%) period-to-period increase in 2004 compared to 2003 includes the following cash flow increases: o a $236.2 million increase in cash from overall higher partnership income in 2004, net of non-cash items including depreciation, depletion and amortization charges and undistributed earnings from equity investments; o a $141.7 million increase in cash inflows relative to net changes in working capital items; and o a $44.9 million increase related to transportation rate reparation and refund payments made in 2003. The higher partnership income reflects the increased level of segment earnings before depreciation, depletion and amortization reported in 2004 and discussed in "Results of Operations." The favorable inflows from working capital in 2004 were mainly related to timing differences in the payments made on our trade and related party account payables. In addition to timing differences, we made higher payments to settle related party payables at the beginning of 2003, primarily for reimbursements to KMI for costs related to the construction of our Mier-Monterrey natural gas pipeline and for general and administrative services. The reparation and refund payments made in 2003 were mandated under an order from the Federal Energy Regulatory Commission pursuant to a consolidated proceeding in FERC Docket OR92-8-000 concerning rates charged by our Pacific operations on certain interstate portions of their products pipelines. Offsetting the overall increase in cash provided by operating activities was a $17.8 million (21%) decrease in distributions received from equity investments and an $18.4 million decrease related to higher payments made in 2004 on non-current accounts, most notably, higher capitalizable project costs and higher cash settlements on long-term reserves and other deferred credits. The decrease in distributions from our equity investments was primarily due to lower distributions from our previous investment in MKM Partners, L.P. and our current investment in the Red Cedar Gas Gathering Company. MKM Partners, L.P. was dissolved on June 30, 2003, thereby eliminating our 15% equity ownership interest, and the decrease in distributions from our 49% equity ownership interest in Red Cedar related to its lower earnings in 2004 versus 2003. Investing Activities Net cash used in investing activities was $1,250.5 million for the year ended December 31, 2004, compared to $943.1 million for the prior year. The $307.4 million (33%) increase in funds utilized in investing activities was mainly attributable to higher payments made for capital expenditures, strategic acquisitions, and incremental purchases of natural gas liquids related to the initiation of our North System's line-fill program. Partially offsetting the overall increase in cash used in investing activities was a $7.0 million (50%) decrease in contributions to equity investments, mainly due to lower contributions made to Plantation Pipe Line Company. Including expansion and maintenance projects, our capital expenditures were $747.3 million in 2004 versus $577.0 million in 2003. The $170.3 million (30%) increase was mainly driven by higher capital investment in our Products Pipelines and CO2 business segments, as we continued to expand and grow our existing asset infrastructure 75 <PAGE> by adding both throughput capacity to our products pipelines and production and delivery capacity to our oil field and carbon dioxide flooding operations. Our sustaining capital expenditures were $119.2 million for 2004, compared to $92.8 million for 2003. Additionally, we continue to make significant investments in strategic acquisitions to fuel future growth and increase unitholder value. During 2004, our acquisition outlays for assets and investments totaled $479.9 million, a $120.0 million (33%) increase over the $359.9 million spent for acquisitions in 2003. Both our 2004 and 2003 acquistion expenditures are discussed more fully in Note 3 to our consolidated financial statements included elsewhere in this report. We also spent $23.0 million in 2004 pursuant to the implementation of our North System's natural gas liquids line-fill program, as discussed in "Results of Operations." The line-fill program calls for us to purchase natural gas liquids to be used as pipeline line-fill and pass the carrying costs on to our shippers through a cost of service filing with the FERC. As of December 31, 2004, we had purchased approximately 650,000 barrels of propane, normal butane and natural gasoline, which we believe will help mitigate the operational constraints that resulted from a lack of product supplies caused by shippers reducing their inventory levels at the close of the winter season. Financing Activities Net cash provided by financing activities was $72.1 million in 2004, compared to $156.8 million in 2003. The $84.7 million (54%) period-to-period decrease in cash provided by financing activities resulted primarily from lower cash inflows from overall debt financing activities and from higher partnership distributions. These overall decreases in cash provided by financing activities were partially offset by an increase in cash inflows from overall partnership equity issuances and an increase in temporary cash book overdrafts. During each of the years 2004 and 2003, we used our commercial paper borrowings to fund our asset acquisitions, capital expansion projects and other partnership activities, and we subsequently raised funds to refinance a portion of those borrowings by completing public offerings of senior notes and by issuing additional common units and i-units. We used the proceeds from these debt and equity issuances to reduce our borrowings under our commercial paper program. In 2004, we received $257.0 million from overall debt financing activities, which included both issuances and payments of debt, loans to related parties and debt issuance costs. In 2003, our debt financing activities provided us with $655.1 million in cash. The $398.1 million (61%) period-to-period net decrease was primarily due to the following: o a $215.4 million decrease in net incremental commercial paper borrowings in 2004 versus 2003; o an $87.9 million decrease related to payments, in 2004, to redeem and retire the principal amount of five series of tax-exempt bonds related to certain liquids terminal facilities. Pursuant to certain provisions that gave us the right to call and retire the bonds prior to maturity, we took advantage of the opportunity to refinance at lower rates; o a $96.3 million decrease related to a long-term loan we made to Plantation Pipe Line Company in 2004, which corresponded to our 51.17% ownership interest and allowed Plantation to pay all of its outstanding credit facility and commercial paper borrowings. In exchange, we received a seven year note receivable bearing interest at the rate of 4.72% per annum; o a $28.4 million decrease related to payments made to retire a significant portion of the $33.7 million of outstanding debt assumed as part of our October 2004 acquisition of Kinder Morgan River Terminals, LLC; o a $9.5 million decrease related to payments made to retire all of the outstanding debt assumed as part of our August 2004 acquisition of Kinder Morgan Wink Pipeline, L.P.; and o a $37.1 million increase related to payments made in December 2003 to retire the outstanding balance under SFPP, L.P.'s Series F notes. 76 <PAGE> In addition, in each of November 2004 and 2003, we closed public offerings of $500 million in principal amount of senior notes. The offerings resulted in cash inflows, net of discounts and issuing costs, of $496.3 million and $493.6 million, respectively. Cash distributions to all partners, consisting of our common and Class B unitholders (including KMI), our general partner, and minority interests, increased to $791.0 million in 2004 compared to $679.3 million in 2003. The $111.7 million (16%) increase in distributions was due to increases in the per unit cash distributions paid, the number of outstanding units and the resulting increase in our general partner incentive distributions. The $398.5 million period-to-period increase in cash inflows from additional partnership equity issuances was related to the excess of cash received from our 2004 issuances of both common and i-units over cash received from our June 2003 issuance of common units. In 2004, we received proceeds of $574.1 million from additional partnership equity issuances, primarily consisting of the following (amounts are net of all commissions and underwriting expenses): o $237.8 million received from our issuance of 5,300,000 common units in a February 2004 public offering; o $14.9 million received from our issuance of 360,664 i-units in March 2004 to KMR; o $268.3 million received from our issuance of 6,075,000 common units in a November 2004 public offering; and o $52.6 million received from our issuance of 1,300,000 i-units in November 2004 to KMR. By comparison, in 2003, we received net proceeds of $175.6 million from additional partnership equity issuances, mainly the result of $173.3 million received from the issuance of 4,600,000 of our common units in a June 2003 public offering. In both 2003 and 2004, we used the proceeds from each of these issuances to reduce the borrowings under our commercial paper program. The $29.9 million period-to-period increase in cash inflows from cash book overdrafts resulted from temporary increases in outstanding checks due to timing differences in the payments of year-end accruals and outstanding vendor invoices in 2004 versus 2003. We paid distributions of $2.81 per unit in 2004 compared to $2.575 per unit in 2003. The 9% increase in distributions paid per unit principally resulted from favorable operating results in 2004. We also distributed 3,500,512 and 3,342,417 i-units in quarterly distributions during 2004 and 2003, respectively, to KMR, our sole i-unitholder. The amount of i-units distributed in each quarter was based upon the amount of cash we distributed to the owners of our common and Class B units during that quarter of 2004 and 2003. For each outstanding i-unit that KMR held, a fraction of an i-unit was issued. The fraction was determined by dividing the cash amount distributed per common unit by the average of KMR's shares' closing market prices for the ten consecutive trading days preceding the date on which the shares began to trade ex-dividend under the rules of the New York Stock Exchange. Partnership Distributions Our partnership agreement requires that we distribute 100% of "Available Cash," as defined in our 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, including cash received by our operating partnerships and net reductions in reserves, less cash disbursements and net additions to reserves and amounts payable to the former general partner of SFPP, L.P. in respect of its remaining 0.5% interest in SFPP. Our general partner is granted discretion by our partnership agreement, which discretion has been delegated to KMR, subject to the approval of our general partner in certain cases, to establish, maintain and adjust reserves for future operating expenses, debt service, maintenance capital expenditures, rate refunds and distributions for the next four quarters. These reserves are not restricted by magnitude, but only by type of future cash requirements with 77 <PAGE> which they can be associated. When KMR determines our quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level. For 2004, 2003 and 2002, we distributed 87.0%, 100.4% and 97.6%, of the total of cash receipts less cash disbursements, respectively (calculations assume that KMR unitholders received cash). The difference between these numbers and 100% of distributable cash flow reflects net changes in reserves. Our general partner and owners of our common units and Class B units receive distributions in cash, while KMR, the sole owner of our i-units, receives distributions in additional i-units. We do not distribute cash to i-unit owners but retain the cash for use in our business. However, the cash equivalent of distributions of i-units is treated as if it had actually been distributed for purposes of determining the distributions to our general partner. Available cash is initially distributed 98% to our limited partners and 2% to our general partner. These distribution percentages are modified to provide for incentive distributions to be paid to our general partner in the event that quarterly distributions to unitholders exceed certain specified targets. Available cash for each quarter is distributed: o first, 98% to the owners of all classes of units pro rata and 2% to our general partner until the owners of all classes of units have received a total of $0.15125 per unit in cash or equivalent i-units for such quarter; o second, 85% of any available cash then remaining to the owners of all classes of units pro rata and 15% to our general partner until the owners of all classes of units have received a total of $0.17875 per unit in cash or equivalent i-units for such quarter; o third, 75% of any available cash then remaining to the owners of all classes of units pro rata and 25% to our general partner until the owners of all classes of units have received a total of $0.23375 per unit in cash or equivalent i-units for such quarter; and o fourth, 50% of any available cash then remaining to the owners of all classes of units pro rata, to owners of common units and Class B units in cash and to owners of i-units in the equivalent number of i-units, 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 value of cash and i-units being distributed. Our general partner's incentive distribution that we declared for 2004 was $390.7 million, while the incentive distribution paid to our general partner during 2004 was $370.5 million. The difference between declared and paid distributions is due to the fact that our distributions for the fourth quarter of each year are declared and paid in the first quarter of the following year. On February 14, 2005, we paid a quarterly distribution of $0.74 per unit for the fourth quarter of 2004. This distribution was 9% greater than the $0.68 distribution per unit we paid for the fourth quarter of 2003 and 7% greater than the $0.69 distribution per unit we paid for the first quarter of 2004. We paid this distribution in cash to our common unitholders and to our Class B unitholders. KMR, our sole i-unitholder, received additional i-units based on the $0.74 cash distribution per common unit. We believe that future operating results will continue to support similar levels of quarterly cash and i-unit distributions; however, no assurance can be given that future distributions will continue at such levels. Litigation and Environmental As of December 31, 2004, we have recorded a total reserve for environmental claims, without discounting and without regard to anticipated insurance recoveries, in the amount of $40.9 million. The reserve is primarily established to address and clean up soil and ground water impacts from former releases to the environment at facilities we have acquired. Reserves for each project are generally established by reviewing existing documents, conducting interviews and performing site inspections to determine the overall size and impact to the environment. Reviews are made on a quarterly basis to determine the status of the cleanup and the costs associated with the effort and to identify if the reserve allocation is appropriately valued. In assessing environmental risks in conjunction with proposed acquisitions, we review records relating to environmental issues, conduct site inspections, interview 78 <PAGE> employees, and, if appropriate, collect soil and groundwater samples. Please refer to Note 16 to our consolidated financial statements included elsewhere in this report for additional information on our pending environmental and litigation matters, respectively. We believe we have established adequate environmental and legal reserves such that the resolution of pending environmental matters and litigation will not have a material adverse impact on our business, cash flows, financial position or results of operations. However, changing circumstances could cause these matters to have a material adverse impact. Regulation The Pipeline Safety Improvement Act of 2002 requires pipeline companies to perform integrity tests on natural gas transmission pipelines that exist in high population density areas that are designated as High Consequence Areas. Pipeline companies are required to perform the integrity tests within ten years of December 17, 2002, the date of enactment, and must perform subsequent integrity tests on a seven year cycle. At least 50% of the highest risk segments must be tested within five years of the enactment date. The risk ratings are based on numerous factors, including the population density in the geographic regions served by a particular pipeline, as well as the age and condition of the pipeline and its protective coating. Testing will consist of hydrostatic testing, internal electronic testing, or direct assessment of the piping. A similar integrity management rule for refined petroleum products pipelines became effective May 29, 2001. All baseline assessments for products pipelines must be completed by March 31, 2008, and at least half of the line pipe affecting High Consequence Areas was required to be assessed by September 30, 2004. We have included all incremental expenditures estimated to occur during 2005 associated with the Pipeline Safety Improvement Act of 2002 and the integrity management of our products pipelines in our 2005 budget and capital expenditure plan. Please refer to Note 16 to our consolidated financial statements included elsewhere in this report for additional information regarding regulatory matters. Recent Accounting Pronouncements Please refer to Note 17 to our consolidated financial statements included elsewhere in this report for information concerning recent accounting pronouncements. Information Regarding Forward-Looking Statements This filing includes forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as "anticipate," "believe," "intend," "plan," "projection," "forecast," "strategy," "position," "continue," "estimate," "expect," "may," or the negative of those terms or other variations of them or comparable terminology. In particular, statements, express or implied, concerning future actions, conditions or events, future operating results or the ability to generate sales, income or cash flow or to make distributions are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors which could cause actual results to differ from those in the forward-looking statements include: o price trends and overall demand for natural gas liquids, refined petroleum products, oil, carbon dioxide, natural gas, coal and other bulk materials and chemicals in the United States; o economic activity, weather, alternative energy sources, conservation and technological advances that may affect price trends and demand; o changes in our tariff rates implemented by the Federal Energy Regulatory Commission or the California Public Utilities Commission; o our ability to acquire new businesses and assets and integrate those operations into our existing operations, as well as our ability to make expansions to our facilities; 79 <PAGE> o difficulties or delays experienced by railroads, barges, trucks, ships or pipelines in delivering products to or from our terminals or pipelines; o our ability to successfully identify and close acquisitions and make cost- saving changes in operations; o shut-downs or cutbacks at major refineries, petrochemical or chemical plants, ports, utilities, military bases or other businesses that use our services or provide services or products to us; o changes in laws or regulations, third-party relations and approvals, decisions of courts, regulators and governmental bodies that may adversely affect our business or our ability to compete; o our ability to offer and sell equity securities and debt securities or obtain debt financing in sufficient amounts to implement that portion of our business plan that contemplates growth through acquisitions of operating businesses and assets and expansions of our facilities; o our indebtedness could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds and/or place us at competitive disadvantages compared to our competitors that have less debt or have other adverse consequences; o interruptions of electric power supply to our facilities due to natural disasters, power shortages, strikes, riots, terrorism, war or other causes; o our ability to obtain insurance coverage without a significant level of self-retention of risk; o acts of nature, sabotage, terrorism or other similar acts causing damage greater than our insurance coverage limits; o capital markets conditions; o the political and economic stability of the oil producing nations of the world; o national, international, regional and local economic, competitive and regulatory conditions and developments; o the ability to achieve cost savings and revenue growth; o inflation; o interest rates; o the pace of deregulation of retail natural gas and electricity; o foreign exchange fluctuations; o the timing and extent of changes in commodity prices for oil, natural gas, electricity and certain agricultural products; o the extent of our success in discovering, developing and producing oil and gas reserves, including the risks inherent in exploration and development drilling, well completion and other development activities; o engineering and mechanical or technological difficulties with operational equipment, in well completions and workovers, and in drilling new wells; o the uncertainty inherent in estimating future oil and natural gas production or reserves; o the timing and success of business development efforts; and 80 <PAGE> o unfavorable results of litigation and the fruition of contingencies referred to in Note 16 to our consolidated financial statements included elsewhere in this report. You should not put undue reliance on any forward-looking statements. See Items 1 and 2 "Business and Properties--Risk Factors" for a more detailed description of these and other factors that may affect the forward-looking statements. When considering forward-looking statements, one should keep in mind the risk factors described in "Risk Factors" above. The risk factors could cause our actual results to differ materially from those contained in any forward-looking statement. We disclaim any obligation to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments. Item 7A. Quantitative and Qualitative Disclosures About Market Risk. Generally, our market risk sensitive instruments and positions have been determined to be "other than trading." Our exposure to market risk as discussed below includes forward-looking statements and represents an estimate of possible changes in fair value or future earnings that would occur assuming hypothetical future movements in interest rates or commodity prices. Our views on market risk are not necessarily indicative of actual results that may occur and do not represent the maximum possible gains and losses that may occur, since actual gains and losses will differ from those estimated, based on actual fluctuations in interest rates or commodity prices and the timing of transactions. Energy Financial Instruments We are exposed to commodity market risk and other external risks, such as weather-related risk, in the ordinary course of business. We take steps to limit our exposure to these risks in order to maintain a more stable and predictable earnings stream. Accordingly, we use energy financial instruments to reduce our risks associated with changes in the market price of natural gas, natural gas liquids, crude oil and carbon dioxide. To minimize the risks associated with changes in the market price of natural gas, natural gas liquids, crude oil and carbon dioxide, we use certain financial instruments for hedging purposes. These instruments include energy products traded on the New York Mercantile Exchange and over-the-counter markets, including, but not limited to, futures and options contracts, fixed-price swaps and basis swaps. While we enter into derivative transactions only with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that losses will result from counterparty credit risk in the future. The credit ratings of the primary parties from whom we purchase energy financial instruments are as follows: Credit Rating ------------- Morgan Stanley......................... A+ J. Aron & Company / Goldman Sachs...... A+ BNP Paribas............................ AA We account for our risk management derivative instruments under Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (after amendment by SFAS No. 137 and SFAS No. 138). As discussed above, our principal use of derivative financial instruments is to mitigate the market price risk associated with anticipated transactions for the purchase and sale of natural gas, natural gas liquids, crude oil and carbon dioxide. SFAS No. 133 allows these transactions 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. Our application of SFAS No. 133 has resulted in deferred net loss amounts of $457.3 million and $155.8 million being reported as "Accumulated other comprehensive loss" in our accompanying balance sheets as of December 31, 2004 and December 31, 2003, respectively. 81 <PAGE> We measure the risk of price changes in the natural gas, natural gas liquids, crude oil and carbon dioxide markets utilizing a value-at-risk model. Value-at-risk is a statistical measure of how much the mark-to-market value of a portfolio could change during a period of time, within a certain level of statistical confidence. We utilize a closed form model to evaluate risk on a daily basis. The value-at-risk computations utilize a confidence level of 97.7% for the resultant price movement and a holding period of one day chosen for the calculation. The confidence level used means that there is a 97.7% probability that the mark-to-market losses for a single day will not exceed the value-at-risk number presented. Financial instruments evaluated by the model include commodity futures and options contracts, fixed price swaps, basis swaps and over-the-counter options. For each of the years ended December 31, 2004 and 2003, value-at-risk reached a high of $8.6 million and $12.8 million, respectively, and a low of $2.4 million and $2.2 million, respectively. Value-at-risk as of December 31, 2004, was $8.6 million and averaged $5.1 million for 2004. Value-at-Risk as of December 31, 2003, was $6.2 million and averaged $5.2 million for 2003. 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. In addition, as discussed above, we enter into these derivatives solely for the purpose of mitigating the risks that accompany certain of our business activities and, therefore, the change in the market value of our portfolio of derivatives, with the exception of a minor amount of hedging inefficiency, is offset by changes in the value of the underlying physical transactions. For more information on our risk management activities, see Note 14 to our consolidated financial statements included elsewhere in this report. Interest Rate Risk The market risk inherent in our debt instruments and positions is the potential change arising from increases or decreases in interest rates as discussed below. We utilize both variable rate and fixed rate debt in our financing strategy. See Note 9 to our consolidated financial statements included elsewhere in this report for additional information related to our debt instruments. For fixed rate debt, changes in interest rates generally affect the fair value of the debt instrument, but not our earnings or cash flows. Conversely, for variable rate debt, changes in interest rates generally do not impact the fair value of the debt instrument, but may affect our future earnings and cash flows. We do not have an obligation to prepay fixed rate debt prior to maturity and, as a result, interest rate risk and changes in fair value should not have a significant impact on our fixed rate debt until we would be required to refinance such debt. As of December 31, 2004 and 2003, the carrying values of our long-term fixed rate debt were approximately $4,209.6 million and $3,801.7 million, respectively, compared to fair values of $4,626.9 million and $4,372.3 million, respectively. Fair values were determined using quoted market prices, where applicable, or future cash flow discounted at market rates for similar types of borrowing arrangements. A hypothetical 10% change in the average interest rates applicable to such debt for 2004 and 2003, respectively, would result in changes of approximately $161.0 million and $158.6 million, respectively, in the fair values of these instruments. The carrying value and fair value of our variable rate debt, including associated accrued interest and excluding market value of interest rate swaps, was $495.1 million as of December 31, 2004 and $493.0 million as of December 31, 2003. Fair value was determined using future cash flows discounted based on market rates for similar types of borrowing arrangements. A hypothetical 10% change in the average interest rate applicable to our variable rate debt, including adjustments for notional swap amounts as of December 31, 2004 and 2003, would result in changes of approximately $11.7 million and $10.9 million in our 2004 and 2003 annualized pre-tax earnings, respectively. As of December 31, 2004 and 2003, we were a party to interest rate swap agreements with notional principal amounts of $2.3 billion and $2.1 billion, respectively. We entered into these agreements for the purpose of hedging the interest rate risk associated with our fixed and variable rate debt obligations. A hypothetical 10% change in the average interest rates related to these swaps would not have a material effect on our annual pre-tax earnings in 2004 82 <PAGE> or 2003. We monitor our mix of fixed rate and variable rate debt obligations in light of changing market conditions and from time to time may alter that mix by, for example, refinancing balances outstanding under our variable rate debt with fixed rate debt (or vice versa) or by entering into interest rate swaps or other interest rate hedging agreements. In general, we attempt to maintain an overall target mix of approximately 50% fixed rate debt and 50% variable rate debt. As of December 31, 2004, our cash and investment portfolio did not include fixed-income securities. Due to the short-term nature of our investment portfolio, a hypothetical 10% increase in interest rates would not have a material effect on the fair market value of our portfolio. Since we have the ability to liquidate this portfolio, we do not expect our operating results or cash flows to be materially affected to any significant degree by the effect of a sudden change in market interest rates on our investment portfolio. Item 8. Financial Statements and Supplementary Data. The information required in this Item 8 is included in this report as set forth in the "Index to Financial Statements" on page 101. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. None. Item 9A. Controls and Procedures. Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures As of December 31, 2004, our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective in all material respects to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required. Management's Report on Internal Control Over Financial Reporting Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control - Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2004. Our management's assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included elsewhere in this report. 83 <PAGE> Certain businesses we acquired during 2004 were excluded from the scope of our management's assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004. These businesses excluded were North Charleston Bulk Terminal, Kinder Morgan Wink Pipeline, L.P., Kinder Morgan River Terminals LLC, Charter Products Terminals and Kinder Morgan Fairless Hills Terminal. These businesses, in the aggregate, constituted .04% of our consolidated revenues for 2004 and 2.75% of our consolidated assets at December 31, 2004. Changes in Internal Control Financial Reporting There has been no change in our internal control over financial reporting during the fourth quarter of 2004 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. Item 9B. Other Information. None. 84 <PAGE> PART III Item 10. Directors and Executive Officers of the Registrant. Directors and Executive Officers of our General Partner and the Delegate Set forth below is certain information concerning the directors and executive officers of our general partner and KMR, the delegate of our general partner. All directors of our general partner are elected annually by, and may be removed by, Kinder Morgan (Delaware), Inc. as its sole shareholder, and all directors of KMR are elected annually by, and may be removed by, our general partner as the sole holder of the delegate's voting shares. Kinder Morgan (Delaware), Inc. is a wholly owned subsidiary of KMI. All officers of the general partner and all officers of KMR serve at the discretion of the board of directors of our general partner. Name Age Position with our General Partner and the Delegate - ------------------ --- -------------------------------------------------- Richard D. Kinder....... 60 Director, Chairman, Chief Executive Officer and President C. Park Shaper.......... 36 Director, Executive Vice President and Chief Financial Officer Edward O. Gaylord....... 73 Director Gary L. Hultquist....... 61 Director Perry M. Waughtal....... 69 Director Thomas A. Bannigan...... 51 Vice President (President, Products Pipelines) Richard T. Bradley...... 49 Vice President (President, CO2) David D. Kinder......... 30 Vice President, Corporate Development Joseph Listengart....... 36 Vice President, General Counsel and Secretary Deborah A. Macdonald.... 53 Vice President (President, Natural Gas Pipelines) Jeffrey R. Armstrong.... 36 Vice President (President, Terminals) James E. Street......... 48 Vice President, Human Resources and Administration Richard D. Kinder is Director, Chairman, Chief Executive Officer and President of KMR, Kinder Morgan G.P., Inc. and KMI. Mr. Kinder has served as Director, Chairman and Chief Executive Officer of KMR since its formation in February 2001. He was elected Director, Chairman and Chief Executive Officer of KMI in October 1999. He was elected Director, Chairman and Chief Executive Officer of Kinder Morgan G.P., Inc. in February 1997. Mr. Kinder was elected President of KMR, Kinder Morgan G.P., Inc. and KMI in July 2004. Mr. Kinder is the uncle of David Kinder, Vice President, Corporate Development of KMR, Kinder Morgan G.P., Inc. and KMI. C. Park Shaper is Director, Executive Vice President and Chief Financial Officer of KMR and Kinder Morgan G.P., Inc. and Executive Vice President and Chief Financial Officer of KMI. Mr. Shaper was elected Executive Vice President of KMR, Kinder Morgan G.P., Inc. and KMI in July 2004, and was elected Director of KMR and Kinder Morgan G.P., Inc. in January 2003. He was elected Vice President, Treasurer and Chief Financial Officer of KMR upon its formation in February 2001, and served as Treasurer of KMR from February 2001 to January 2004. He was elected Vice President, Treasurer and Chief Financial Officer of KMI in January 2000, and served as Treasurer of KMI from January 2000 to January 2004. Mr. Shaper was elected Vice President, Treasurer and Chief Financial Officer of Kinder Morgan G.P., Inc. in January 2000, and served as Treasurer of Kinder Morgan G.P., Inc. from January 2000 to January 2004. He received a Masters in Business Administration degree from the J.L. Kellogg Graduate School of Management at Northwestern University. Mr. Shaper also has a Bachelor of Science degree in Industrial Engineering and a Bachelor of Arts degree in Quantitative Economics from Stanford University. Edward O. Gaylord is a Director of KMR and Kinder Morgan G.P., Inc. Mr. Gaylord was elected Director of KMR upon its formation in February 2001. Mr. Gaylord was elected Director of Kinder Morgan G.P., Inc. in February 1997. Since 1989, Mr. Gaylord has been the Chairman of the board of directors of Jacintoport Terminal Company, a liquid bulk storage terminal on the Houston, Texas ship channel. Gary L. Hultquist is a Director of KMR and Kinder Morgan G.P., Inc. Mr. Hultquist was elected Director of KMR upon its formation in February 2001. He was elected Director of Kinder Morgan G.P., Inc. in October 1999. Since 1995, Mr. Hultquist has been the Managing Director of Hultquist Capital, LLC, a San Francisco-based strategic and merger advisory firm. 85 <PAGE> Perry M. Waughtal is a Director of KMR and Kinder Morgan G.P., Inc. Mr. Waughtal was elected Director of KMR upon its formation in February 2001. Mr. Waughtal was elected Director of Kinder Morgan G.P., Inc. in April 2000. Since 1994, Mr. Waughtal has been the Chairman of Songy Partners Limited, an Atlanta, Georgia based real estate investment company. Mr. Waughtal is also a director of HealthTronics, Inc. Thomas A. Bannigan is Vice President (President, Products Pipelines) of KMR and Kinder Morgan G.P., Inc. and President and Chief Executive Officer of Plantation Pipe Line Company. Mr. Bannigan was elected Vice President (President, Products Pipelines) of KMR upon its formation in February 2001. He was elected Vice President (President, Products Pipelines) of Kinder Morgan G.P., Inc. in October 1999. Mr. Bannigan has served as President and Chief Executive Officer of Plantation Pipe Line Company since May 1998. Mr. Bannigan received his Juris Doctor, cum laude, from Loyola University in 1980 and received a Bachelors degree from the State University of New York in Buffalo. Richard T. Bradley is Vice President (President, CO2) of KMR and of Kinder Morgan G.P., Inc. and President of Kinder Morgan CO2 Company, L.P. Mr. Bradley was elected Vice President (President, CO2) of KMR upon its formation in February 2001 and Vice President (President, CO2) of Kinder Morgan G.P., Inc. in April 2000. Mr. Bradley has been President of Kinder Morgan CO2 Company, L.P. (formerly known as Shell CO2 Company, Ltd.) since March 1998. Mr. Bradley received a Bachelor of Science in Petroleum Engineering from the University of Missouri at Rolla. David D. Kinder is Vice President, Corporate Development of KMR, Kinder Morgan G.P., Inc. and KMI. Mr. Kinder was elected Vice President, Corporate Development of KMR, Kinder Morgan G.P., Inc. and KMI in October 2002. He served as manager of corporate development for KMI and Kinder Morgan G.P., Inc. from January 2000 to October 2002. Mr. Kinder graduated cum laude with a Bachelors degree in Finance from Texas Christian University in 1996. Mr. Kinder is the nephew of Richard D. Kinder. Joseph Listengart is Vice President, General Counsel and Secretary of KMR, Kinder Morgan G.P., Inc. and KMI. Mr. Listengart was elected Vice President, General Counsel and Secretary of KMR upon its formation in February 2001. He was elected Vice President and General Counsel of Kinder Morgan G.P., Inc. and Vice President, General Counsel and Secretary of KMI in October 1999. Mr. Listengart was elected Secretary of Kinder Morgan G.P., Inc. in November 1998 and has been an employee of Kinder Morgan G.P., Inc. since March 1998. Mr. Listengart received his Masters in Business Administration from Boston University in January 1995, his Juris Doctor, magna cum laude, from Boston University in May 1994, and his Bachelor of Arts degree in Economics from Stanford University in June 1990. Deborah A. Macdonald is Vice President (President, Natural Gas Pipelines) of KMR, Kinder Morgan G.P., Inc. and KMI. She was elected as Vice President (President, Natural Gas Pipelines) of KMR, Kinder Morgan G.P., Inc. and KMI in June 2002. Ms. Macdonald served as President of Natural Gas Pipeline Company of America from October 1999 to March 2003. Ms. Macdonald received her Juris Doctor, summa cum laude, from Creighton University in May 1980 and received a Bachelors degree, magna cum laude, from Creighton University in December 1972. Jeffrey R. Armstrong is Vice President (President, Terminals) of KMR and Kinder Morgan G.P., Inc. Mr. Armstrong became Vice President (President, Terminals) in July 2003. He served as President, Kinder Morgan Liquids Terminals LLC from March 1, 2001, when the company was formed via the acquisition of GATX Terminals, through July 2003. From 1994 to 2001, Mr. Armstrong worked for GATX Terminals, where he was General Manager of their East Coast operations. He received his bachelor's degree from the United States Merchant Marine Academy and an MBA from the University of Notre Dame. James E. Street is Vice President, Human Resources and Administration of KMR, Kinder Morgan G.P., Inc. and KMI. Mr. Street was elected Vice President, Human Resources and Administration of KMR upon its formation in February 2001. He was elected Vice President, Human Resources and Administration of Kinder Morgan G.P., Inc. and KMI in August 1999. Mr. Street received a Masters of Business Administration degree from the University of Nebraska at Omaha and a Bachelor of Science degree from the University of Nebraska at Kearney. 86 <PAGE> Corporate Governance Our limited partnership agreement provides for us to have a general partner rather than a board of directors. Pursuant to a delegation of control agreement, our general partner delegated to KMR, to the fullest extent permitted under Delaware law and our partnership agreement, all of its power and authority to manage and control our business and affairs, except that KMR cannot take certain specified actions without the approval of our general partner. Through the operation of that agreement and our partnership agreement, KMR manages and controls our business and affairs, and the board of directors of KMR performs the functions of and acts as our board of directors. Similarly, the standing committees of KMR's board of directors function as standing committees of our board. KMR's board of directors is comprised of the same persons who comprise our general partner's board of directors. References in this report to the board mean KMR's board, acting as our board of directors, and references to committees mean KMR's committees, acting as committees of our board of directors. The board has adopted governance guidelines for the board and charters for the audit committee, nominating and governance committee and compensation committee. The governance guidelines and the rules of the New York Stock Exchange require that a majority of the directors be independent, as described in those guidelines and rules respectively. To assist in making determinations of independence, the board has determined that the following categories of relationships are not material relationships that would cause the affected director not to be independent: o If the director was an employee, or had an immediate family member who was an executive officer, of KMR or us or any of its or our affiliates, but the employment relationship ended more than three years prior to the date of determination (or, in the case of employment of a director as an interim chairman, interim chief executive officer or interim executive officer, such employment relationship ended by the date of determination); o If during any twelve month period within the three years prior to the determination the director received no more than, and has no immediate family member that received more than, $100,000 in direct compensation from us or our affiliates, other than (i) director and committee fees and pension or other forms of deferred compensation for prior service (provided such compensation is not contingent in any way on continued service), (ii) compensation received by a director for former service as an interim chairman, interim chief executive officer or interim executive officer, and (iii) compensation received by an immediate family member for service as an employee (other than an executive officer); o If the director is at the date of determination a current employee, or has an immediate family member that is at the date of determination a current executive officer, of another company that has made payments to, or received payments from, us and our affiliates for property or services in an amount which, in each of the three fiscal years prior to the date of determination, was less than the greater of $1.0 million or 2% of such other company's annual consolidated gross revenues. Contributions to tax-exempt organizations are not considered payments for purposes of this determination; o If the director is also a director, but is not an employee or executive officer, of our general partner or another affiliate or affiliates of KMR or us, so long as such director is otherwise independent; and o If the director beneficially owns less than 10% of each class of voting securities of us, our general partner, KMR or Kinder Morgan, Inc. The board has affirmatively determined that Messrs. Gaylord, Hultquist and Waughtal, who constitute a majority of the directors, are independent as described in our governance guidelines and the New York Stock Exchange rules. Each of them meets the standards above and has no other relationship with us. In conjunction with regular quarterly and special board meetings, these three non-management directors also meet in executive session without members of management. In December 2004, Mr. Gaylord was elected for a one year term to serve as lead director to develop the agendas for and moderate these executive sessions of independent directors. We have a separately designated standing audit committee established in accordance with Section 3(a)(58)(A) of the Securities Exchange Act of 1934 comprised of Messrs. Gaylord, Hultquist and Waughtal. Mr. Waughtal is the chairman of the audit committee and has been determined by the board to be an "audit committee financial expert." 87 <PAGE> The governance guidelines and our audit committee charter, as well as the rules of the New York Stock Exchange and the Securities and Exchange Commission, require that members of the audit committee satisfy independence requirements in addition to those above. The board has determined that all of the members of the audit committee are independent as described under the relevant standards. We have not, nor has our general partner nor KMR made, within the preceding three years, contributions to any tax-exempt organization in which any of our or KMR's independent directors serves as an executive officer that in any single fiscal year exceeded the greater of $1 million or 2% of such tax-exempt organization's consolidated gross revenues. On September 3, 2004, our chief executive officer certified to the New York Stock Exchange, as required by Section 303A.12(a) of the New York Stock Exchange Listed Company Manual, that as of September 3, 2004, he was not aware of any violation by us of the New York Stock Exchange's Corporate Governance listing standards. We have also filed as an exhibit to this report the Sarbanes-Oxley Act Section 302 certifications regarding the quality of our public disclosure. We make available free of charge within the "Investors" information section of our Internet website, at www.kindermorgan.com, and in print to any unitholder who requests, the governance guidelines, the charters of the audit committee, compensation committee and nominating and governance committee, and our code of business conduct and ethics (which applies to senior financial and accounting officers and the chief executive officer, among others). Requests for copies may be directed to Investor Relations, Kinder Morgan Energy Partners, L.P., 500 Dallas Street, Suite 1000, Houston, Texas 77002, or telephone (713) 369-9490. We intend to disclose any amendments to our code of business conduct and ethics that would otherwise be disclosed on Form 8-K and any waiver from a provision of that code granted to our executive officers or directors that would otherwise be disclosed on Form 8-K on our Internet website within five business days following such amendment or waiver. The information contained on or connected to our Internet website is not incorporated by reference into this Form 10-K and should not be considered part of this or any other report that we file with or furnish to the SEC. You may contact our lead director, the chairpersons of any of the board's committees, the independent directors as a group or the full board by mail to Kinder Morgan Management, LLC, 500 Dallas Street, Suite 1000, Houston, Texas 77002, Attention: General Counsel, or by e-mail within the "Contact Us" section of our Internet website, at www.kindermorgan.com. Your communication should specify the intended recipient. Section 16(a) Beneficial Ownership Reporting Compliance Section 16 of the Securities Exchange Act of 1934 requires our directors and officers, and persons who own more than 10% of a registered class of our equity securities, to file initial reports of ownership and reports of changes in ownership with the Securities and Exchange Commission. Such persons are required by SEC regulation to furnish us with copies of all Section 16(a) forms they file. Based solely on our review of the copies of such forms furnished to us and written representations from our executive officers and directors, we believe that all Section 16(a) filing requirements were met during 2004. Item 11. Executive Compensation. As is commonly the case for publicly traded limited partnerships, we have no officers. Under our limited partnership agreement, Kinder Morgan G.P., Inc., as our general partner, is to direct, control and manage all of our activities. Pursuant to a delegation of control agreement, Kinder Morgan G.P., Inc. has delegated to KMR the management and control of our business and affairs to the maximum extent permitted by our partnership agreement and Delaware law, subject to our general partner's right to approve certain actions by KMR. The executive officers and directors of Kinder Morgan G.P., Inc. serve in the same capacities for KMR. Certain of those executive officers, including all of the named officers below, also serve as executive officers of KMI. All information in this report with respect to compensation of executive officers describes the total compensation received by those persons in all capacities for Kinder Morgan G.P., Inc., KMR, KMI and their respective affiliates. 88 <PAGE> <TABLE> <CAPTION> Summary Compensation Table Long-Term Compensation Awards Annual Compensation ----------------------- ------------------------------- Restricted KMI Shares Stock Underlying All Other Name and Principal Position Year Salary Bonus(1) Awards(2) Options Compensation(3) - ----------------------------- --------- --------- ---------- ------------ ---------- --------------- <S> <C> <C> <C> <C> <C> <C> Richard D. Kinder........... 2004 $ 1 $ -- $ -- -- $ -- Director, Chairman , CEO 2003 1 -- -- -- -- and President 2002 1 -- -- -- -- C. Park Shaper.............. 2004 200,000 975,000 -- -- 8,378 Director, Executive Vice 2003 200,000 875,000 5,918,000 -- 8,378 President and CFO 2002 200,000 950,000 -- 100,000(4) 8,336 Deborah A. Macdonald........ 2004 200,000 975,000 -- -- 8,966 Vice President (President, 2003 200,000 875,000 5,380,000 -- 8,966 Natural Gas Pipelines) 2002 200,000 950,000 -- 50,000(5) 8,966 Joseph Listengart........... 2004 200,000 875,000 -- -- 8,378 Vice President, 2003 200,000 825,000 3,766,000 -- 8,378 General Counsel and 2002 200,000 950,000 -- -- 8,336 Secretary Richard T. Bradley.......... 2004 200,000 560,000 -- -- 8,630 Vice President (President, 2003 200,000 525,000 2,152,000 -- 8,606 CO2) 2002 200,000 500,000 -- -- 8,606 </TABLE> - ---------- (1) Amounts earned in year shown but paid the following year. (2) Represent shares of restricted KMI stock awarded in 2003. The awards were issued under a shareholder approved plan. For the 2003 awards, value computed as the number of shares awarded times the closing price on date of grant ($53.80 at July 16, 2003). Twenty-five percent of the shares in each grant vest on the third anniversary after the date of grant and the remaining seventy-five percent of the shares in each grant vest on the fifth anniversary after the date of grant. To vest, we and/or KMI must also achieve one of the following performance hurdles during the vesting period: (i) KMI must earn $3.70 per share in any fiscal year; (ii) we must distribute $2.72 over four consecutive quarters; (iii) we and KMI must fund at least one year's annual incentive program; or (iv) KMI's stock price must average over $60.00 per share during any consecutive 30-day period. All of these hurdles have been met. The 2003 awards were long-term equity compensation for our current senior management through July 2008, and neither we nor KMI intend to make further restricted stock awards or other long-term equity grants to them before that date. The holders of the restricted stock awards are eligible to vote and to receive dividends declared on such shares. (3) Amounts represent value of contributions to the Kinder Morgan Savings Plan (a 401(k) plan), value of group-term life insurance exceeding $50,000 and taxable parking subsidy. (4) The 100,000 options to purchase KMI shares were granted on January 16, 2002 with an exercise price of $56.99 per share and vest at the rate of twenty-five percent on each of the first four anniversaries after the date of grant. (5) The 50,000 options to purchase KMI shares were granted on January 16, 2002 with an exercise price of $56.99 per share and vest at the rate of twenty-five percent on each of the first four anniversaries after the date of grant. Kinder Morgan Savings Plan. The Kinder Morgan Savings Plan is a defined contribution 401(k) plan. The plan permits all full-time employees of Kinder Morgan, Inc. and KMGP Services Company, Inc. to contribute between 1% and 50% of base compensation, on a pre-tax basis, into participant accounts. In addition to a mandatory contribution equal to 4% of base compensation per year for most plan participants, our general partner may make discretionary contributions in years when specific performance objectives are met. Certain employees' contributions are based on collective bargaining agreements. The 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 employer 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. During the first quarter of 2005, we will not make any discretionary contributions to individual accounts for 2004. 89 <PAGE> For employees hired on or prior to December 31, 2004, all contributions, together with earnings thereon, are immediately vested and not subject to forfeiture. Employer contributions for employees hired on or after January 1, 2005 will vest on the second anniversary of the date of hire. Participants may direct the investment of their contributions into a variety of investments. Plan assets are held and distributed pursuant to a trust agreement. Because levels of future compensation, participant contributions and investment yields cannot be reliably predicted over the span of time contemplated by a plan of this nature, it is impractical to estimate the annual benefits payable at retirement to the individuals listed in the Summary Compensation Table above. At its July 2004 meeting, the compensation committee of the KMI board of directors approved that contingent upon its approval at its July 2005 meeting, each eligible employee will receive an additional 1% company contribution based on eligible base pay to his or her Savings Plan account each pay period beginning with the first pay period after the July 2005 Committee meeting. The 1% contribution will be in the form of KMI common stock (the same as the current 4% contribution). The 1% contribution will be in addition to, and does not change or otherwise impact, the annual 4% contribution that eligible employees currently receive. It may be converted to any other Savings Plan investment fund at any time and it will vest on the second anniversary of the employee's date of hire. Since this additional 1% company contribution is discretionary, compensation committee approval will be required annually for each contribution. Common Unit Option Plan. Pursuant to our Common Unit Option Plan, key personnel are eligible to receive grants of options to acquire common units. The total number of common units authorized under the option plan is 500,000. None of the options granted under the option plan may be "incentive stock options" under Section 422 of the Internal Revenue Code. If an option expires without being exercised, the number of common units covered by such option will be available for a future award. The exercise price for an option may not be less than the fair market value of a common unit on the date of grant. KMR's compensation committee administers the option plan, and the plan has a termination date of March 5, 2008. No individual employee may be granted options for more than 20,000 common units in any year. KMR's compensation committee will determine the duration and vesting of the options to employees at the time of grant. As of December 31, 2004, options to purchase 95,400 common units are currently outstanding and held by 30 former Kinder Morgan G.P., Inc. employees who are now employees of Kinder Morgan, Inc. or KMGP Services Company, Inc. Forty percent of such options will vest on the first anniversary of the date of grant and twenty percent on each of the next three anniversaries. The options expire seven years from the date of grant. As of December 31, 2004, all 95,400 outstanding options were fully vested. The option plan also granted to each of our non-employee directors an option to purchase 10,000 common units at an exercise price equal to the fair market value of the common units at the end of the trading day on such date. Under this provision, as of December 31, 2004, options to purchase 20,000 common units are currently outstanding and held by two of Kinder Morgan G.P., Inc.'s three non-employee directors. Forty percent of all such options will vest on the first anniversary of the date of grant and twenty percent on each of the next three anniversaries. The non-employee director options will expire seven years from the date of grant. As of December 31, 2004, all 20,000 outstanding options were fully vested. No options to purchase common units were granted during 2004 to any of the individuals named in the Summary Compensation Table above. The following table sets forth certain information as of December 31, 2004 and for the fiscal year then ended with respect to common unit options previously granted to the individuals named in the Summary Compensation Table above. Mr. Listengart is the only person named in the Summary Compensation Table who was granted common unit options. No common unit options were granted at an option price below the fair market value on the date of grant. <TABLE> <CAPTION> Aggregated Common Unit Option Exercises in 2004 and 2004 Year-End Common Unit Option Values Number of Units Value of Unexercised Underlying Unexercised In-the-Money Options Units Acquired Value Options at 2004 Year-End At 2004 Year-End --------------------------- ---------------------------- Name on Exercise Realized Exercisable Unexercisable Exercisable Unexercisable - ------------------ -------------- ---------- ------------- -------------- -------------- -------------- <S> <C> <C> <C> <C> <C> <C> Joseph Listengart.... 10,000 $ 283,667 -- -- -- -- </TABLE> 90 <PAGE> KMI Stock Plan. Under KMI's stock plan, employees of KMI and its affiliates, including employees of KMI's direct and indirect subsidiaries, like KMGP Services Company, Inc., are eligible to receive grants of restricted KMI stock and grants of options to acquire shares of common stock of KMI. The compensation committee of KMI's board of directors administers this plan. The primary purpose for granting restricted KMI stock and KMI stock options under this plan to employees of KMI, KMGP Services Company, Inc. and our subsidiaries is to provide them with an incentive to increase the value of the common stock of KMI. A secondary purpose of the grants is to provide compensation to those employees for services rendered to our subsidiaries and us. During 2004, none of the persons named in the Summary Compensation Table above were granted KMI stock options. <TABLE> <CAPTION> Number of Shares Value of Unexercised Underlying Unexercised In-the-Money Options Options at 2004 Year-End at 2004 Year-End(1) Shares Acquired Value --------------------------- ---------------------------- Name on Exercise Realized Exercisable Unexercisable Exercisable Unexercisable - -------------------- --------------- ---------- --------------------------- ----------- ------------- <S> <C> <C> <C> <C> <C> <C> C. Park Shaper.............. - $ - 170,000 50,000 $5,984,475 $807,000 Deborah A. Macdonald........ 50,000 $1,900,674 25,000 25,000 $ 403,500 $403,500 Joseph Listengart........... 50,000 $1,843,154 56,300 - $2,612,382 - Richard T. Bradley.......... 40,000 $1,284,830 25,000 - $1,057,938 - </TABLE> - ---------- (1) Calculated on the basis of the fair market value of the underlying shares at year-end, minus the exercise price. Cash Balance Retirement Plan. Employees of KMGP Services Company, Inc. and KMI are also eligible to participate in a Cash Balance Retirement Plan. Certain employees continue to accrue benefits through a career-pay formula, "grandfathered" according to age and years of service on December 31, 2000, or collective bargaining arrangements. All other employees accrue benefits through a personal retirement account in the Cash Balance Retirement Plan. Employees with prior service and not grandfathered converted to the Cash Balance Retirement Plan on January 1, 2001, and were credited with the current fair value of any benefits they had previously accrued through the defined benefit plan. Under the plan, we make contributions on behalf of participating employees equal to 3% of eligible compensation every pay period. In addition, discretionary contributions are made to the plan based on our and KMI's performance. No discretionary contributions were made for 2004 performance. Interest is credited to the personal retirement accounts at the 30-year U.S. Treasury bond rate, or an approved substitute, in effect each year. Employees become fully vested in the plan after five years, and they may take a lump sum distribution upon termination of employment or retirement. The following table sets forth the estimated annual benefits payable as of December 31, 2004, under normal retirement at age sixty-five, assuming current remuneration levels without any salary projection, and participation until normal retirement at age sixty-five, with respect to the named executive officers under the provisions of the Kinder Morgan Cash Balance Retirement Plan. These benefits are subject to federal and state income taxes, where applicable, but are not subject to deduction for social security or other offset amounts. <TABLE> <CAPTION> Estimated Current Estimated Current Credited Yrs Compensation Annual Benefit Credited Yrs of Service Age as of Covered by Payable Upon Name Of Service at Age 65 Jan. 1, 2005 Plans Retirement (1) ---- ------------ ------------ ------------ ------------ -------------- <S> <C> <C> <C> <C> <C> Richard D. Kinder......... 4 8.8 60.2 $ 1 $ - C. Park Shaper............ 4 32.7 36.4 200,000 62,363 Joseph Listengart......... 4 32.5 36.6 200,000 61,608 Deborah A. Macdonald...... 4 15.9 53.1 200,000 15,763 Richard T. Bradley........ 4 19.8 49.2 200,000 22,727 </TABLE> - ---------- (1) The estimated annual benefits payable are based on the straight-life annuity form. 91 <PAGE> 2000 Annual Incentive Plan. Effective January 20, 2000, KMI established the 2000 Annual Incentive Plan of Kinder Morgan, Inc. The plan was established, in part, to enable the portion of an officer's or other employee's annual bonus based on objective performance criteria to qualify as "qualified performance- based compensation" under the Internal Revenue Code. "Qualified performance- based compensation" compensation is deductible for tax purposes. The plan permits annual bonuses to be paid to KMI's officers and other employees and employees of KMI's subsidiaries based on their individual performance, KMI's performance and the performance of KMI's subsidiaries. The plan is administered by the compensation committee of KMI's board of directors. Under the plan, at or before the start of each calendar year, the compensation committee establishes written performance objectives. The performance objectives are based on one or more criteria set forth in the plan. The compensation committee may specify a minimum acceptable level of achievement of each performance objective below which no bonus is payable with respect to that objective. The maximum payout to any individual under the plan in any year is $1.5 million, and the compensation committee has the discretion to reduce the bonus amount in any performance period. The cash bonuses set forth in the Summary Compensation Table above were paid under the plan. Awards may be granted under the plan for calendar years 2000 through 2005. Compensation Committee Interlocks and Insider Participation. As disclosed above, the compensation committee of KMR functions as our compensation committee. KMR's compensation committee, comprised of Mr. Edward O. Gaylord, Mr. Gary L. Hultquist and Mr. Perry M. Waughtal, makes compensation decisions regarding the executive officers of our general partner and its delegate, KMR. Mr. Richard D. Kinder and Mr. James E. Street, who are executive officers of KMR, participate in the deliberations of the KMR compensation committee concerning executive officer compensation. Mr. Kinder receives $1.00 annually in total compensation for services to KMI, KMR and our general partner. Directors Fees. Our Directors' Unit Appreciation Rights Plan, as discussed below, served as partial compensation for non-employee directors for 2004. In addition to the awards provided by this plan, each non-employee director received additional compensation of $10,000 in 2004, paid $2,500 per quarter. Mr. Edward O. Gaylord, as chairman of the KMR audit committee, received additional compensation in the amount of $10,000, paid $2,500 per quarter. Mr. Perry M. Waughtal, appointed as lead director in October 2003 by KMR and who served as lead director until December 2004, received additional compensation in the amount of $25,000, paid $10,000 in the first quarter and $5,000 in each of the last three quarters. In addition, directors are reimbursed for reasonable expenses in connection with board meetings. In January 2005, KMR terminated the Directors' Unit Appreciation Rights Plan and implemented the Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors, as discussed below, to compensate non-employee directors for 2005. Directors' Unit Appreciation Rights Plan. On April 1, 2003, KMR's compensation committee established our Directors' Unit Appreciation Rights Plan. Pursuant to this plan, each of KMR's three non-employee directors was eligible to receive common unit appreciation rights. Upon the exercise of unit appreciation rights, we will pay, within thirty days of the exercise date, the participant an amount of cash equal to the excess, if any, of the aggregate fair market value of the unit appreciation rights exercised as of the exercise date over the aggregate award price of the rights exercised. The fair market value of one unit appreciation right as of the exercise date will be equal to the closing price of one common unit on the New York Stock Exchange on that date. The award price of one unit appreciation right will be equal to the closing price of one common unit on the New York Stock Exchange on the date of grant. Proceeds, if any, from the exercise of a unit appreciation right granted under the plan will be payable only in cash (that is, no exercise will result in the issuance of additional common units) and will be evidenced by a unit appreciation rights agreement. All unit appreciation rights granted vest on the six-month anniversary of the date of grant. If a unit appreciation right is not exercised in the ten year period following the date of grant, the unit appreciation right will expire and not be exercisable after the end of such period. In addition, if a participant ceases to serve on the board for any reason prior to the vesting date of a unit appreciation right, such unit appreciation right will immediately expire on the date of cessation of service and may not be exercised. 92 <PAGE> On April 1, 2003, the date of adoption of the plan, each of KMR's three non-employee directors were granted 7,500 unit appreciation rights. In addition, 10,000 unit appreciation rights were granted to each of KMR's three non-employee directors on January 21, 2004, at the first meeting of the board in 2004. As of December 31, 2004, 52,500 unit appreciation rights had been granted. No unit appreciation rights were exercised during 2004. During the first board meeting of 2005, the plan was terminated and replaced by the Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors; however, all unexercised awards made under the plan remain outstanding. Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors. On January 18, 2005, KMR's compensation committee established the Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan to compensate KMR's non-employee directors for 2005. The plan is administered by KMR's compensation committee and KMR's board has sole discretion to terminate the plan at any time. The primary purpose of this plan was to promote our interests and the interests of our unitholders by aligning the compensation of the non-employee members of the board of directors of KMR with unitholders' interests. Further, since KMR's success is dependent on its operation and management of our business and our resulting performance, the plan is expected to align the compensation of the non-employee members of the board with the interests of KMR's shareholders. The plan recognizes that the compensation to be paid to each non-employee director is fixed by the KMR board, generally annually, and that the compensation is expected to include an annual retainer payable in cash and other cash compensation. Pursuant to the plan, in lieu of receiving the other cash compensation, each non-employee director may elect to receive common units. Each election shall be generally at or around the first board meeting in January of each calendar year and will be effective for the entire calendar year. The initial election under this plan was made effective January 20, 2005. A non-employee director may make a new election each calendar year. The total number of common units authorized under this compensation plan is 100,000. Each annual election shall be evidenced by an agreement, the Common Unit Compensation Agreement, between us and each non-employee director, and this agreement will contain the terms and conditions of each award. Pursuant to this agreement, all common units issued under this plan are subject to forfeiture restrictions that expire six months from the date of issuance. Until the forfeiture restrictions lapse, common units issued under the plan may not be sold, assigned, transferred, exchanged, or pledged by a non-employee director. In the event the director's service as a director of KMR is terminated prior to the lapse of the forfeiture restriction either for cause, or voluntary resignation, each director shall, for no consideration, forfeit to us all common units to the extent then subject to the forfeiture restrictions. Common units with respect to which forfeiture restrictions have lapsed shall cease to be subject to any forfeiture restrictions, and we will provide each director a certificate representing the units as to which the forfeiture restrictions have lapsed. In addition, each non-employee director shall have the right to receive distributions with respect to the common units awarded to him under the plan, to vote such common units and to enjoy all other unitholder rights, including during the period prior to the lapse of the forfeiture restrictions. The number of common units to be issued to a non-employee director electing to receive the other cash compensation in the form of common units will equal such other cash compensation awarded, divided by the closing price of the common units on the New York Stock Exchange on the day the cash compensation is awarded (such price, the fair market value), rounded down to the nearest 50 common units. The common units will be issuable as specified in the Common Unit Compensation Agreement. A non-employee director electing to receive the other cash compensation in the form of common units will receive cash equal to the difference between (i) the other cash compensation awarded to such non-employee director and (ii) the number of common units to be issued to such non-employee director multiplied by the fair market value of a common unit. This cash payment shall be payable in four equal installments (together with the annual cash retainer) generally around March 31, June 30, September 30 and December 31 of the calendar year in which such cash compensation is awarded. On January 18, 2005, the date of adoption of the plan, each of KMR's three non-employee directors was awarded a cash retainer of $40,000 that will be paid quarterly during 2005, and other cash compensation of $79,750. Effective January 20, 2005, each non-employe director elected to receive the other cash compensation of $79,750 in the form of our common units and was issued 1,750 common units pursuant to the plan and its agreements (based on the $45.55 closing market price of our common units on January 18, 2005, as reported on the New York Stock Exchange). Also, consistent with the plan, the $37.50 of other cash compensation that did not equate to a whole 93 <PAGE> common unit, based on the January 18, 2005 $45.55 closing price, will be paid to each of the non-employee directors as described above. No other compensation is to be paid to the non-employee directors during 2005. Item 12. Security Ownership of Certain Beneficial Owners and Management. The following table sets forth information as of January 31, 2005, regarding (a) the beneficial ownership of (i) our common and Class B units, (ii) the common stock of KMI, the parent company of our general partner, and (iii) KMR shares by all directors of our general partner and KMR, its delegate, by each of the named executive officers and by all directors and executive officers as a group and (b) the beneficial ownership of our common and Class B units or shares of KMR by all persons known by our general partner to own beneficially more than 5% of our common and Class B units and KMR shares. Unless otherwise noted, the address of each person below is c/o Kinder Morgan Energy Partners, L.P., 500 Dallas Street, Suite 1000, Houston, Texas 77002. <TABLE> <CAPTION> Kinder Morgan Common Units Class B Units Management Shares KMI Voting Stock ---------------------- --------------------- --------------------- ----------------------- Number Percent Number Percent Number Percent Number Percent of Units(2) of Class Of Units(3) of Class of Shares(4) of Class of Shares(5) of Class ----------- -------- ----------- -------- ------------ -------- ------------ -------- <S> <C> <C> <C> <C> <C> <C> <C> <C> <C> Richard D. Kinder(6)........... 315,979 * -- -- 47,379 * 23,995,415 19.45% C. Park Shaper(7).............. 4,000 * -- -- 2,534 * 326,808 * Edward O. Gaylord(8)........... 34,750 * -- -- -- -- 2,000 * Gary L. Hultquist(9)........... 11,750 * -- -- -- -- -- -- Perry M. Waughtal(10).......... 39,050 * -- -- 37,594 * 50,000 * Joseph Listengart(11).......... 4,198 * -- -- -- -- 140,106 * Deborah A. Macdonald(12)....... -- -- -- -- -- -- 121,374 * Richard T. Bradley(13)......... -- -- -- -- -- -- 71,314 * Directors and Executive Officers as a group (12 persons)(14). 427,006 * -- -- 90,607 * 25,033,714 20.29% Kinder Morgan, Inc.(15)........ 14,355,735 9.73% 5,313,400 100.00% 13,293,298 24.55% -- -- Fayez Sarofim(16).............. 7,888,871 5.35% -- -- -- -- -- -- Capital Group International, -- -- -- -- 4,970,550 9.18% -- -- Inc.(17)....................... OppenheimerFunds, Inc.(18)..... -- -- -- -- 4,822,317 8.90% -- -- Kayne Anderson Capital Advisors, L.P.(19).................... -- -- -- -- 3,816,642 7.05% -- -- </TABLE> - ---------- * Less than 1%. (1) Except as noted otherwise, all units, KMR shares and KMI shares involve sole voting power and sole investment power. For KMR, see note (4). On January 18, 2005, KMR's board of directors initiated a rule requiring each director to own a minimum of 10,000 common units, KMR shares, or a combination thereof. If a director does not already own the minimum number of required securities, the director will have six years to acquire such securities. (2) As of January 31, 2005, we had 147,555,658 common units issued and outstanding. (3) As of January 31, 2005, we had 5,313,400 Class B units issued and outstanding. (4) Represent the limited liability company shares of KMR. As of January 31, 2005, there were 54,157,641 issued and outstanding KMR shares, including two voting shares owned by our general partner. In all cases, our i-units will be voted in proportion to the affirmative and negative votes, abstentions and non-votes of owners of KMR shares. Through the provisions in our partnership agreement and KMR's limited liability company agreement, the number of outstanding KMR shares, including voting shares owned by our general partner, and the number of our i-units will at all times be equal. (5) As of January 31, 2005, KMI had a total of 123,378,197 shares of issued and outstanding voting common stock, which excludes 11,076,901 shares held in treasury. (6) Includes (a) 7,879 common units owned by Mr. Kinder's spouse, (b) 5,173 KMI shares held by Mr. Kinder's spouse and (c) 250 KMI shares held by Mr. Kinder in a custodial account for his nephew. Mr. Kinder disclaims any and all beneficial or pecuniary interest in these units and shares. (7) Includes options to purchase 195,000 KMI shares exercisable within 60 days of January 31, 2005, and includes 112,500 shares of restricted KMI stock. 94 <PAGE> (8) Includes 1,750 restricted common units. (9) Includes options to purchase 10,000 common units exercisable within 60 days of January 31, 2005, and includes 1,750 restricted common units. (10) Includes options to purchase 10,000 common units exercisable within 60 days of January 31, 2005, and includes 1,750 restricted common units. (11) Includes options to purchase 56,300 KMI shares exercisable within 60 days of January 31, 2005, and includes 72,500 shares of restricted KMI stock. (12) Includes 102,500 shares of restricted KMI stock. (13) Includes options to purchase 20,000 KMI shares exercisable within 60 days of January 31, 2005, and includes 41,250 shares of restricted KMI stock. (14) Includes options to purchase 24,000 common units and 433,300 KMI shares exercisable within 60 days of January 31, 2005, and includes 5,250 restricted common units and 467,500 shares of restricted KMI stock. (15) Includes common units owned by KMI and its consolidated subsidiaries, including 1,724,000 common units owned by Kinder Morgan G.P., Inc. (16) As reported on the Schedule 13G/A filed February 11, 2005 by Fayez Sarofim & Co. and Fayez Sarofim. Mr. Sarofim reports that in regard to our common units, he has sole voting power over 2,300,000 common units, shared voting power over 4,242,612 common units, sole disposition power over 2,300,000 common units and shared disposition power over 5,588,871 common units. Mr. Sarofim's address is 2907 Two Houston Center, Houston, Texas 77010. (17) As reported on the Schedule 13G/A filed February 14, 2005 by Capital Group International, Inc. and Capital Guardian Trust Company. Capital Group International, Inc. and Capital Guardian Trust Company report that in regard to KMR shares, they have sole voting power over 3,913,560 shares, shared voting power over 0 shares, sole disposition power over 4,970,550 shares and shared disposition power over 0 shares. Capital Group International, Inc.'s and Capital Guardian Trust Company's address is 11100 Santa Monica Blvd., Los Angeles, California 90025. (18) As reported on the Schedule 13G/A filed February 11, 2005 by OppenheimerFunds, Inc. and Oppenheimer Capital Income Fund. OppenheimerFunds, Inc. reports that in regard to KMR shares, it has sole voting power over 0 shares, shared voting power over 0 shares, sole disposition power over 0 shares and shared disposition power over 4,822,317 shares. Of these 4,822,317 KMR shares, Oppenheimer Capital Income Fund has sole voting power over 3,232,500 shares, shared voting power over 0 shares, sole disposition power over 0 shares and shared disposition power over 3,232,500 shares. OppenheimerFunds, Inc.'s address is 225 Liberty Street, 11th Floor, New York, New York 10281, and Oppenheimer Capital Income Fund's address is 6803 Tucson Way, Centennial, Colorado 80112. (19) As reported on the Schedule 13G filed February 11, 2005 by Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne. Kayne Anderson Capital Advisors, L.P. reports that in regard to KMR shares, it has sole voting power over 0 shares, shared voting power over 3,815,712 shares, sole disposition power over 0 shares and shared disposition power over 3,815,712 shares. Mr. Anderson reports that in regard to KMR shares, he has sole voting power over 930 shares, shared voting power over 3,815,712 shares, sole disposition power over 930 shares and shared disposition power over 3,815,712 shares. Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne's address is 1800 Avenue of the Stars, Second Floor, Los Angeles, California 90067. Equity Compensation Plan Information The following table sets forth information regarding our equity compensation plans as of January 31, 2005. Specifically, the table refers to information regarding our Common Unit Option Plan described in Item 11. "Executive Compensation") as of January 31, 2005. 95 <PAGE> <TABLE> <CAPTION> Number of securities remaining available for Number of securities Weighted average future issuance under equity to be issued upon exercise exercise price compensation plans of outstanding options, of outstanding options, (excluding securities reflected warrants and rights warrants and rights In column (a)) Plan category (a) (b) (c) - --------------------------------- -------------------------- ----------------------- ------------------------------- <S> <C> <C> <C> Equity compensation plans approved by security holders - - - Equity compensation plans not approved by security holders 95,900 $18.0755 55,400 ------ ------ Total 95,900 55,400 ====== ====== </TABLE> Item 13. Certain Relationships and Related Transactions. See Note 12 of the notes to our consolidated financial statements included elsewhere in this report. Item 14. Principal Accounting Fees and Services The following sets forth fees billed for the audit and other services provided by PricewaterhouseCoopers LLP for the fiscal years ended December 31, 2004 and 2003 (in dollars): Year Ended December 31, ----------------------- 2004 2003 ---------- ---------- Audit fees(1).............$2,147,000 $1,079,092 Audit-Related fees(2)..... 34,000 - Tax fees(3)............... 1,994,956 1,347,903 --------- --------- Total...................$4,175,956 $2,426,995 ========== ========== - ---------- (1) Includes fees for audit of annual financial statements, reviews of the related quarterly financial statements, and reviews of documents filed with the Securities and Exchange Commission. (2) Includes fees for assurance and related services that are reasonably related to the performance of the audit or review of our financial statements. (3) Includes fees related to professional services for tax compliance, tax advice and tax planning. All services rendered by PricewaterhouseCoopers LLP are permissible under applicable laws and regulations, and are pre-approved by the audit committee of KMR and our general partner. Pursuant to the charter of the audit committee of KMR, the delegate of our general partner, the committee's primary purposes include the following: o to select, appoint, engage, oversee, retain, evaluate and terminate our external auditors; o to pre-approve all audit and non-audit services, including tax services, to be provided, consistent with all applicable laws, to us by our external auditors; and o to establish the fees and other compensation to be paid to our external auditors. Furthermore, the audit committee will review the external auditors' proposed audit scope and approach as well as the performance of the external auditors. It also has direct responsibility for and sole authority to resolve any disagreements between our management and our external auditors regarding financial reporting, will regularly review with the external auditors any problems or difficulties the auditors encountered in the course of their audit work, and will, at least annually, use its reasonable efforts to obtain and review a report from the external auditors addressing the following (among other items): o the auditors' internal quality-control procedures; 96 <PAGE> o any material issues raised by the most recent internal quality-control review, or peer review, of the external auditors; o the independence of the external auditors; and o the aggregate fees billed by our external auditors for each of the previous two fiscal years. 97 <PAGE> PART IV Item 15. Exhibits and Financial Statement Schedules. (a)(1) and (2) Financial Statements and Financial Statement Schedules See "Index to Financial Statements" set forth on page 101. (a)(3) Exhibits *3.1-- Third Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 3.1 to Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter ended June 30, 2001, filed on August 9, 2001). *3.2-- Amendment No. 1 dated November 19, 2004 to Third Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 99.1 to Kinder Morgan Energy Partners, L.P. Form 8-K filed November 22, 2004). *4.1-- Specimen Certificate evidencing Common Units representing Limited Partner Interests (filed as Exhibit 4.1 to Amendment No. 1 to Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-4, File No. 333-44519, filed on February 4, 1998). *4.2-- Indenture dated as of January 29, 1999 among Kinder Morgan Energy Partners, L.P., the guarantors listed on the signature page thereto and U.S. Trust Company of Texas, N.A., as trustee, relating to Senior Debt Securities (filed as Exhibit 4.1 to the Partnership's Current Report on Form 8-K filed February 16, 1999, File No. 1-11234 (the "February 16, 1999 Form 8-K")). *4.3-- First Supplemental Indenture dated as of January 29, 1999 among Kinder Morgan Energy Partners, L.P., the subsidiary guarantors listed on the signature page thereto and U.S. Trust Company of Texas, N.A., as trustee, relating to $250,000,000 of 6.30% Senior Notes due February 1, 2009 (filed as Exhibit 4.2 to the February 16, 1999 Form 8-K). *4.4-- Second Supplemental Indenture dated as of September 30, 1999 among Kinder Morgan Energy Partners, L.P. and U.S. Trust Company of Texas, N.A., as trustee, relating to release of subsidiary guarantors under the $250,000,000 of 6.30% Senior Notes due February 1, 2009 (filed as Exhibit 4.4 to the Partnership's Form 10-Q for the quarter ended September 30, 1999 (the "1999 Third Quarter Form 10-Q")). *4.5-- Indenture dated March 22, 2000 between Kinder Morgan Energy Partners, L.P. and First Union National Bank, as Trustee (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-4 (File No. 333-35112) filed on April 19, 2000 (the "April 2000 Form S-4")). *4.6-- Form of 8% Note (contained in the Indenture filed as Exhibit 4.1 to the April 2000 Form S-4). *4.7-- Indenture dated November 8, 2000 between Kinder Morgan Energy Partners, L.P. and First Union National Bank, as Trustee (filed as Exhibit 4.8 to Kinder Morgan Energy Partners, L.P. Form 10-K for 2001). *4.8-- Form of 7.50% Notes due November 1, 2010 (contained in the Indenture filed as Exhibit 4.8 to the Kinder Morgan Energy Partners, L.P. Form 10-K for 2001). *4.9-- Indenture dated January 2, 2001 between Kinder Morgan Energy Partners and First Union National Bank, as trustee, relating to Senior Debt Securities (including form of Senior Debt Securities) (filed as Exhibit 4.11 to Kinder Morgan Energy Partners, L.P. Form 10-K for 2000). *4.10-- Indenture dated January 2, 2001 between Kinder Morgan Energy Partners and First Union National Bank, as trustee, relating to Subordinated Debt Securities (including form of Subordinated Debt Securities) (filed as Exhibit 4.12 to Kinder Morgan Energy Partners, L.P. Form 10-K for 2000). *4.11-- Certificate of Vice President and Chief Financial Officer of Kinder Morgan Energy Partners, L.P. establishing the terms of the 6.75% Notes due March 15, 2011 and the 7.40% Notes due March 15, 2031 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P. Form 8-K, filed on March 14, 2001). *4.12-- Specimen of 6.75% Notes due March 15, 2011 in book-entry form (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Form 8-K, filed on March 14, 2001). *4.13-- Specimen of 7.40% Notes due March 15, 2031 in book-entry form (filed as Exhibit 4.3 to Kinder Morgan Energy Partners, L.P. Form 8-K, filed on March 14, 2001). 98 <PAGE> *4.14-- Certificate of Vice President and Chief Financial Officer of Kinder Morgan Energy Partners, L.P. establishing the terms of the 7.125% Notes due March 15, 2012 and the 7.750% Notes due March 15, 2032 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter ended March 31, 2002, filed on May 10, 2002). *4.15-- Specimen of 7.125% Notes due March 15, 2012 in book-entry form (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter ended March 31, 2002, filed on May 10, 2002). *4.16-- Specimen of 7.750% Notes due March 15, 2032 in book-entry form (filed as Exhibit 4.3 to Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter ended March 31, 2002, filed on May 10, 2002). *4.17-- Indenture dated August 19, 2002 between Kinder Morgan Energy Partners, L.P. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.1 to the Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-4 (File No. 333-100346) filed on October 4, 2002 (the "October 4, 2002 Form S-4")). *4.18-- First Supplemental Indenture to Indenture dated August 19, 2002, dated August 23, 2002 between Kinder Morgan Energy Partners, L.P. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.2 to the October 4, 2002 Form S-4). *4.19-- Form of 5.35% Note and Form of 7.30% Note (contained in the Indenture filed as Exhibit 4.1 to the October 4, 2002 Form S-4). *4.20-- Senior Indenture dated January 31, 2003 between Kinder Morgan Energy Partners, L.P. and Wachovia Bank, National Association (filed as Exhibit 4.2 to the Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-3 (File No. 333-102961) filed on February 4, 2003 (the "February 4, 2003 Form S-3")). *4.21-- Form of Senior Note of Kinder Morgan Energy Partners, L.P. (included in the Form of Senior Indenture filed as Exhibit 4.2 to the February 4, 2003 Form S-3). *4.22-- Subordinated Indenture dated January 31, 2003 between Kinder Morgan Energy Partners, L.P. and Wachovia Bank, National Association (filed as Exhibit 4.4 to the February 4, 2003 Form S-3). *4.23-- Form of Subordinated Note of Kinder Morgan Energy Partners, L.P. (included in the Form of Subordinated Indenture filed as Exhibit 4.4 to the February 4, 2003 Form S-3). *4.24-- Certificate of Vice President, Treasurer and Chief Financial Officer and Vice President, General Counsel and Secretary of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P. establishing the terms of the 5.00% Notes due December 15, 2013 (filed as Exhibit 4.25 to Kinder Morgan Energy Partners, L.P. Form 10-K for 2003 filed March 5, 2004). *4.25-- Specimen of 5.00% Notes due December 15, 2013 in book-entry form (filed as Exhibit 4.26 to Kinder Morgan Energy Partners, L.P. Form 10-K for 2003 filed March 5, 2004). 4.26-- Specimen of 5.125% Notes due November 15, 2014 in book-entry form. 4.27-- Certificate of Executive Vice President and Chief Financial Officer and Vice President, General Counsel and Secretary of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P. establishing the terms of the 5.125% Notes due November 15, 2014. 4.28-- Certain instruments with respect to long-term debt of Kinder Morgan Energy Partners, L.P. and its consolidated subsidiaries which relate to debt that does not exceed 10% of the total assets of Kinder Morgan Energy Partners, L.P. and its consolidated subsidiaries are omitted pursuant to Item 601(b) (4) (iii) (A) of Regulation S-K, 17 C.F.R. sec.229.601. Kinder Morgan Energy Partners, L.P. hereby agrees to furnish supplementally to the Securities and Exchange Commission a copy of each such instrument upon request. *10.1-- Kinder Morgan Energy Partners, L.P. Common Unit Option Plan (filed as Exhibit 10.6 to the Kinder Morgan Energy Partners, L.P. 1997 Form 10-K, File No. 1-11234). *10.2-- Delegation of Control Agreement among Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan Energy Partners, L.P. and its operating partnerships (filed as Exhibit 10.1 to the Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter ended June 30, 2001). *10.3-- Kinder Morgan Energy Partners, L.P. Directors' Unit Appreciation Rights Plan (filed as Exhibit 10.6 to the Kinder Morgan Energy Partners, L.P. Form 10-K for 2003 filed March 5, 2004). *10.4-- Amendment No. 1 to Kinder Morgan Energy Partners, L.P. Directors' Unit Appreciation Rights Plan (filed as Exhibit 10.7 to the Kinder Morgan Energy Partners, L.P. Form 10-K for 2003 filed March 5, 2004). 99 <PAGE> *10.5-- Resignation and Non-Compete agreement dated July 21, 2004 between KMGP Services, Inc. and Michael C. Morgan, President of Kinder Morgan, Inc., Kinder Morgan G.P., Inc. and Kinder Morgan Management, LLC (filed as Exhibit 10.1 to the Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter ended June 30, 2004, filed on August 5, 2004). *10.6-- 5-Year Credit Agreement dated as of August 18, 2004 among Kinder Morgan Energy Partners, L.P., the lenders party thereto and Wachovia Bank, National Association as Administrative Agent (filed as Exhibit 10.1 to Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter ended September 30, 2004, filed November 2, 2004). *10.7-- Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors (filed as Exhibit 10.2 to Kinder Morgan Energy Partners, L.P. Form 8-K filed January 21, 2005). *10.8-- Form of Common Unit Compensation Agreement entered into with Non-Employee Directors (filed as Exhibit 10.1 to Kinder Morgan Energy Partners, L.P. Form 8-K filed January 21, 2005). 11.1-- Statement re: computation of per share earnings. 21.1-- List of Subsidiaries. 23.1-- Consent of PricewaterhouseCoopers LLP. 23.2-- Consent of Netherland, Sewell and Associates, Inc. 31.1-- Certification by CEO pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31.2-- Certification by CFO pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 32.1-- Certification by CEO pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 32.2-- Certification by CFO pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. - ---------- * Asterisk indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith, except as noted otherwise. 100 <PAGE> INDEX TO FINANCIAL STATEMENTS Page Number ------ KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES Report of Independent Registered Public Accounting Firm................. 102 Consolidated Statements of Income for the years ended December 31, 2004, 2003, and 2002.................................................... 103 Consolidated Statements of Comprehensive Income for the years ended December 31, 2004, 2003, and 2002....................................... 104 Consolidated Balance Sheets as of December 31, 2004 and 2003............ 105 Consolidated Statements of Cash Flows for the years ended December 31, 2004, 2003, and 2002................................................ 106 Consolidated Statements of Partners' Capital for the years ended December 31, 2004, 2003, and 2002....................................... 107 Notes to Consolidated Financial Statements.............................. 108 101 <PAGE> Report of Independent Registered Public Accounting Firm To the Partners of Kinder Morgan Energy Partners, L.P. We have completed an integrated audit of Kinder Morgan Energy Partners, L.P.'s (the Partnership) 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004 and audits of its 2003 and 2002 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below. Consolidated financial statements - --------------------------------- In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Kinder Morgan Energy Partners, L.P. and its subsidiaries at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 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 the standards of the Public Company Accounting Oversight Board (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 of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. As discussed in Note 4 to the consolidated financial statements, the Partnership changed its method of accounting for asset retirement obligations effective January 1, 2003. As discussed in Note 8 to the consolidated financial statements, the Partnership changed its method of accounting for goodwill and other intangible assets effective January 1, 2002. Internal control over financial reporting - ----------------------------------------- Also, in our opinion, management's assessment, included in Management's Report on Internal Control Over Financial Reporting appearing under Item 9A, that the Partnership maintained effective internal control over financial reporting as of December 31, 2004 based on criteria established in Internal Control -- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control -- Integrated Framework issued by the COSO. The Partnership's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management's assessment and on the effectiveness of the Partnership's internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions. A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. As described in Management's Report on Internal Control Over Financial Reporting, management has excluded North Charleston Bulk Terminal, Kinder Morgan Wink Pipeline, L.P., Kinder Morgan River Terminals LLC, Charter Products Terminals and Kinder Morgan Fairless Hills Terminal from its assessment of internal control over financial reporting as of December 31, 2004 because these businesses were acquired by the Partnership in purchase business combinations during 2004. We have also excluded North Charleston Bulk Terminal, Kinder Morgan Wink Pipeline, L.P., Kinder Morgan River Terminals LLC, Charter Products Terminals and Kinder Morgan Fairless Hills Terminal from our audit of internal control over financial reporting. These businesses, in the aggregate, constituted .04% of the Partnership's consolidated revenues for 2004 and 2.75% of the Partnership's consolidated assets at December 31, 2004. PricewaterhouseCoopers LLP Houston, Texas March 3, 2004 102 <PAGE> <TABLE> <CAPTION> KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME Year Ended December 31, -------------------------------------- 2004 2003 2002 ---------- ---------- ---------- (In thousands except per unit amounts) Revenues <S> <C> <C> <C> Natural gas sales............................................... $5,803,065 $4,889,235 $2,740,518 Services........................................................ 1,571,504 1,377,745 1,272,640 Product sales and other......................................... 558,292 357,342 223,899 ---------- ---------- ---------- 7,932,861 6,624,322 4,237,057 ---------- ---------- ---------- Costs and Expenses Gas purchases and other costs of sales.......................... 5,767,169 4,880,118 2,704,295 Operations and maintenance...................................... 499,714 397,723 376,479 Fuel and power.................................................. 151,480 108,112 86,413 Depreciation and amortization................................... 288,626 219,032 172,041 General and administrative...................................... 170,507 150,435 122,205 Taxes, other than income taxes.................................. 81,369 62,213 51,326 ---------- ---------- ---------- 6,958,865 5,817,633 3,512,759 ---------- ---------- ---------- Operating Income.................................................. 973,996 806,689 724,298 Other Income (Expense) Earnings from equity investments................................ 83,190 92,199 89,258 Amortization of excess cost of equity investments............... (5,575) (5,575) (5,575) Interest, net................................................... (192,882) (181,357) (176,460) Other, net...................................................... 2,254 7,601 1,698 Minority Interest................................................. (9,679) (9,054) (9,559) ---------- ---------- ---------- Income Before Income Taxes and Cumulative Effect of a Change in Accounting Principle ........................................... 851,304 710,503 623,660 Income Taxes...................................................... 19,726 16,631 15,283 ---------- ---------- ---------- Income Before Cumulative Effect of a Change in Accounting Principle 831,578 693,872 608,377 Cumulative effect adjustment from change in accounting for asset retirement obligations.......................................... - 3,465 - ---------- ---------- ---------- Net Income........................................................ $ 831,578 $ 697,337 $ 608,377 ========== ========== ========== Calculation of Limited Partners' Interest in Net Income: Income Before Cumulative Effect of a Change in Accounting $ 831,578 $ 693,872 $ 608,377 Principle......................................................... Less: General Partner's interest................................ (395,092) (326,489) (270,816) ---------- ---------- ---------- Limited Partners' interest...................................... 436,486 367,383 337,561 Add: Limited Partners' interest in Change in Accounting Principle - 3,430 - ---------- ---------- ---------- Limited Partners' interest in Net Income........................ $ 436,486 $ 370,813 $ 337,561 ========== ========== ========== Basic and Diluted Limited Partners' Net Income per Unit: Income Before Cumulative Effect of a Change in Accounting $ 2.22 $ 1.98 $ 1.96 Principle......................................................... Cumulative effect adjustment from change in accounting for asset retirement obligations........................................ - 0.02 - ---------- ---------- ---------- Net Income...................................................... $ 2.22 $ 2.00 $ 1.96 ========== =========== ========== Weighted average number of units used in computation of Limited Partners' Net Income per Unit: Basic............................................................. 196,956 185,384 172,017 ========== ========== ========== Diluted........................................................... 197,038 185,494 172,186 ========== ========== ========== </TABLE> The accompanying notes are an integral part of these consolidated financial statements. 103 <PAGE> KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME <TABLE> <CAPTION> Year Ended December 31, 2004 2003 2002 ---------- ---------- ------- (In thousands) <S> <C> <C> <C> Net Income.................................................. $ 831,578 $ 697,337 $ 608,377 Foreign currency translation adjustments.................... 375 -- -- Change in fair value of derivatives used for hedging purposes................................ (494,212) (192,618) (116,560) Reclassification of change in fair value of derivatives to net income................................................... 192,304 82,065 7,477 --------- --------- --------- Comprehensive Income........................................ $ 530,045 $ 586,784 $ 499,294 ========= ========= ========= </TABLE> The accompanying notes are an integral part of these consolidated financial statements. 104 <PAGE> KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS <TABLE> <CAPTION> December 31, 2004 2003 ----------- -------- ASSETS (Dollars in thousands) Current Assets <S> <C> <C> Cash and cash equivalents................................ $ - $ 23,329 Accounts, notes and interest receivable, net Trade................................................. 739,798 563,012 Related parties....................................... 12,482 27,587 Inventories Products.............................................. 17,868 7,214 Materials and supplies................................ 11,345 10,783 Gas imbalances Trade................................................. 24,653 36,449 Related parties....................................... 980 9,084 Gas in underground storage............................... - 8,160 Other current assets..................................... 46,045 19,904 ----------- ---------- 853,171 705,522 Property, Plant and Equipment, net......................... 8,168,680 7,091,558 Investments................................................ 413,255 404,345 Notes receivable Trade.................................................... 1,944 2,422 Related parties.......................................... 111,225 - Goodwill................................................... 732,838 729,510 Other intangibles, net..................................... 15,284 13,202 Deferred charges and other assets.......................... 256,545 192,623 ----------- ---------- Total Assets............................................... $10,552,942 $9,139,182 =========== ========== LIABILITIES AND PARTNERS' CAPITAL Current Liabilities Accounts payable Cash book overdrafts.................................. $ 29,866 $ - Trade................................................. 685,034 477,783 Related parties....................................... 16,650 - Current portion of long-term debt........................ - 2,248 Accrued interest......................................... 56,930 52,356 Accrued taxes............................................ 26,435 20,857 Deferred revenues........................................ 7,825 10,752 Gas imbalances........................................... 32,452 49,912 Accrued other current liabilities........................ 325,663 190,471 ----------- ---------- 1,180,855 804,379 Long-Term Liabilities and Deferred Credits Long-term debt Outstanding........................................... 4,722,410 4,316,678 Market value of interest rate swaps................... 130,153 121,464 ----------- ---------- 4,852,563 4,438,142 Deferred revenues........................................ 14,680 20,975 Deferred income taxes.................................... 56,487 38,106 Asset retirement obligations............................. 37,464 34,898 Other long-term liabilities and deferred credits......... 468,727 251,691 ----------- ---------- 5,429,921 4,783,812 Commitments and Contingencies (Notes 13 and 16) Minority Interest.......................................... 45,646 40,064 ----------- ---------- Partners' Capital Common Units (147,537,908 and 134,729,258 units issued and outstanding as of December 31, 2004 and 2003, respectively)......................................... 2,438,011 1,946,116 Class B Units (5,313,400 and 5,313,400 units issued and outstanding as of December 31, 2004 and 2003, respectively)......................................... 117,414 120,582 i-Units (54,157,641 and 48,996,465 units issued and outstanding as of December 31, 2004 and 2003, respectively)........................................ 1,694,971 1,515,659 General Partner.......................................... 103,467 84,380 Accumulated other comprehensive loss..................... (457,343) (155,810) ----------- ---------- 3,896,520 3,510,927 Total Liabilities and Partners' Capital.................... $10,552,942 $9,139,182 =========== ========== </TABLE> The accompanying notes are an integral part of these consolidated financial statements. 105 <PAGE> KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS <TABLE> <CAPTION> Year Ended December 31, --------------------------------------- 2004 2003 2002 ----------- ----------- ----------- (In thousands) Cash Flows From Operating Activities <S> <C> <C> <C> Net income................................................ $ 831,578 $ 697,337 $ 608,377 Adjustments to reconcile net income to net cash provided by operating activities: Cumulative effect adj. from change in accounting for asset retirement obligations...................... -- (3,465) -- Depreciation, depletion and amortization................ 288,626 219,032 172,041 Amortization of excess cost of equity investments....... 5,575 5,575 5,575 Earnings from equity investments........................ (83,190) (92,199) (89,258) Distributions from equity investments..................... 65,248 83,000 77,735 Changes in components of working capital: Accounts receivable..................................... (172,393) (180,632) (177,240) Other current assets.................................... 26,175 (1,858) (7,583) Inventories............................................. (7,353) (2,945) (1,713) Accounts payable........................................ 222,377 92,702 288,712 Accrued liabilities..................................... (18,482) 9,740 26,132 Accrued taxes........................................... 3,444 (4,904) 2,379 FERC rate reparations and refunds......................... -- (44,944) -- Other, net................................................ (6,497) (7,923) (35,462) ----------- ----------- ----------- Net Cash Provided by Operating Activities................... 1,155,108 768,516 869,695 ----------- ----------- ----------- Cash Flows From Investing Activities Acquisitions of assets.................................... (478,830) (349,867) (908,511) Additions to property, plant and equip. for expansion and maintenance projects................ (747,262) (576,979) (542,235) Sale of investments, property, plant and equipment, net of removal costs..................................... 1,069 2,090 13,912 Acquisitions of investments............................... (1,098) (10,000) (1,785) Contributions to equity investments....................... (7,010) (14,052) (10,841) Natural gas stored underground and natural gas liquids line-fill............................ (19,189) 5,459 (884) Other..................................................... 1,810 288 (536) ----------- ----------- ----------- Net Cash Used in Investing Activities....................... (1,250,510) (943,061) (1,450,880) ----------- ----------- ----------- Cash Flows From Financing Activities Issuance of debt.......................................... 6,016,670 4,674,605 3,803,414 Payment of debt........................................... (5,657,566) (4,014,296) (2,985,322) Loans to related party.................................... (96,271) -- -- Debt issue costs.......................................... (5,843) (5,204) (17,006) Increase in cash book overdrafts.......................... 29,866 -- -- Proceeds from issuance of common units.................... 506,520 175,567 1,586 Proceeds from issuance of i-units......................... 67,528 -- 331,159 Contributions from General Partner........................ 7,956 4,181 3,353 Distributions to partners: Common units............................................ (389,912) (340,927) (306,590) Class B units........................................... (14,931) (13,682) (12,540) General Partner......................................... (376,005) (314,244) (253,344) Minority interest....................................... (10,117) (10,445) (9,668) Other, net................................................ (5,822) 1,231 4,429 ------------ ----------- ----------- Net Cash Provided by Financing Activities................... 72,073 156,786 559,471 ----------- ----------- ----------- Decrease in Cash and Cash Equivalents....................... (23,329) (17,759) (21,714) Cash and Cash Equivalents, beginning of period.............. 23,329 41,088 62,802 ----------- ----------- ----------- Cash and Cash Equivalents, end of period.................... $ -- $ 23,329 $ 41,088 =========== =========== =========== Noncash Investing and Financing Activities: Assets acquired by the issuance of units.................. $ 64,050 $ 2,000 $ -- Assets acquired by the assumption of liabilities.......... 81,403 36,187 213,861 Supplemental disclosures of cash flow information: Cash paid (received) during the year for Interest (net of capitalized interest).................... 193,247 183,908 161,840 Income taxes.............................................. (752) (261) 1,464 </TABLE> The accompanying notes are an integral part of these consolidated financial statements. 106 <PAGE> KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL <TABLE> <CAPTION> <S> <C> <C> <C> <C> <C> <C> 2004 2003 2002 ------------------------ ------------------------- ------------------------ Units Amount Units Amount Units Amount ----------- ----------- ------------ ----------- ----------- ----------- (Dollars in thousands) Common Units: Beginning Balance..................... 134,729,258 $ 1,946,116 129,943,218 $ 1,844,553 129,855,018 $ 1,894,677 Net income............................ -- 311,237 -- 265,423 -- 254,934 Units issued as consideration in the acquisition of assets............... 1,400,000 64,050 51,490 2,000 -- -- Units issued for cash................. 11,408,650 506,520 4,734,550 175,067 88,200 1,532 Distributions......................... -- (389,912) -- (340,927) -- (306,590) ----------- ----------- ----------- ----------- ----------- ----------- Ending Balance........................ 147,537,908 2,438,011 134,729,258 1,946,116 129,943,218 1,844,553 Class B Units: Beginning Balance..................... 5,313,400 120,582 5,313,400 123,635 5,313,400 125,750 Net income............................ -- 11,763 -- 10,629 -- 10,427 Units issued for cash................. -- -- -- -- -- (2) Distributions......................... -- (14,931) -- (13,682) -- (12,540) ----------- ----------- ----------- ----------- ----------- ----------- Ending Balance........................ 5,313,400 117,414 5,313,400 120,582 5,313,400 123,635 i-Units: Beginning Balance..................... 48,996,465 1,515,659 45,654,048 1,420,898 30,636,363 1,020,153 Net income............................ -- 113,486 -- 94,761 -- 72,200 Units issued for cash................. 1,660,664 65,826 -- -- 12,478,900 328,545 Distributions......................... 3,500,512 -- 3,342,417 -- 2,538,785 -- ----------- ----------- ----------- ----------- ----------- ----------- Ending Balance........................ 54,157,641 1,694,971 48,996,465 1,515,659 45,654,048 1,420,898 General Partner: Beginning Balance..................... -- 84,380 -- 72,100 -- 54,628 Net income............................ -- 395,092 -- 326,524 -- 270,816 Units issued for cash................. -- -- -- -- -- -- Distributions......................... -- (376,005) -- (314,244) -- (253,344) ------------ ------------ ----------- ----------- ----------- ------------ Ending Balance........................ -- 103,467 -- 84,380 -- 72,100 Accum. other comprehensive income (loss): Beginning Balance..................... -- (155,810) -- (45,257) -- 63,826 Foreign currency translation adjustments -- 375 -- -- -- -- Change in fair value of derivatives used for hedging purposes........... -- (494,212) -- (192,618) -- (116,560) Reclassification of change in fair value of derivatives to net income.. -- 192,304 -- 82,065 -- 7,477 ------------ ----------- ------------ ----------- ------------ ------------ Ending Balance........................ -- (457,343) -- (155,810) -- (45,257) Total Partners' Capital................. 207,008,949 $ 3,896,520 189,039,123 $ 3,510,927 180,910,666 $ 3,415,929 =========== =========== ============ ============ =========== ============ </TABLE> The accompanying notes are an integral part of these consolidated financial statements. 107 <PAGE> KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. Organization General Kinder Morgan Energy Partners, L.P. is a Delaware limited partnership formed in August 1992. Unless the context requires otherwise, references to "we," "us," "our" or the "Partnership" are intended to mean Kinder Morgan Energy Partners, L.P. and its consolidated subsidiaries. We own and manage a diversified portfolio of energy transportation and storage assets. We provide services to our customers and create value for our unitholders primarily through the following activities: o transporting, storing and processing refined petroleum products; o transporting, storing and selling natural gas; o producing, transporting and selling carbon dioxide, commonly called CO2, for use in, and selling crude oil produced from, enhanced oil recovery operations; and o transloading, storing and delivering a wide variety of bulk, petroleum and petrochemical products at terminal facilities located across the United States. We focus on providing fee-based services to customers, generally avoiding near-term commodity price risks and taking advantage of the tax benefits of a limited partnership structure. We trade on the New York Stock Exchange under the symbol "KMP" and presently conduct our business through four reportable business segments: o Products Pipelines; o Natural Gas Pipelines; o CO2; and o Terminals. For more information on our reportable business segments, see Note 15. Kinder Morgan, Inc. Kinder Morgan, Inc., a Kansas corporation, is the sole stockholder of Kinder Morgan (Delaware), Inc. Kinder Morgan (Delaware), Inc., a Delaware corporation, is the sole stockholder of our general partner, Kinder Morgan G.P., Inc. Kinder Morgan, Inc. 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 energy transportation and storage companies in the United States, operating, either for itself or on our behalf, more than 35,000 miles of natural gas and products pipelines and approximately 135 terminals. At December 31, 2004, KMI and its consolidated subsidiaries owned, through its general and limited partner interests, an approximate 18.5% interest in us. Kinder Morgan Management, LLC Kinder Morgan Management, LLC, a Delaware limited liability company, was formed on February 14, 2001. It is referred to as "KMR" in this report. Our general partner owns all of KMR's voting securities and, pursuant to a delegation of control agreement, our general partner has delegated to KMR, to the fullest extent permitted under Delaware law and our partnership agreement, all of its power and authority to manage and control our business and 108 <PAGE> affairs, except that KMR cannot take certain specified actions without the approval of our general partner. Under the delegation of control agreement, KMR manages and controls our business and affairs and the business and affairs of our operating limited partnerships and their subsidiaries. Furthermore, in accordance with its limited liability company agreement, KMR's activities are limited to being a limited partner in, and managing and controlling the business and affairs of us, our operating limited partnerships and their subsidiaries. As of December 31, 2004, KMR owned approximately 26.2% of our outstanding limited partner units (which are in the form of i-units that are issued only to KMR). 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. Our consolidated financial statements were prepared in accordance with accounting principles generally accepted in the United States. Certain amounts included in or affecting our financial statements and related disclosures must be estimated by management, requiring us to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities and our disclosure of contingent assets and liabilities at the date of the financial statements. Therefore, the reported amounts of our assets and liabilities and associated disclosures with respect to contingent assets and obligations are necessarily affected by these estimates. We evaluate these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. In preparing our financial statements and related disclosures, we must use estimates in determining the economic useful lives of our assets, the fair values used to determine possible asset impairment charges, provisions for uncollectible accounts receivable, exposures under contractual indemnifications and various other recorded or disclosed amounts. However, we believe that certain accounting policies are of more significance in our financial statement preparation process than others. Cash Equivalents We define cash equivalents as all highly liquid short-term investments with original maturities of three months or less. Accounts Receivables Our policy for determining an appropriate allowance for doubtful accounts varies according to the type of business being conducted and the customers being served. An allowance for doubtful accounts is charged to expense monthly, generally using a percentage of revenue or receivables, based on a historical analysis of uncollected amounts, adjusted as necessary for changed circumstances and customer-specific information. When specific receivables are determined to be uncollectible, the reserve and receivable are relieved. The following tables show the balance in the allowance for doubtful accounts and activity for the years ended December 31, 2004, 2003 and 2002. 109 <PAGE> Valuation and Qualifying Accounts (in thousands) <TABLE> <CAPTION> <S> <C> <C> <C> <C> <C> Balance at Additions Additions Balance at beginning of charged to costs charged to other end of Allowance for Doubtful Accounts Period and expenses accounts(1) Deductions(2) period - -------------------------------- ------------ ---------------- ----------------- ----------------- ----------- Year ended December 31, 2004.... $8,783 $1,460 $ 431 $(2,052) $8,622 Year ended December 31, 2003.... $8,092 $1,448 $ - $ (757) $8,783 Year ended December 31, 2002.... $7,556 $ 822 $ 4 $ (290) $8,092 </TABLE> __________ (1) Amount for 2004 represents the allowance recognized when we acquired Kinder Morgan River Terminals LLC and Consolidated Subsidiaries ($393) and TransColorado Gas Transmission Company ($38). Amount for 2002 represents the allowance recognized when we acquired IC Terminal Holdings Company and Consolidated Subsidiaries. (2) Deductions represent the write-off of receivables. In addition, the balances of "Accrued other current liabilities" in our accompanying consolidated balance sheets include amounts related to customer prepayments of approximately $5.1 million as of December 31, 2004 and $8.2 million as of December 31, 2003. 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 report 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 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. Gains and losses on minor system sales, excluding land, are recorded to the appropriate accumulated depreciation reserve. Gains and losses for operating systems sales and land sales are booked to income or expense accounts in accordance with regulatory accounting guidelines. 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. In practice, the composite life may not be determined with a high degree of precision, and hence the composite life may not reflect the weighted average of the expected useful lives of the asset's principal components. Our oil and gas producing activities are accounted for under the successful efforts method of accounting. Under this method costs that are incurred to acquire leasehold and subsequent development costs are capitalized. Costs that are associated with the drilling of successful exploration wells are capitalized if proved reserves are found. Costs associated with the drilling of exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of certain non-producing leasehold costs are expensed as incurred. The capitalized costs of our producing oil and gas properties are depreciated and depleted by the units-of-production method. Other miscellaneous property, plant and equipment are depreciated over the estimated useful lives of the asset. A gain on the sale of property, plant and equipment used in our oil and gas producing activities is calculated as the difference between the cost of the asset disposed of, net of depreciation, and the sales proceeds received. A gain on an asset disposal is recognized in income in the period that the sale is closed. A loss on the sale of property, 110 <PAGE> plant and equipment is calculated as the difference between the cost of the asset disposed of, net of depreciation, and the sales proceeds received or the maket value if the asset is being held for sale. A loss is recognized when the asset is sold or when the net cost of an asset held for sale is greater than the market value of the asset. In addition, we engage in enhanced recovery techniques in which carbon dioxide is injected into certain producing oil reservoirs. In some cases, the acquisition cost of the carbon dioxide associated with enhanced recovery is capitalized as part of our development costs when it is injected. The acquisition cost associated with pressure maintenance operations for reservoir management is expensed when it is injected. When carbon dioxide is recovered in conjunction with oil production, it is extracted and re-injected, and all of the associated costs are expensed as incurred. 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 units-of-production rate is determined by field. 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. We evaluate our oil and gas producing properties for impairment of value on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure, using undiscounted future cash flows based on total proved and risk-adjusted probable and possible reserves. Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted future cash flows based on total proved and risk-adjusted probable and possible reserves or, if available, comparable market values. Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment. On January 1, 2002, we adopted Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" and we now evaluate the impairment of our long-lived assets in accordance with this Statement. This Statement retains the requirements of SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," however, this Statement requires that long-lived assets that are to be disposed of by sale be measured at the lower of book value or fair value less the cost to sell. Furthermore, the scope of discontinued operations is expanded to include all components of an entity with operations of the entity in a disposal transaction. The adoption of SFAS No. 144 has not had an impact on our business, financial position or results of operations. Equity Method of Accounting We account for investments greater than 20% in 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, and less distributions received. Excess of Cost Over Fair Value Effective January 1, 2002, we adopted SFAS No. 141, "Business Combinations" and SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS No. 141 supercedes Accounting Principles Board Opinion No. 16 and requires that all transactions fitting the description of a business combination be accounted for using the purchase method and prohibits the use of the pooling of interests for all business combinations initiated after June 30, 2001. The Statement also modifies the accounting for the excess of cost over the fair value of net assets acquired as well as intangible assets acquired in a business combination. The provisions of this Statement apply to all business combinations initiated after June 30, 2001, and all business combinations accounted for by the purchase method that are completed after July 1, 2001. In addition, this Statement requires disclosure of the primary reasons for a business combination and the allocation of the purchase price paid to the assets acquired and liabilities assumed by major balance sheet caption. SFAS No. 142 supercedes Accounting Principles Board Opinion No. 17 and requires that goodwill no longer be amortized, but instead should be tested, at least on an annual basis, for impairment. A benchmark assessment of potential impairment was required to be completed within six months of adopting SFAS No. 142. After the first six months, goodwill must be tested for impairment annually or as changes in circumstances require. Other intangible assets are to be amortized over their useful life and reviewed for impairment in accordance with the provisions of SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." An intangible asset with an indefinite useful life can no longer be amortized until its useful life becomes determinable. In addition, this Statement requires disclosure of information about goodwill and other intangible assets in the years subsequent to their acquisition that was not previously required. Required disclosures include information about the changes in the carrying amount of goodwill from period to period and the carrying amount of intangible assets by major intangible asset class. 111 <PAGE> These accounting pronouncements required that, beginning with their implementation, we prospectively cease amortization of all intangible assets having indefinite useful economic lives. Such assets, including goodwill, are not to be amortized until their lives are determined to be finite. A recognized intangible asset with an indefinite useful life should be tested for impairment annually or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value. We completed the initial transition impairment test in June 2002 and determined that our goodwill was not impaired as of January 1, 2002. We have selected an impairment measurement test date of January 1 of each year and we have determined that our goodwill was not impaired as of January 1, 2005. Our total unamortized excess cost over fair value of net assets in consolidated affiliates was approximately $732.8 million as of December 31, 2004 and $729.5 million as of December 31, 2003. Such amounts are reported as "Goodwill" on our accompanying consolidated balance sheets. Our total unamortized excess cost over underlying fair value of net assets accounted for under the equity method was approximately $150.3 million as of both December 31, 2004, and December 31, 2003. Pursuant to SFAS No. 142, this amount, referred to as equity method goodwill, should continue to be recognized in accordance with Accounting Principles Board Opinion No. 18, "The Equity Method of Accounting for Investments in Common Stock." Accordingly, we included this amount within "Investments" on our accompanying consolidated balance sheets. In addition, approximately $184.2 million and $189.7 million at December 31 2004 and 2003, respectively, representing the excess of the fair market value of property, plant and equipment over its book value at the date of acquisition was included within "Investments" on our accompanying consolidated balance sheets and was being amortized over a weighted average life of approximately 33.6 years. In addition to our annual impairment test of goodwill, 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 in accordance with APB Opinion No. 18. The impairment test under APB No. 18 considers whether the fair value of the equity investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. As of December 31, 2004, we believed no such impairment had occurred and no reduction in estimated useful lives was warranted. For more information on our acquisitions, see Note 3. For more information on our investments, see Note 7. 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 liquids terminal tank rental revenue ratably over the contract period. We recognize liquids terminal through-put revenue based on volumes received or volumes delivered depending on the customer contract. Liquids terminal minimum take-or-pay revenue is recognized at the end of the contract year or contract term depending on the terms of the contract. We recognize transmix processing revenues based on volumes processed or sold, and if applicable, when title has passed. We recognize energy-related product sales revenues based on delivered quantities of product. Revenues from the sale of oil and natural gas liquids production are recorded using the entitlement method. Under the entitlement method, revenue is recorded when title passes based on our net interest. We record our entitled share of revenues based on entitled volumes and contracted sales prices. Revenues from the sale of natural gas production are recognized when the natural gas is sold. Since there is a ready market for oil and gas production, we sell the majority of our products soon after production at various locations, at which time title and risk of loss pass to the buyer. As a result, we maintain a minimum amount of product inventory in storage and the differences between actual production and sales is not significant. Capitalized Interest We capitalize interest expense during the construction or upgrade of qualifying assets. Interest expense capitalized in 2004, 2003 and 2002 was $6.4 million, $5.3 million and $5.8 million, respectively. 112 <PAGE> Unit-Based Compensation SFAS No. 123, "Accounting for Stock-Based Compensation," as amended by SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure," encourages, but does not require, entities to adopt the fair value method of accounting for stock or unit-based compensation plans. As allowed under SFAS No. 123, we apply APB Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations in accounting for common unit options granted under our common unit option plan. Accordingly, compensation expense is not recognized for common unit options unless the options are granted at an exercise price lower than the market price on the grant date. No compensation expense has been recorded since the options were granted at exercise prices equal to the market prices at the date of grant. Pro forma information regarding changes in net income and per unit data, if the accounting prescribed by SFAS No. 123 had been applied, is not material. For more information on unit-based compensation, see Note 13. 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, which do not contribute to current or future revenue generation. We do not discount environmental liabilities to a 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 recording of these accruals coincides with our completion of a feasibility study or our commitment to a formal plan of action. We recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable. We utilize both internal staff and external experts to assist us in identifying environmental issues and in estimating the costs and timing of remediation efforts. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in our income in the period in which they are reasonably determinable. We routinely conduct reviews of potential environmental issues and claims that could impact our assets or operations. In December 2004, we recognized a $0.2 million increase in environmental expenses and an associated $0.1 million increase in deferred income tax expense resulting from changes to previous estimates. The adjustment included an $18.9 million increase in our estimated environmental receivables and reimbursables and a $19.1 million increase in our overall accrued environmental and related claim liabilities. We included the additional $0.2 million environmental expense within "Other, net" in our accompanying consolidated statement of income for 2004. The $0.3 million expense item, including taxes, is the net impact of a $30.6 million increase in expense in our Products Pipelines business segment, a $7.6 million decrease in expense in our Natural Gas Pipelines segment, a $4.1 million decrease in expense in our CO2 segment, and an $18.6 million decrease in expense in our Terminals business segment. In December 2002, we recognized a $0.3 million reduction in environmental expense and in our overall accrued environmental liability, and we included this amount within "Other, net" in our accompanying consolidated statement of income for 2002. The $0.3 million reduction in environmental expense resulted from a $15.7 million loss in our Products Pipelines business segment and a $16.0 million gain in our Terminals business segment. For more information on our environmental disclosures, see Note 16. Legal We are subject to litigation and regulatory proceedings as the result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to reviseour estimates, our earnings will be affected. We expense legal costs as incurred and all recorded legal liabilities are revised as better information becomes available. For more information on our legal 113 <PAGE> disclosures, see Note 16. Pension We are required to make assumptions and estimates regarding the accuracy of our pension investment returns. Specifically, these include: o our investment return assumptions; o the significant estimates on which those assumptions are based; and o the potential impact that changes in those assumptions could have on our reported results of operations and cash flows. We consider our overall pension liability exposure to be minimal in relation to the value of our total consolidated assets and net income. However, in accordance with SFAS No. 87, "Employers' Accounting for Pensions," our net periodic pension cost includes the return on pension plan assets, including both realized and unrealized changes in the fair market value of pension plan assets. A source of volatility in pension costs comes from this inclusion of unrealized or market value gains and losses on pension assets as part of the components recognized as pension expense. To prevent wide swings in pension expense from occurring because of one-time changes in fund values, SFAS No. 87 allows for the use of an actuarial computed "expected value" of plan asset gains or losses to be the actual element included in the determination of pension expense. The actuarial derived expected return on pension assets not only employs an expected rate of return on plan assets, but also assumes a market-related value of plan assets, which is a calculated value that recognizes changes in fair value in a systematic and rational manner over not more than five years. As required, we disclose the weighted average expected long-run rate of return on our plan assets, which is used to calculate our plan assets' expected return. For more information on our pension disclosures, see Note 10. Gas Imbalances and Gas Purchase Contracts We value gas imbalances due to or due from interconnecting pipelines at the lower of cost or market. Gas imbalances represent the difference between customer nominations and actual gas receipts from and gas deliveries to our interconnecting pipelines under various operational balancing agreements. Natural gas imbalances are either settled in cash or made up in-kind subject to the pipelines' various tariff provisions. Minority Interest As of December 31, 2004, minority interest consisted of the following: o the 1.0101% general partner interest in each of our five operating partnerships; o the 0.5% special limited partner interest in SFPP, L.P.; o the 50% interest in Globalplex Partners, a Louisiana joint venture owned 50% and controlled by Kinder Morgan Bulk Terminals, Inc.; o the 33 1/3% interest in International Marine Terminals Partnership, a Louisiana partnership owned 66 2/3% and controlled by Kinder Morgan Operating L.P. "C"; o the approximate 31% interest in the Pecos Carbon Dioxide Company, a Texas general partnership owned approximately 69% and controlled by Kinder Morgan CO2 Company, L.P. and its consolidated subsidiaries; o the 1% interest in River Terminals Properties, L.P., a Tennessee partnership owned 99% and controlled by Kinder Morgan River Terminals LLC; and 114 <PAGE> o the 25% interest in Guilford County Terminal Company, LLC, a limited liability company owned 75% and controlled by Kinder Morgan Southeast Terminals LLC. 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 us. Some of our corporate subsidiaries and corporations in which we have an equity investment do pay federal and state income taxes. Deferred income tax assets and liabilities for certain 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. Foreign Currency Translation In October 2004, we acquired Kinder Morgan River Terminals LLC, formerly Global Materials Services LLC. Included in the acquisition was Arrow Terminals, B.V., a wholly-owned subsidiary of Kinder Morgan River Terminals LLC that conducts bulk terminal operations in The Netherlands. We translate the assets and liabilities of Arrow Terminals, B.V. to U.S. dollars at year-end exchange rates. Income and expense items are translated at weighted-average rates of exchange prevailing during the year and stockholders' equity accounts are translated by using historical exchange rates. Translation adjustments result from translating all assets and liabilities at current year-end rates, while stockholders' equity is translated by using historical and weighted-average rates. The cumulative translation adjustments balance is reported as a component of accumulated other comprehensive income within Partners' Capital on our accompanying balance sheet. Due to the limited size of our foreign operations, we do not believe these foreign currency translations are material to our financial position. Comprehensive Income Statement of Financial Accounting Standards No. 130, "Accounting for Comprehensive Income," requires that enterprises report a total for comprehensive income. For the year ended December 31, 2004, the difference between our net income and our comprehensive income resulted from unrealized gains or losses on derivatives utilized for hedging purposes and from foreign currency translation adjustments. For each of the years ended December 31, 2003 and 2002, the only difference between our net income and our comprehensive income was the unrealized gain or loss on derivatives utilized for hedging purposes. For more information on our risk management activities, see Note 14. Net Income Per Unit We compute Basic Limited Partners' Net Income per Unit by dividing Limited Partners' 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. Asset Retirement Obligations As of January 1, 2003, we account for asset retirement obligations pursuant to SFAS No. 143, "Accounting for Asset Retirement Obligations." For more information on our asset retirement obligations, see Note 4. 115 <PAGE> Risk Management Activities We utilize energy derivatives for the purpose of mitigating our risk resulting from fluctuations in the market price of natural gas, natural gas liquids, crude oil and carbon dioxide. In addition, we enter into interest rate swap agreements for the purpose of hedging the interest rate risk associated with our debt obligations. Our derivatives are accounted for under SFAS No. 133, as amended by SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No.133" and No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities." SFAS No. 133 established accounting and reporting standards requiring that every derivative financial instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. SFAS No. 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. If the derivatives meet those criteria, SFAS No. 133 allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company formally designate a derivative as a hedge and document and assess the effectiveness of derivatives associated with transactions that receive hedge accounting. Furthermore, if the derivative transaction qualifies for and is designated as a normal purchase and sale, it is exempted from the fair value accounting requirements of SFAS No. 133 and is accounted for using traditional accrual accounting. Our derivatives that hedge our commodity price risks involve our normal business activities, which include the sale of natural gas, natural gas liquids, oil and carbon dioxide, and these derivatives have been designated as cash flow hedges as defined by SFAS No. 133. SFAS No. 133 designates derivatives that hedge exposure to variable cash flows of forecasted transactions as cash flow hedges and the effective portion of the derivative's gain or loss is initially reported as a component of other comprehensive income (outside earnings) and subsequently reclassified into earnings when the forecasted transaction affects earnings. The ineffective portion of the gain or loss is reported in earnings immediately. See Note 14 for more information on our risk management activities. 3. Acquisitions and Joint Ventures During 2002, 2003 and 2004, we completed or made adjustments for 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 allocation of assets and liabilities may be adjusted to reflect the final determined amounts during a short period of time following the acquisition. The results of operations from these acquisitions are included in our consolidated financial statements from the acquisition date. 116 <PAGE> <TABLE> <CAPTION> <S> <C> <C> <C> <C> <C> <C> Allocation of Purchase Price ------------------------------------------------------------------- (in millions) ------------------------------------------------------------------- Property Deferred Purchase Current Plant & Charges Minority Ref. Date Acquisition Price Assets Equipment & Other Goodwill Interest ----- -------------------------------------------------- ------------- --------- ----------- --------- --------- ---------- (1) 1/02 Kinder Morgan Materials Services LLC...... $ 14.1 $ 0.9 $ 13.2 $- $- $- (2) 1/02 66 2/3% Interest in Intl. MarineTerminals. 40.5 6.6 31.8 0.1 - 2.0 (3) 1/02 Kinder Morgan Tejas....................... 878.5 56.5 674.1 - 147.9 - (4) 5/02 Milwaukee Bagging Operations.............. 8.5 0.1 3.1 - 5.3 - (5) 5/02 Trailblazer Pipeline Company.............. 80.1 - 41.7 - 15.0 23.4 (6) 9/02 Owensboro Gateway Terminal................ 7.7 0.0 4.3 0.1 3.3 - (7) 9/02 IC Terminal Holdings Company.............. 17.7 0.1 14.3 3.3 - - (8) 1/03 Bulk Terminals from M.J. Rudolph.......... 31.3 0.1 18.2 0.1 12.9 - (9) 6/03 MKM Partners, L.P......................... 25.2 - 25.2 - - - (10) 8/03 Interest in Red Cedar Gathering Company... 10.0 - - 10.0 - - (11) 10/03 Shell Products Terminals.................. 20.0 - 20.0 - - - (12) 11/03 Yates Field Unit and Carbon Dioxide Assets 259.9 3.6 256.6 - - (0.3) (13) 11/03 Interest in MidTex Gas Storage Co., LLP... 17.5 - 11.9 - - 5.6 (14) 12/03 ConocoPhillips Products Terminals......... 15.3 - 14.3 1.0 - - (15) 12/03 Tampa, Florida Bulk Terminals............. 29.1 - 29.1 - - - (16) 3/04 ExxonMobil Products Terminals............. 50.9 - 50.9 - - - (17) 8/04 Kinder Morgan Wink Pipeline, L.P.......... 100.3 0.1 100.2 - - - (18) 10/04 Interest in Cochin Pipeline System........ 10.9 - 10.9 - - - (19) 10/04 Kinder Morgan River Terminals LLC......... 89.6 9.9 70.2 3.1 6.4 - (20) 11/04 Charter Products Terminals................ 75.2 3.7 71.8 0.8 - (1.1) (21) 11/04 TransColorado Gas Transmission Company.... 284.5 2.0 280.6 1.9 - - (22) 12/04 Kinder Morgan Fairless Hills Terminal..... $ 7.5 $ - $ 6.2 $1.3 $- $- </TABLE> (1) Kinder Morgan Materials Services LLC Effective January 1, 2002, we acquired all of the equity interests of Kinder Morgan Materials Services LLC, formerly Laser Materials Services LLC, for an aggregate consideration of $14.1 million, consisting of approximately $10.8 million in cash and the assumption of approximately $3.3 million of liabilities, including long-term debt of $0.4 million. Kinder Morgan Materials Services LLC currently operates approximately 60 transload facilities in 20 states. The facilities handle dry-bulk products, including aggregates, plastics and liquid chemicals. The acquisition of Kinder Morgan Materials Services LLC expanded our growing terminal operations and is part of our Terminals business segment. (2) 66 2/3% Interest in International Marine Terminals Effective January 1, 2002, we acquired a 33 1/3% interest in International Marine Terminals Partnership, referred to in this report as IMT, from Marine Terminals Incorporated. Effective February 1, 2002, we acquired an additional 33 1/3% interest in IMT from Glenn Springs Holdings, Inc. Our combined purchase price was approximately $40.5 million, including the assumption of $40 million of long-term debt. IMT is a partnership that operates a bulk terminal site in Port Sulphur, Louisiana. This terminal is a multi-purpose import and export facility, which handles approximately 10 million tons annually of bulk products including coal, petroleum coke, iron ore and barite. The acquisition complements our existing bulk terminal assets. IMT is part of our Terminals business segment. (3) Kinder Morgan Tejas Effective January 31, 2002, we acquired all of the equity interests of Tejas Gas, LLC, a wholly-owned subsidiary of InterGen (North America), Inc., for an aggregate consideration of approximately $878.5 million, consisting of $727.1 million in cash and the assumption of $151.4 million of liabilities. Tejas Gas, LLC consists primarily of a 3,400-mile natural gas intrastate pipeline system that extends from south Texas along the Mexico border and the Texas Gulf Coast to near the Louisiana border and north from near Houston to east Texas. The acquisition expanded our natural gas operations within the State of Texas. The acquired assets are referred to as Kinder Morgan Tejas in this report and are included in our Natural Gas Pipelines business segment. The combination of these 117 <PAGE> systems is part of our Texas intrastate natural gas pipeline group. Our allocation to assets acquired and liabilities assumed was based on an appraisal of fair market values. The $147.9 million of goodwill was assigned to our Natural Gas Pipelines business segment and the entire amount is expected to be deductible for tax purposes. (4) Milwaukee Bagging Operations Effective May 1, 2002, we purchased a bagging operation facility adjacent to our Milwaukee, Wisconsin dry-bulk terminal for $8.5 million. The purchase enhances the operations at our Milwaukee bulk terminal, which is capable of handling up to 150,000 tons per year of fertilizer and salt for de-icing and livestock purposes. The Milwaukee bagging operations are included in our Terminals business segment. The $5.3 million of goodwill was assigned to our Terminals business segment and the entire amount is expected to be deductible for tax purposes. (5) Trailblazer Pipeline Company On May 6, 2002, we acquired the remaining 33 1/3% ownership interest in Trailblazer Pipeline Company that we did not already own from Enron Trailblazer Pipeline Company for an aggregate consideration of $80.1 million. We now own 100% of Trailblazer Pipeline Company. In May 2002, we paid $68 million to an affiliate of Enron Corp., and during the first quarter of 2002, we paid $12.1 million to CIG Trailblazer Gas Company, an affiliate of El Paso Corporation, in exchange for CIG's relinquishment of its rights to become a 7% to 8% equity owner in Trailblazer Pipeline Company in mid-2002. Trailblazer Pipeline Company is an Illinois partnership that owns and operates a 436-mile natural gas pipeline system that traverses from Colorado through southeastern Wyoming to Beatrice, Nebraska. Trailblazer Pipeline Company has a current certificated capacity of 846 million cubic feet per day of natural gas. The $15.0 million of goodwill was assigned to our Natural Gas Pipelines business segment and the entire amount is expected to be deductible for tax purposes. (6) Owensboro Gateway Terminal Effective September 1, 2002, we acquired the Lanham River Terminal near Owensboro, Kentucky and related equipment for $7.7 million. In September 2002, we paid approximately $7.2 million and established a $0.5 million purchase price retention liability to be paid at the later of: (i) one year following the acquisition, or (ii) the day we received consent to the assignment of a contract between the seller and the New York Mercantile Exchange, Inc. We paid the $0.5 million liability in September 2003. The facility is one of the nation's largest storage and handling points for bulk aluminum. The terminal also handles a variety of other bulk products, including petroleum coke, lime and de-icing salt. The terminal is situated on a 92-acre site along the Ohio River, and the purchase expanded our presence along the river, complementing our existing facilities located near Cincinnati, Ohio and Moundsville, West Virginia. We refer to the acquired terminal as our Owensboro Gateway Terminal and we include its operations in our Terminals business segment. The $3.3 million of goodwill was assigned to our Terminals business segment and the entire amount is expected to be deductible for tax purposes. (7) IC Terminal Holdings Company Effective September 1, 2002, we acquired all of the shares of the capital stock of IC Terminal Holdings Company from the Canadian National Railroad. Our purchase price was $17.7 million, consisting of $17.4 million in cash and the assumption of $0.3 million in liabilities. The total purchase price decreased $0.2 million in the third quarter of 2003 primarily due to adjustments in the amount of working capital items assumed on the acquisition date. The acquisition included the former ICOM marine terminal in St. Gabriel, Louisiana. The St. Gabriel facility has 400,000 barrels of liquids storage capacity and a related pipeline network. The acquisition further expanded our terminal businesses along the Mississippi River. The acquired terminal is referred to as the Kinder Morgan St. Gabriel terminal, and we include its operations in our Terminals business segment. (8) Bulk Terminals from M.J. Rudolph Effective January 1, 2003, we acquired long-term lease contracts from New York-based M.J. Rudolph Corporation to operate four bulk terminal facilities at major ports along the East Coast and in the southeastern United States. The acquisition also included the purchase of certain assets that provide stevedoring services at these locations. The aggregate cost of the acquisition was approximately $31.3 million. On December 31, 2002, we paid 118 <PAGE> $29.9 million, and in the first quarter of 2003, we paid the remaining $1.4 million. The acquired operations serve various terminals located at the ports of New York and Baltimore, along the Delaware River in Camden, New Jersey, and in Tampa Bay, Florida. Combined, these facilities transload nearly four million tons annually of products such as fertilizer, iron ore and salt. The acquisition expanded our growing Terminals business segment and complements certain of our existing terminal facilities. We include its operations in our Terminals business segment, and in our final analysis, it was considered reasonable to allocate a portion of our purchase price to goodwill given the substance of this transaction, including expected benefits from integrating this acquisition with our existing assets. The $12.9 million of goodwill was assigned to our Terminals business segment and the entire amount is expected to be deductible for tax purposes. (9) MKM Partners, L.P. Effective June 1, 2003, we acquired the MKM joint venture's 12.75% ownership interest in the SACROC oil field unit for an aggregate consideration of $25.2 million, consisting of $23.3 million in cash and the assumption of $1.9 million of liabilities. The SACROC unit is one of the largest and oldest oil fields in the United States using carbon dioxide flooding technology. This transaction increased our ownership interest in the SACROC unit to approximately 97%. On June 20, 2003, we signed an agreement with subsidiaries of Marathon Oil Corporation to dissolve MKM Partners, L.P., a joint venture we formed on January 1, 2001 with subsidiaries of Marathon Oil Company. The joint venture assets consisted of a 12.75% interest in the SACROC oil field unit, which we acquired June 1, 2003 as described above, and a 49.9% interest in the Yates Field unit, both of which are in the Permian Basin of West Texas. The MKM joint venture was owned 85% by subsidiaries of Marathon Oil Company and 15% by Kinder Morgan CO2 Company, L.P. It was dissolved effective June 30, 2003, and the net assets were distributed to partners in accordance with its partnership agreement. (10) Interest in Red Cedar Gas Gathering Company Effective August 1, 2003, we acquired reversionary interests in the Red Cedar Gas Gathering Company held by the Southern Ute Indian Tribe. Our purchase price was $10.0 million. The 4% reversionary interests were scheduled to take effect September 1, 2004 and September 1, 2009. With the elimination of these reversions, our ownership interest in Red Cedar will be maintained at 49% in the future. The purchase price was allocated to our equity investment in Red Cedar, included with our equity method goodwill. (11) Shell Products Terminals Effective October 1, 2003, we acquired five refined petroleum products terminals in the western United States for approximately $20.0 million from Shell Oil Products U.S. As of our acquisition date, we expected to invest an additional $8.0 million in the facilities. The terminals are located in Colton and Mission Valley, California; Phoenix and Tucson, Arizona; and Reno, Nevada. Combined, the terminals have 28 storage tanks with total capacity of approximately 700,000 barrels for gasoline, diesel fuel and jet fuel. As part of the transaction, Shell has entered into a long-term contract to store products in the terminals. The acquisition enhances our Pacific operations and complements our existing West Coast Terminals. The acquired operations are included as part of our Pacific operations and our Products Pipelines business segment. (12) Yates Field Unit and Carbon Dioxide Assets Effective November 1, 2003, we acquired certain assets in the Permian Basin of West Texas from a subsidiary of Marathon Oil Corporation. Our purchase price was approximately $259.9 million, consisting of $230.2 million in cash and the assumption of $29.7 million of liabilities. The assets acquired consisted of the following: o Marathon's approximate 42.5% interest in the Yates oil field unit. We previously owned a 7.5% ownership interest in the Yates field unit and we now operate the field; o Marathon's 100% interest in the crude oil gathering system surrounding the Yates field unit; and 119 <PAGE> o Kinder Morgan Carbon Dioxide Transportation Company, formerly Marathon Carbon Dioxide Transportation Company. Kinder Morgan Carbon Dioxide Transportation Company owns a 65% ownership interest in the Pecos Carbon Dioxide Pipeline Company, which owns a 25-mile carbon dioxide pipeline. We previously owned a 4.27% ownership interest in the Pecos Carbon Dioxide Pipeline Company and accounted for this investment under the cost method of accounting. After the acquisition of our additional 65% interest in Pecos, its financial results are included in our consolidated results and we recognize the appropriate minority interest. Together, the acquisition of these assets complemented our existing carbon dioxide assets in the Permian Basin, increased our working interest in the Yates field to nearly 50% and allowed us to become the operator of the field. We recorded a deferred tax liability of $0.8 million in August 2004 to properly reflect the tax obligations of Kinder Morgan Carbon Dioxide Transportation Company. The acquired operations are included as part of our CO2 business segment. (13) Interest in MidTex Gas Storage Company, LLP Effective November 1, 2003, we acquired the remaining approximate 32% ownership interest in MidTex Gas Storage Company, LLP that we did not already own from an affiliate of NiSource Inc. Our combined purchase price was approximately $17.5 million, consisting of $15.8 million in cash and the assumption of $1.7 million of debt. The debt represented a MidTex note payable that was to be paid by the former partner. We now own 100% of MidTex Gas Storage Company, LLP. MidTex Gas Storage Company, LLP is a Texas limited liability partnership that owns two salt dome natural gas storage facilities located in Matagorda County, Texas. MidTex's operations are included as part of our Natural Gas Pipelines business segment. (14) ConocoPhillips Products Terminals Effective December 11, 2003, we acquired seven refined petroleum products terminals located in the southeastern United States from ConocoPhillips Company and Phillips Pipe Line Company. Our purchase price was approximately $15.3 million, consisting of approximately $14.1 million in cash and $1.2 million in assumed liabilities. The terminals are located in Charlotte and Selma, North Carolina; Augusta and Spartanburg, South Carolina; Albany and Doraville, Georgia; and Birmingham, Alabama. We fully own and operate all of the terminals except for the Doraville, Georgia facility, which is operated and owned 70% by Citgo. As of our acquisition date, we expected to invest an additional $1.3 million in the facilities. Combined, the terminals have 35 storage tanks with total capacity of approximately 1.15 million barrels for gasoline, diesel fuel and jet fuel. As part of the transaction, ConocoPhillips entered into a long-term contract to use the terminals. The contract consists of a five-year terminaling agreement, an intangible asset which we valued at $1.0 million. The acquisition broadened our refined petroleum products operations in the southeastern United States as three of the terminals are connected to the Plantation pipeline system, which is operated and owned 51% by us. The acquired operations are included as part of our Products Pipelines business segment. (15) Tampa, Florida Bulk Terminals In December 2003, we acquired two bulk terminal facilities in Tampa, Florida for an aggregate consideration of approximately $29.1 million, consisting of $26.3 million in cash and $2.8 million in assumed liabilities. As of our acquisition date, we expected to invest an additional $16.9 million in the facilities. The principal facility purchased was a marine terminal acquired from a subsidiary of The Mosaic Company, formerly IMC Global, Inc. We entered into a long-term agreement with Mosaic pursuant to which Mosaic will be the primary user of the facility, which we will operate and refer to as the Kinder Morgan Tampaplex terminal. The terminal sits on a 114-acre site, and serves as a storage and receipt point for imported ammonia, as well as an export location for dry bulk products, including fertilizer and animal feed. We closed on the Tampaplex portion of this transaction on December 23, 2003. The second facility purchased was the former Nitram, Inc. bulk terminal, which we have converted to an inland bulk storage warehouse facility for overflow cargoes from our Port Sutton, Florida import terminal. We closed on the Nitram portion of this transaction on December 10, 2003. We recorded our final purchase price adjustments in the third quarter of 2004. The adjustments included the removal of a property tax liability in the amount of $0.6 million, which had been established in December 2003 pending final determination of assumed tax obligations. The 120 <PAGE> acquired operations are included as part of our Terminals business segment and complement our existing businesses in the Tampa area by generating additional fee-based income. (16) ExxonMobil Products Terminals Effective March 9, 2004, we acquired seven refined petroleum products terminals in the southeastern United States from Exxon Mobil Corporation. Our purchase price was approximately $50.9 million, consisting of approximately $48.2 million in cash and $2.7 million in assumed liabilities. The terminals are located in Collins, Mississippi; Knoxville, Tennessee; Charlotte and Greensboro, North Carolina; and Richmond, Roanoke and Newington, Virginia. Combined, the terminals have a total storage capacity of approximately 3.2 million barrels for gasoline, diesel fuel and jet fuel. As part of the transaction, ExxonMobil entered into a long-term contract to store products at the terminals. As of our acquisition date, we expected to invest an additional $1.2 million in the facilities. The acquisition enhanced our terminal operations in the Southeast and complemented our December 2003 acquisition of seven products terminals from ConocoPhillips Company and Phillips Pipe Line Company. The acquired operations are included as part of our Products Pipelines business segment. (17) Kinder Morgan Wink Pipeline, L.P. Effective August 31, 2004, we acquired all of the partnership interests in Kaston Pipeline Company, L.P. from KPL Pipeline Company, LLC and RHC Holdings, L.P. for a purchase price of approximately $100.3 million, consisting of $89.9 million in cash and the assumption of approximately $10.4 million of liabilities, including debt of $9.5 million. In September 2004, we paid the $9.5 million outstanding debt balance. We renamed the limited partnership Kinder Morgan Wink Pipeline, L.P., and since August 31, 2004, we have included its results as part of our CO2 business segment. The acquisition included a 450-mile crude oil pipeline system, consisting of four mainline sections, numerous gathering systems and truck off-loading stations. The mainline sections, all in Texas, have a total capacity of 115,000 barrels of crude oil per day. As part of the transaction, we entered into a long-term throughput agreement with Western Refining Company, L.P. to transport crude oil into Western's 107,000 barrel per day refinery in El Paso, Texas. As of our acquisition date, we expected to invest approximately $11.0 million over the next five years to upgrade the assets. The acquisition allows us to better manage crude oil deliveries from our oil field interests in West Texas. (18) Interest in Cochin Pipeline Effective October 1, 2004, we acquired an additional undivided 5% interest in the Cochin Pipeline System from subsidiaries of ConocoPhillips Corporation for approximately $10.9 million. On November 3, 2000, we acquired from NOVA Chemicals Corporation an undivided 32.5% interest in the Cochin Pipeline System for approximately $120.5 million. On June 20, 2001, we acquired an additional 2.3% ownership interest from Shell Canada Limited for approximately $8.1 million, and effective December 31, 2001, we purchased an additional 10% ownership interest from NOVA Chemicals Corporation for approximately $29 million. We now own approximately 49.8% of the Cochin Pipeline System. A subsidiary of BP owns the remaining interest and operates the pipeline. We record our proportional share of joint venture revenues and expenses and cost of joint venture assets with respect to the Cochin Pipeline System as part of our Products Pipelines business segment. Our allocation of the purchase price to assets acquired is preliminary, pending any minor adjustments that may be necessary under the purchase and sale agreement. We expect to make any final adjustments by the end of the first quarter of 2005. (19) Kinder Morgan River Terminals LLC Effective October 6, 2004, we acquired Global Materials Services LLC and its consolidated subsidiaries from Mid-South Terminal Company, L.P. for approximately $89.6 million, consisting of $31.8 million in cash and $57.8 million of assumed liabilities, including debt of $33.7 million. Global Materials Services LLC, which we renamed Kinder Morgan River Terminals LLC, operates a network of 21 river terminals and two rail transloading facilities primarily located along the Mississippi River system. The network provides loading, storage and unloading points for various bulk commodity imports and exports. As of our acquisition date, we expected to invest an additional $9.4 million over the next two years to expand and upgrade the terminals, which are located in 11 Mid-Continent states. The acquisition further expands and diversifies our customer base and complements our existing terminal facilities located along the lower-Mississippi River system. The acquired terminals are included in our Terminals 121 <PAGE> business segment. Our allocation of the purchase price to assets acquired and liabilities assumed is preliminary, pending final purchase price adjustments that may be necessary following an independent appraisal of fair market values. We expect the appraisal to be completed by the end of the first quarter of 2005. The $6.4 million of goodwill was assigned to our Terminals business segment and the entire amount is expected to be deductible for tax purposes. (20) Charter Products Terminals Effective November 5, 2004, we acquired ownership interests in nine refined petroleum products terminals in the southeastern United States from Charter Terminal Company and Charter-Triad Terminals, LLC for approximately $75.2 million, consisting of $72.4 million in cash and $2.8 million of assumed liabilities. Three terminals are located in Selma, North Carolina, and the remaining facilities are located in Greensboro and Charlotte, North Carolina; Chesapeake and Richmond, Virginia; Athens, Georgia; and North Augusta, South Carolina. We fully own seven of the terminals and jointly own the remaining two. The nine facilities have a combined 3.2 million barrels of storage. As of our acquisition date, we expected to invest an additional $2 million over the next two years to upgrade the facilities. All of the terminals are connected to products pipelines owned by either Plantation Pipe Line Company or Colonial Pipeline Company. The acquisition complements the existing terminals we own in the Southeast and increased our southeast terminal storage capacity 76% (to 7.7 million barrels) and terminal throughput capacity 62% (to over 340,000 barrels per day). The acquired terminals are included as part of our Products Pipelines business segment. Our allocation of the purchase price to assets acquired and liabilities assumed is preliminary, pending final purchase price adjustments that may be necessary following an independent appraisal of fair market values. We expect the appraisal to be completed by the end of the first quarter of 2005. (21) TransColorado Gas Transmission Company Effective November 1, 2004, we acquired all of the partnership interests in TransColorado Gas Transmission Company from two wholly-owned subsidiaries of KMI. TransColorado Gas Transmission Company, a Colorado general partnership referred to in this report as TransColorado, owned assets valued at approximately $284.5 million. As consideration for TransColorado, we paid to KMI $211.2 million in cash and approximately $64.0 million in units, consisting of 1,400,000 common units. We also assumed liabilities of approximately $9.3 million. The purchase price for this transaction was determined by the boards of directors of KMR and our general partner, and KMI based on valuation parameters used in the acquisition of similar assets. The transaction was approved unanimously by the independent members of the boards of directors of both KMR and our general partner, and KMI, with the benefit of advice of independent legal and financial advisors, including the receipt of fairness opinions from separate investment banks, specifically Goldman, Sachs & Co. and Morgan Stanley & Co. TransColorado owns a 300-mile interstate natural gas pipeline that originates in the Piceance Basin of western Colorado and runs to the Blanco Hub in northwest New Mexico. The acquisition expanded our natural gas operations within the Rocky Mountain region and the acquired operations are included as part of our Natural Gas Pipelines business segment. (22) Kinder Morgan Fairless Hills Terminal Effective December 1, 2004, we acquired substantially all of the assets used to operate the major port distribution facility located at the Fairless Industrial Park in Bucks County, Pennsylvania for an aggregate consideration of approximately $7.5 million, consisting of $7.2 million in cash and $0.3 million in assumed liabilities. The facility, referred to as our Kinder Morgan Fairless Hills Terminal, was purchased from Novolog Bucks County, Inc. and is located on the Delaware River. It is the largest port on the East Coast for the handling of semi-finished steel slabs, which are used as feedstock by domestic steel mills. The port operations at Fairless Hills also include the handling of other types of steel and specialized cargo that caters to the construction industry and service centers that use steel sheet and plate. The terminal expanded our presence along the Delaware River and complements our existing Mid-Atlantic terminal facilities. As of our acquisition date, we expected to invest an additional $8.3 million in the facility. We include its operations in our Terminals business segment. 122 <PAGE> Pro Forma Information The following summarized unaudited pro forma consolidated income statement information for the years ended December 31, 2004 and 2003, assumes that all of the acquisitions we have made and joint ventures we have entered into since January 1, 2003, including the ones listed above, had occurred as of January 1, 2003. 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 these acquisitions and joint ventures as of January 1, 2003 or the results that will be attained in the future. Amounts presented below are in thousands, except for the per unit amounts: Pro Forma Year Ended December 31, --------------------- 2004 2003 ---------- ---------- (Unaudited) Revenues................................................ $8,049,660 $6,872,721 Operating Income........................................ 1,015,229 913,716 Income Before Cumulative Effect of a Change in Accounting Principle................................... 868,759 786,247 Net Income.............................................. $ 868,759 $ 789,712 Basic and Diluted Limited Partners' Net Income per unit: Income Before Cumulative Effect of a Change in Accounting Principle................................ $ 2.38 $ 2.44 Net Income............................................ $ 2.38 $ 2.46 4. Change in Accounting for Asset Retirement Obligations In August 2001, the Financial Accounting Standards Board issued SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 provides accounting and reporting guidance for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction or normal operation of a long-lived asset. The provisions of this Statement are effective for fiscal years beginning after June 15, 2002. We adopted SFAS No. 143 on January 1, 2003. SFAS No. 143 requires companies to record a liability relating to the retirement and removal of assets used in their businesses. Its primary impact on us was to change the method of accruing for oil and gas production site restoration costs related to our CO2 business segment. Prior to January 1, 2003, we accounted for asset retirement obligations for this business in accordance with SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies." Under SFAS No. 143, the fair value of asset retirement obligations are recorded as liabilities on a discounted basis when they are incurred, which is typically at the time the assets are installed or acquired. Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities will be accreted for the change in their present value and the initial capitalized costs will be depreciated over the useful lives of the related assets. The liabilities are eventually extinguished when the asset is taken out of service. Specifically, upon adoption of this Statement, an entity must recognize the following items in its balance sheet: o a liability for any existing asset retirement obligations adjusted for cumulative accretion to the date of adoption; o an asset retirement cost capitalized as an increase to the carrying amount of the associated long-lived asset; and o accumulated depreciation on that capitalized cost. Amounts resulting from initial application of this Statement are measured using current information, current assumptions and current interest rates. The amount recognized as an asset retirement cost is measured as of the date the asset retirement obligation was incurred. Cumulative accretion and accumulated depreciation are measured for the time period from the date the liability would have been recognized had the provisions of this Statement been in effect to the date of adoption of this Statement. The cumulative effect adjustment for this change in accounting principle resulted in income of $3.4 million in the first quarter of 2003. Furthermore, as required by SFAS No. 143, we recognized the cumulative effect of initially applying SFAS No. 143 as a change in accounting principle as described in Accounting Principles Board Opinion 20, "Accounting Changes." The cumulative effect adjustment resulted from the difference between the amounts 123 <PAGE> recognized in our consolidated balance sheet prior to the application of SFAS No. 143 and the net amount recognized in our consolidated balance sheet pursuant to SFAS No. 143. In our CO2 business segment, we are required to plug and abandon oil and gas wells that have been removed from service and to remove our surface wellhead equipment and compressors. As of December 31, 2004 and 2003, we have recognized asset retirement obligations relating to these requirements at existing sites within our CO2 segment in the aggregate amounts of $34.7 million and $32.7 million, respectively. In our Natural Gas Pipelines business segment, if we were to cease providing utility services, we would be required to remove surface facilities from land belonging to our customers and others. Our Texas intrastate natural gas pipeline group has various condensate drip tanks and separators located throughout its natural gas pipeline systems, as well as inactive gas processing plants, laterals and gathering systems which are no longer integral to the overall mainline transmission systems, and asbestos-coated underground pipe which is being abandoned and retired. Our Kinder Morgan Interstate Gas Transmission system has compressor stations which are no longer active and other miscellaneous facilities, all of which have been officially abandoned. We believe we can reasonably estimate both the time and costs associated with the retirement of these facilities. As of December 31, 2004 and 2003, we have recognized asset retirement obligations relating to the businesses within our Natural Gas Pipelines segment in the aggregate amounts of $3.6 million and $3.0 million, respectively. We have included $0.8 million of our total asset retirement obligations as of both December 31, 2004 and December 31, 2003 with "Accrued other current liabilities" in our accompanying consolidated balance sheets. The remaining $37.5 million obligation as of December 31, 2004 and $34.9 million obligation as of December 31, 2003 are reported separately as non-current liabilities in our accompanying consolidated balance sheets. No assets are legally restricted for purposes of settling our asset retirement obligations. A reconciliation of the beginning and ending aggregate carrying amount of our asset retirement obligations for each of years ended December 31, 2004 and 2003 is as follows (in thousands): Year Ended December 31, ------------------------------- 2004 2003 ------------ ------------ Balance at beginning of period..........$ 35,708 $ - Initial ARO balance upon adoption....... - 14,125 Liabilities incurred.................... 1,157 12,911 Liabilities settled..................... (672) (1,056) Accretion expense....................... 2,081 1,028 Revisions in estimated cash flows....... - 8,700 ------------ ------------ Balance at end of period................$ 38,274 $ 35,708 ============ ============ Pro Forma Information Had the provisions of SFAS No. 143 been in effect prior to January 1, 2003, our net income and associated per unit amounts, and the amount of our liability for asset retirement obligations, would have been as follows (in thousands, except per unit amounts): Pro Forma Year Ended -------------------- December 31, 2002 ----------------- (Unaudited) Reported income before cumulative effect of a change in accounting principle..................................... $608,377 Adjustments from change in accounting for asset retirement obligations.............................................. (1,161) --------- Adjusted income before cumulative effect of a change in accounting principle..................................... $607,216 ======== Reported income before cumulative effect of a change in accounting principle per unit (fully diluted).............. $ 1.96 ======== Adjusted income before cumulative effect of a change in accounting principle per unit (fully diluted).............. $ 1.95 ======== December 31, ------------ 2002 ------ Liability for asset retirement obligations.... $14,125 ======= 124 <PAGE> 5. Income Taxes Components of the income tax provision applicable to continuing operations for federal, foreign and state taxes are as follows (in thousands): Year Ended December 31, ------------------------------ 2004 2003 2002 ---------- ---------- ------- Taxes currently payable: Federal............. $ 7,515 $ 437 $ 15,855 State............... 1,497 1,131 3,116 Foreign............. 70 25 147 -------- -------- --------- Total............... 9,082 1,593 19,118 Taxes deferred: Federal............. 5,694 11,650 (3,280) State............... 883 1,939 (555) Foreign............. 4,067 1,449 - -------- -------- --------- Total............... 10,644 15,038 (3,835) -------- -------- --------- Total tax provision... $ 19,726 $ 16,631 $ 15,283 ======== ======== ========= Effective tax rate.... 2.3% 2.3% 2.4% The difference between the statutory federal income tax rate and our effective income tax rate is summarized as follows: Year Ended December 31, ------------------------- 2004 2003 2002 ------- ------- ------- Federal income tax rate....................... 35.0% 35.0% 35.0% Increase (decrease) as a result of: Partnership earnings not subject to tax..... (35.0)% (35.0)% (35.0)% Corporate subsidiary earnings subject to tax 0.5% 0.5% 0.6% Income tax expense attributable to corporate equity earnings........................... 1.2% 1.5% 1.6% Income tax expense attributable to foreign corporate earnings........................ 0.5% 0.2% - State taxes................................. 0.1% 0.1% 0.2% ------- ------- ------- Effective tax rate............................ 2.3% 2.3% 2.4% ======= ======= ======== Deferred tax assets and liabilities result from the following (in thousands): December 31, ----------------- 2004 2003 -------- ------- Deferred tax assets: Book accruals.................................... $ 1,349 $ 1,424 Net Operating Loss/Alternative minimum tax credits 7,138 10,797 Other............................................ 1,472 - -------- ------- Total deferred tax assets.......................... 9,959 12,221 Deferred tax liabilities: Property, plant and equipment.................... 59,277 50,327 Other............................................ 7,169 - -------- ------- Total deferred tax liabilities..................... 66,446 50,327 -------- ------- Net deferred tax liabilities....................... $ 56,487 $38,106 ======== ======= We had available, at December 31, 2004, approximately $0.3 million of alternative minimum tax credit carryforwards, which are available indefinitely, and $6.8 million of net operating loss carryforwards, which will expire between the years 2005 and 2024. We believe it is more likely than not that the net operating loss carryforwards will be utilized prior to their expiration; therefore, no valuation allowance is necessary. 6. Property, Plant and Equipment Property, plant and equipment consists of the following (in thousands): 125 <PAGE> December 31, ------------------------ 2004 2003 ----------- ----------- Natural gas, liquids and carbon dioxide pipelines....$ 3,903,021 $ 3,458,736 Natural gas, liquids and carbon dioxide pipeline station equipment......................... 3,443,817 2,908,273 Coal and bulk tonnage transfer, storage and services. 512,024 359,088 Natural gas and transmix processing.................. 105,375 100,778 Other................................................ 511,787 330,982 Accumulated depreciation and depletion............... (947,660) (641,914) ----------- ----------- 7,528,364 6,515,943 Land and land right-of-way........................... 371,172 339,579 Construction work in process......................... 269,144 236,036 ----------- ----------- Property, Plant and Equipment, net...................$ 8,168,680 $ 7,091,558 =========== =========== Depreciation and depletion expense charged against property, plant and equipment consists of the following (in thousands): 2004 2003 2002 ------- -------- -------- Depreciation and depletion expense.... $285,351 $217,401 $171,461 7. Investments Our significant equity investments as of December 31, 2004 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%). We own approximately 51% of Plantation Pipe Line Company, and an affiliate of ExxonMobil owns the remaining approximate 49%. Each investor has an equal number of directors on Plantation's board of directors, and board approval is required for certain corporate actions that are considered participating rights. Therefore, we do not control Plantation Pipe Line Company, and we account for our investment under the equity method of accounting. On January 1, 2002, Kinder Morgan CO2 Company, L.P. owned a 15% interest in MKM Partners, L.P., a joint venture with Marathon Oil Company. The remaining 85% interest in MKM Partners was owned by subsidiaries of Marathon Oil Company. The joint venture assets consisted of a 12.75% interest in the SACROC oil field unit and a 49.9% interest in the Yates field unit, both of which are in the Permian Basin of West Texas. We accounted for our 15% investment in the joint venture under the equity method of accounting because our ownership interest included 50% of the joint venture's general partner interest, and the ownership of this general partner interest gave us the ability to exercise significant influence over the operating and financial policies of the joint venture. Effective June 1, 2003, we acquired the MKM joint venture's 12.75% ownership interest in the SACROC unit for $23.3 million and the assumption of $1.9 million of liabilities. On June 20, 2003, we signed an agreement with subsidiaries of Marathon Oil Corporation to dissolve MKM Partners, L.P. The partnership's dissolution was effective June 30, 2003, and the net assets were distributed to partners in accordance with its partnership agreement. Our interests in the SACROC unit and the Yates field unit, including the incremental interest acquired in November 2003, are accounted for using the proportional method of consolidation for oil and gas operations. In September 2003, we paid $10.0 million to acquire reversionary interests in the Red Cedar Gas Gathering Company. The 4% reversionary interests were held by the Southern Ute Indian Tribe and were scheduled to take effect September 1, 2004 and September 1, 2009. With the elimination of these reversions, our ownership interest in Red Cedar will be maintained at 49% in the future. For more information on our acquisitions, see Note 3. 126 <PAGE> Our total investments consisted of the following (in thousands): December 31, ------------------- 2004 2003 -------- -------- Plantation Pipe Line Company........................... $216,142 $219,349 Red Cedar Gathering Company............................ 124,209 114,176 Thunder Creek Gas Services, LLC........................ 37,122 37,245 Cortez Pipeline Company................................ 15,503 12,591 Coyote Gas Treating, LLC............................... 12,964 13,502 Heartland Pipeline Company............................. 5,106 5,109 All Others............................................. 2,209 2,373 -------- -------- Total Equity Investments............................... $413,255 $404,345 ======== ======== Our earnings from equity investments were as follows (in thousands): Year Ended December 31, ------------------------------- 2004 2003 2002 -------- -------- -------- Cortez Pipeline Company............. $ 34,179 $ 32,198 $ 28,154 Plantation Pipe Line Company........ 25,879 27,983 26,426 Red Cedar Gathering Company......... 14,679 18,571 19,082 Thunder Creek Gas Services, LLC..... 2,828 2,833 2,154 Coyote Gas Treating, LLC............ 2,453 2,608 2,651 Heartland Pipeline Company.......... 1,369 973 998 MKM Partners, L.P................... - 5,000 8,174 All Others.......................... 1,803 2,033 1,619 -------- -------- -------- Total............................... $ 83,190 $ 92,199 $ 89,258 ======== ======== ======== Amortization of excess costs........ $ (5,575) $ (5,575) $ (5,575) ======== ======== ======== Summarized combined unaudited financial information for our significant equity investments (listed above) is reported below (in thousands; amounts represent 100% of investee financial information): Year Ended December 31, -------------------------------- Income Statement 2004 2003 2002 - ---------------------------------- --------- -------- --------- Revenues...................................... $ 418,186 $467,871 $ 505,602 Costs and expenses............................ 265,819 295,931 309,291 --------- -------- --------- Earnings before extraordinary items and cumulative effect of a change in accounting principle................................... 152,367 171,940 196,311 ========= ======== ========= Net income.................................... $152,367 $168,167 $196,311 ========= ======== ========= December 31, ---------------------- Balance Sheet 2004 2003 -------------------------- ----------- ---------- Current assets............ $ 107,954 $ 93,709 Non-current assets........ 696,493 684,754 Current liabilities....... 218,922 377,535 Non-current liabilities... 364,406 209,468 Partners'/owners' equity.. $ 221,119 $ 191,460 8. Intangibles Under ABP No. 18, any premium paid by an investor, which is analogous to goodwill, must be identified. Under prior rules, excess cost over underlying fair value of net assets accounted for under the equity method, referred to as equity method goodwill, would have been amortized, however, under SFAS No. 142, equity method goodwill is not subject to amortization but rather to impairment testing pursuant to ABP No. 18. The impairment test under APB No. 18 considers whether the fair value of the equity investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. This test requires equity method investors to continue to assess impairment of investments in investees by considering whether declines in the fair values of those investments, versus carrying values, may be other than temporary in nature. The caption "Investments" in our accompanying consolidated balance sheets includes $150.3 million of equity method goodwill as of both December 31, 2004, and December 31, 2003. 127 <PAGE> Our intangible assets include goodwill, lease value, contracts and agreements. All of our intangible assets having definite lives are being amortized on a straight-line basis over their estimated useful lives. Following is information related to our intangible assets still subject to amortization and our goodwill (in thousands): December 31, -------------------- 2004 2003 --------- --------- Goodwill Gross carrying amount...... $ 746,980 $ 743,652 Accumulated amortization... (14,142) (14,142) --------- --------- Net carrying amount........ 732,838 729,510 --------- --------- Lease value Gross carrying amount...... 6,592 6,592 Accumulated amortization... (1,028) (888) --------- --------- Net carrying amount........ 5,564 5,704 --------- --------- Contracts and other Gross carrying amount...... 10,775 7,801 Accumulated amortization... (1,055) (303) --------- --------- Net carrying amount........ 9,720 7,498 --------- --------- Total intangibles, net..... $ 748,122 $ 742,712 ========= ========= <TABLE> <CAPTION> Changes in the carrying amount of goodwill for each of the two years ended December 31, 2003 and 2004 are summarized as follows (in thousands): Products Natural Gas Pipelines Pipelines CO2 Terminals Total ----------- ----------- ----------- ----------- ----------- <S> <C> <C> <C> <C> <C> Balance as of December 31, 2002... $ 263,182 $ 253,358 $ 46,101 $ 153,969 $ 716,610 Goodwill acquired............... - - - 12,900 12,900 Impairments..................... - - - - - ----------- ----------- ----------- ----------- ----------- Balance as of December 31, 2003... $ 263,182 $ 253,358 $ 46,101 $ 166,869 $ 729,510 Goodwill acquired............... - - - 6,368 6,368 Disposals - purchase price adjs. - (3,040) - - (3,040) Impairments..................... - - - - - ----------- ----------- ----------- ----------- ----------- Balance as of December 31, 2004... $ 263,182 $ 250,318 $ 46,101 $ 173,237 $ 732,838 =========== =========== =========== =========== =========== </TABLE> Amortization expense on intangibles consists of the following (in thousands): Year Ended December 31, --------------------------- 2004 2003 2002 -------- -------- -------- Goodwill................. $ - $ - $ - Lease value.............. 140 140 140 Contracts and other...... 752 64 40 -------- ------- -------- Total amortization....... $ 892 $ 204 $ 180 ======== ======= ======== As of December 31, 2004, our weighted average amortization period for our intangible assets is approximately 24 years. Our estimated amortization expense for these assets for each of the next five fiscal years is approximately $1.0 million. Had SFAS No. 142 been in effect prior to January 1, 2002, our limited partners' interest in net income and net income per unit would not have differed from the reported amounts. 9. Debt Our debt and credit facility as of December 31, 2004, consisted primarily of: o a $1.25 billion unsecured five-year credit facility due August 18, 2009; 128 <PAGE> o $200 million of 8.00% Senior Notes due March 15, 2005; o $40 million of Plaquemines, Louisiana Port, Harbor, and Terminal District Revenue Bonds due March 15, 2006 (our 66 2/3% owned subsidiary, International Marine Terminals, is the obligor on the bonds); o $250 million of 5.35% Senior Notes due August 15, 2007; o $20 million of 7.84% Senior Notes, with a final maturity of July 2008 (our subsidiary, Central Florida Pipe Line LLC, is the obligor on the notes); o $250 million of 6.30% Senior Notes due February 1, 2009; o $5.3 million of Illinois Development Revenue Bonds due January 1, 2010 (our subsidiary, Arrow Terminals L.P., is the obligor on the bonds); o $250 million of 7.50% Senior Notes due November 1, 2010; o $700 million of 6.75% Senior Notes due March 15, 2011; o $450 million of 7.125% Senior Notes due March 15, 2012; o $500 million of 5.00% Senior Notes due December 15, 2013; o $500 million of 5.125% Senior Notes due November 15, 2014; o $25 million of New Jersey Economic Development Revenue Refunding Bonds due January 15, 2018 (our subsidiary, Kinder Morgan Liquids Terminals LLC, is the obligor on the bonds); o $23.7 million of tax-exempt bonds due April 1, 2024 (our subsidiary, Kinder Morgan Operating L.P. "B," is the obligor on the bonds); o $300 million of 7.40% Senior Notes due March 15, 2031; o $300 million of 7.75% Senior Notes due March 15, 2032; o $500 million of 7.30% Senior Notes due August 15, 2033; and o a $1.25 billion short-term commercial paper program (supported by our credit facility, the amount available for borrowing under our credit facility is reduced by our outstanding commercial paper borrowings). Our outstanding short-term debt as of December 31, 2004 was $621.2 million. The balance consisted of: o $416.9 million of commercial paper borrowings; o $200 million of 8.00% Senior Notes due March 15, 2005; o $5 million under the Central Florida Pipeline LLC Notes; and o an offset of $0.7 million (which represents the net of other borrowings and the accretion of discounts on our senior note issuances). As of December 31, 2004, we intended and had the ability to refinance all of our short-term debt on a long-term basis under our unsecured long-term credit facility. Accordingly, such amounts have been classified as long-term debt in our accompanying consolidated balance sheet. The weighted average interest rate on all of our borrowings was approximately 4.4702% during 2004 and 4.4924% during 2003. 129 <PAGE> Credit Facilities As of December 31, 2002, we had two outstanding credit facilities. The two facilities consisted of a $530 million unsecured 364-day credit facility due October 14, 2003, and a $445 million unsecured three-year credit facility due October 15, 2005. There were no borrowings under either credit facility as of December 31, 2002. On May 5, 2003, we increased the borrowings available under our two credit facilities by $75 million as follows: o our $530 million unsecured 364-day credit facility was increased to $570 million; and o our $445 million unsecured three-year credit facility was increased to $480 million. Our $570 million unsecured 364-day credit facility expired October 14, 2003. On that date, we obtained a new $570 million unsecured 364-day credit facility due October 12, 2004. As of December 31, 2003, we had two credit facilities totaling $1.05 billion in committed credit lines, consisting of the $570 million unsecured 364-day credit facility due October 12, 2004, and the $480 million unsecured three-year credit facility due October 15, 2005. There were no borrowings under either credit facility as of December 31, 2003. On August 18, 2004, we replaced our existing bank facilities with a $1.25 billion five-year, unsecured revolving credit facility due August 18, 2009. Similar to our previous credit facilities, our current credit facility is with a syndicate of financial institutions and Wachovia Bank, National Association is the administrative agent. There were no borrowings under our five-year credit facility as of December 31, 2004. Our five-year credit facility also permits us to obtain bids for fixed rate loans from members of the lending syndicate. Interest on our credit facility accrues at our option at a floating rate equal to either: o the administrative agent'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 amount available for borrowing under our credit facility as of December 31, 2004 was reduced by: o our outstanding commercial paper borrowings ($416.9 million as of December 31, 2004); o a $50 million letter of credit that supports our hedging of commodity price risks involved from the sale of natural gas, natural gas liquids, oil and carbon dioxide; o a $25.9 million letter of credit entered into on December 23, 2002 that supports Nassau County, Florida Ocean Highway and Port Authority tax-exempt bonds (associated with the operations of our bulk terminal facility located at Fernandina Beach, Florida); o a $24.1 million letter of credit that supports Kinder Morgan Operating L.P. "B"'s tax-exempt bonds; o a $1 million letter of credit entered into on December 13, 2004 that supports a workers' compensation insurance policy; o a $0.3 million letter of credit entered into on December 3, 2004 that supports an equipment rental obligation related to our bulk terminal facility located at Fairless Hills, Pennsylvania; and o a $0.2 million letter of credit entered into on June 4, 2003 that supports a workers' compensation insurance policy. Our credit facility included the following restrictive covenants as of December 31, 2004: o requirements to maintain certain financial ratios: 130 <PAGE> o total debt divided by earnings before interest, income taxes, depreciation and amortization for the preceding four quarters may not exceed 5.0; o total indebtedness of all consolidated subsidiaries shall at no time exceed 15% of consolidated indebtedness; and o consolidated indebtedness shall at no time exceed 62.5% of total capitalization; o certain limitations on entering into mergers, consolidations and sales of assets; o limitations on granting liens; and o prohibitions on making any distribution to holders of units if an event of default exists or would exist upon making such distribution. In addition to normal repayment covenants, under the terms of our credit facility, the occurrence at any time of any of the following would constitute an event of default: o our failure to make required payments of any item of indebtedness or any payment in respect of any hedging agreement, provided that the aggregate outstanding principal amount for all such indebtedness or payment obligations in respect of all hedging agreements is equal to or exceeds $75 million; o our general partner's failure to make required payments of any item of indebtedness, provided that the aggregate outstanding principal amount for all such indebtedness is equal to or exceeds $75 million; o adverse judgments rendered against us for the payment of money in an aggregate amount in excess of $75 million, if this same amount remains undischarged for a period of thirty consecutive days during which execution shall not be effectively stayed; and o voluntary or involuntary commencements of any proceedings or petitions seeking our liquidation, reorganization or any other similar relief under any federal, state or foreign bankruptcy, insolvency, receivership or similar law. Excluding the relatively non-restrictive specified negative covenants and events of defaults, our credit facility does not contain material adverse change clauses or any provisions designed to protect against a situation where a party to an agreement is unable to find a basis to terminate that agreement while its counterparty's impending financial collapse is revealed and perhaps hastened through the default structure of some other agreement. None of our debt is subject to payment acceleration as a result of any change to our credit ratings. However, the margin that we pay with respect to LIBOR-based borrowings under our credit facility varies with our credit ratings. Interest Rate Swaps Information on our interest rate swaps is contained in Note 14. Commercial Paper Program As of December 31, 2003, our commercial paper program provided for the issuance of up to $1.05 billion of commercial paper, and on that date, we had $426.1 million of commercial paper outstanding with an average interest rate of 1.1803%. On October 15, 2004, we increased our commercial paper program by $200 million to provide for the issuance of up to $1.25 billion. Our $1.25 billion unsecured 5-year credit facility supports our commercial paper program, and borrowings under our commercial paper program reduce the borrowings allowed under our credit facility. As of December 31, 2004, we had $416.9 million of commercial paper outstanding with an average interest rate of 2.2856%. The borrowings under our commercial paper program were used principally to finance the acquisitions we made during 2003 and 2004. 131 <PAGE> Senior Notes On November 21, 2003, we closed a public offering of $500 million in principal amount of 5% senior notes due December 15, 2013 at a price to the public of 99.363%. In the offering, we received proceeds, net of underwriting discounts and commissions, of approximately $493.6 million. We used the proceeds to reduce the outstanding balance of our commercial paper borrowings. On November 12, 2004, we closed a public offering of $500 million in principal amount of 5.125% senior notes due November 15, 2014 at a price to the public of 99.914%. In the offering, we received proceeds, net of underwriting discounts and commissions, of approximately $496.3 million. We used the proceeds to reduce the outstanding balance on our commercial paper borrowings. As of December 31, 2004, the outstanding balance on the various series of our senior notes was as follows (in millions): 8.00% senior notes due March 15, 2005...... $ 200.0 5.35% senior notes due August 15, 2007..... 249.9 6.30% senior notes due February 1, 2009.... 249.7 7.50% senior notes due November 1, 2010.... 249.1 6.75% senior notes due March 15, 2011...... 698.7 7.125% senior notes due March 15, 2012..... 448.5 5.00% senior notes due December 15, 2013... 497.2 5.125% senior notes due November 15, 2014.. 499.6 7.40% senior notes due March 15, 2031...... 299.3 7.75% senior notes due March 15, 2032...... 298.6 7.30% senior notes due August 15, 2033..... 499.0 --------- Total.................................... $ 4,189.6 ========= SFPP, L.P. Debt In December 2003, SFPP, L.P. prepaid the $37.1 million balance outstanding under its Series F notes, plus $2.0 million for interest, as a result of its taking advantage of certain optional prepayment provisions without penalty. The annual interest rate on the Series F notes was 10.70%, the maturity was December 2004, and interest was payable semiannually in June and December. We had agreed as part of the acquisition of SFPP, L.P.'s operations (which constitute a significant portion of our Pacific operations) not to take actions with respect to $190 million of SFPP, L.P.'s debt that would cause adverse tax consequences for the prior general partner of SFPP, L.P. The Series F notes were collateralized by mortgages on substantially all of the properties of SFPP, L.P. and contained certain covenants limiting the amount of additional debt or equity that may be issued by SFPP, L.P. and limiting the amount of cash distributions, investments, and property dispositions by SFPP, L.P. Kinder Morgan Wink Pipeline, L.P. Debt Effective August 31, 2004, we acquired all of the partnership interests in Kaston Pipeline Company, L.P., which we renamed Kinder Morgan Wink Pipeline, L.P. (see Note 3). As part of our purchase price, we assumed Kaston's $9.5 million note payable to Western Refining Company, L.P. In September 2004, we paid the $9.5 million outstanding balance under the note, and following our repayment of the note, Kinder Morgan Wink Pipeline, L.P. had no outstanding debt. International Marine Terminals Debt Since February 1, 2002, we have owned a 66 2/3% interest in International Marine Terminals partnership (see Note 3). The principal assets owned by IMT are dock and wharf facilities financed by the Plaquemines Port, Harbor and Terminal District (Louisiana) $40,000,000 Adjustable Rate Annual Tender Port Facilities Revenue Refunding Bonds (International Marine Terminals Project) Series 1984A and 1984B. The bonds mature on March 15, 2006. The bonds are backed by two letters of credit issued by KBC Bank N.V. On March 19, 2002, an Amended and Restated Letter of Credit Reimbursement Agreement relating to the letters of credit in the amount of $45.5 million was entered into by IMT and KBC Bank. In connection with that agreement, we agreed to guarantee the obligations 132 <PAGE> of IMT in proportion to our ownership interest. Our obligation is approximately $30.3 million for principal, plus interest and other fees. Central Florida Pipeline LLC Debt Effective January 1, 2001, we acquired Central Florida Pipeline LLC. As part of our purchase price, we assumed an aggregate principal amount of $40 million of senior notes originally issued to a syndicate of eight insurance companies. The senior notes have a fixed annual interest rate of 7.84% with repayments in annual installments of $5 million beginning July 23, 2001. The final payment is due July 23, 2008. Interest is payable semiannually on January 1 and July 23 of each year. As of December 31, 2003, Central Florida's outstanding balance under the senior notes was $25.0 million. In July 2004, we made an annual repayment of $5.0 million and as of December 31, 2004, Central Florida's outstanding balance under the senior notes was $20.0 million. Kinder Morgan River Terminals LLC Effective October 6, 2004, we acquired Global Materials Services LLC and its consolidated subsidiaries (see Note 3). We renamed Global Materials Services LLC as Kinder Morgan River Terminals LLC, and as part of our purchase price, we assumed debt of $33.7 million, consisting of third-party notes payables, current and non-current bank borrowings, and long-term bonds payable. In October 2004, we paid $28.4 million of the assumed debt and following these repayments, the only remaining outstanding debt was a $5.3 million principal amount of Adjustable Rate Industrial Development Revenue Bonds issued by the Illinois Development Finance Authority. Our subsidiary, Arrow Terminals L.P., is the obligor on these bonds. The bonds have a maturity date of January 1, 2010, and interest on these bonds is paid and computed quarterly at the Bond Market Association Municipal Swap Index. The bonds are collateralized by a first mortgage on assets of Arrow's Chicago operations and a third mortgage on assets of Arrow's Pennsylvania operations. As of December 31, 2004, the interest rate was 1.674%. The bonds are also backed by a $5.4 million letter of credit issued by JP Morgan Chase that backs-up the $5.3 million principal amount of the bonds and $0.1 million of interest on the bonds for up to 45 days computed at 12% on a per annum basis on the principal thereof. Kinder Morgan Liquids Terminals LLC Debt Effective January 1, 2001, we acquired Kinder Morgan Liquids Terminals LLC. As part of our purchase price, we assumed debt of $87.9 million, consisting of five series of tax-exempt industrial revenue bonds. Kinder Morgan Liquids Terminals LLC was the obligor on the bonds, which consisted of the following: o $4.1 million of 7.30% New Jersey Industrial Revenue Bonds due September 1, 2019; o $59.5 million of 6.95% Texas Industrial Revenue Bonds due February 1, 2022; o $7.4 million of 6.65% New Jersey Industrial Revenue Bonds due September 1, 2022; o $13.3 million of 7.00% Louisiana Industrial Revenue Bonds due March 1, 2023; and o $3.6 million of 6.625% Texas Industrial Revenue Bonds due February 1, 2024. In May 2004, we exercised our right to call and retire all of the industrial revenue bonds (other than the $3.6 million of 6.625% bonds due February 1, 2024) prior to maturity at a redemption price of $84.3 million, plus approximately $1.9 million for interest, prepayment premiums and redemption fees. In October 2004, we exercised our right to call and retire the remaining $3.6 million of bonds due February 1, 2024 prior to maturity at a redemption price of $3.6 million, plus approximately $0.1 million for interest, prepayment premiums and redemption fees. For both of these redemptions and retirements, we borrowed the necessary funds under our commercial paper program. Pursuant to Accounting Principles Board Opinion No. 26, "Early Extinguishment of Debt," we recognized the $1.6 million excess of our reacquisition price over both the carrying value of the bonds and unamortized debt issuance costs as a loss on bond repurchases and we included this amount under the caption "Other, net" in our accompanying consolidated statement of income. 133 <PAGE> In November 2001, we acquired a liquids terminal in Perth Amboy, New Jersey from Stolthaven Perth Amboy Inc. and Stolt-Nielsen Transportation Group, Ltd. As part of our purchase price, we assumed $25.0 million of Economic Development Revenue Refunding Bonds issued by the New Jersey Economic Development Authority. These bonds have a maturity date of January 15, 2018. Interest on these bonds is computed on the basis of a year of 365 or 366 days, as applicable, for the actual number of days elapsed during Commercial Paper, Daily or Weekly Rate Periods and on the basis of a 360-day year consisting of twelve 30-day months during a Term Rate Period. As of December 31, 2004, the interest rate was 1.5288%. We have an outstanding letter of credit issued by Citibank in the amount of $25.4 million that backs-up the $25.0 million principal amount of the bonds and $0.4 million of interest on the bonds for up to 42 days computed at 12% on a per annum basis on the principal thereof. Kinder Morgan Operating L.P. "B" Debt This $23.7 million principal amount of tax-exempt bonds due April 1, 2024 was issued by the Jackson-Union Counties Regional Port District. These bonds bear interest at a weekly floating market rate. As of December 31, 2004, the interest rate on these bonds was 1.704%. An outstanding letter of credit issued under our credit facilities supports our tax-exempt bonds. This letter of credit reduces the amount available for borrowing under our credit facilities. Maturities of Debt The scheduled maturities of our outstanding debt, excluding market value of interest rate swaps, as of December 31, 2004, are summarized as follows (in thousands): 2005...... $ 621,168 2006...... 43,860 2007...... 253,874 2008...... 3,897 2009...... 248,974 Thereafter 3,550,637 ---------- Total..... $4,722,410 ========== Fair Value of Financial Instruments 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. The estimated fair value of our long-term debt, excluding market value of interest rate swaps, is based upon prevailing interest rates available to us as of December 31, 2004 and December 31, 2003 and is disclosed below. December 31, 2004 December 31, 2003 ------------------------- ---------------------- Carrying Estimated Carrying Estimated Value Fair Value Value Fair Value ----------- ---------- ---------- ---------- (In thousands) Total Debt $4,722,410 $5,139,747 $4,318,926 $4,889,478 10. Pensions and Other Post-retirement Benefits In connection with our acquisition of SFPP, L.P. and Kinder Morgan Bulk Terminals, Inc. in 1998, we acquired certain liabilities for pension and post-retirement benefits. We provide medical and life insurance benefits to current employees, their covered dependents and beneficiaries of SFPP and Kinder Morgan Bulk Terminals. We also provide the same benefits to former salaried employees of SFPP. Additionally, we will continue to fund these costs for those employees currently in the plan during their retirement years. SFPP's post-retirement benefit plan is frozen and no additional participants may join the plan. The noncontributory defined benefit pension plan covering the former employees of Kinder Morgan Bulk Terminals is the Kinder Morgan, Inc. Retirement Plan. The benefits under this plan are based primarily upon years of service and final average pensionable earnings; however, benefit accruals were frozen as of December 31, 1998. 134 <PAGE> Net periodic benefit costs and weighted-average assumptions for these plans include the following components (in thousands): Other Post-retirement Benefits ---------------------------------------------- 2004 2003 2002 ------------ -------------- ------------ Net periodic benefit cost Service cost...................... $ 111 $ 41 $ 165 Interest cost..................... 389 807 906 Expected return on plan assets.... -- -- -- Amortization of prior service cost (125) (622) (545) Actuarial (gain).................. (976) -- -- ------- ------ ------ Net periodic benefit cost......... $ (601) $ 226 $ 526 ======= ====== ====== Additional amounts recognized Curtailment (gain) loss......... $ -- $ -- $ -- Weighted-average assumptions as of December 31: Discount rate..................... 5.75% 6.00% 6.50% Expected return on plan assets.... -- -- -- Rate of compensation increase..... 3.9% 3.9% 3.9% Information concerning benefit obligations, plan assets, funded status and recorded values for these plans follows (in thousands): Other Post-retirement Benefits ------------------------------ 2004 2003 -------------- ------------ Change in benefit obligation Benefit obligation at Jan. 1............ $ 6,176 $ 13,275 Service cost............................ 111 41 Interest cost........................... 389 807 Participant contributions............... 166 144 Amendments.............................. (207) (190) Actuarial (gain) loss................... (632) (7,456) Benefits paid from plan assets.......... (448) (445) -------- -------- Benefit obligation at Dec. 31........... $ 5,555 $ 6,176 ======== ======== Change in plan assets Fair value of plan assets at Jan. 1..... $ -- $ -- Actual return on plan assets............ -- -- Employer contributions.................. 282 301 Participant contributions............... 166 144 Benefits paid from plan assets.......... (448) (445) -------- -------- Fair value of plan assets at Dec. 31.... $ -- $ -- ========= ========= Other Post-retirement Benefits ------------------------------ 2004 2003 -------------- ------------ Funded status........................... $ (5,555) $ (6,176) Unrecognized net actuarial (gain) loss.. (6,383) (6,728) Unrecognized prior service (benefit).... (710) (627) Adj. for 4th qtr. Employer contributions......................... 91 72 -------- -------- Accrued benefit cost.................... $(12,557) $(13,459) ======== ======== The unrecognized prior service credit is amortized on a straight-line basis over the average future lifetime until full eligibility for benefits. For measurement purposes, a 10% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2005. The rate was assumed to decrease gradually to 5% by 2010 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 (in thousands): 1-Percentage 1-Percentage Point Increase Point Decrease -------------- -------------- Effect on total of service and interest cost components..................................... $ 34 $ (29) Effect on postretirement benefit obligation...... $ 552 $ (466) 135 <PAGE> Amounts recognized in our consolidated balance sheets consist of (in thousands): As of December 31, -------------------------------- 2004 2003 -------------- ------------ Prepaid benefit cost...................... $ - $ - Accrued benefit liability................. (12,557) (13,459) Intangible asset.......................... - - Accumulated other comprehensive income.... - - -------- -------- - - Net amount recognized as of Dec. 31..... $ (12,557) $ (13,459) ======== ======== We expect to contribute approximately $0.3 million to our post-retirement benefit plans in 2005. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid (in thousands): Other Post-retirement Benefits ------------------------------- 2005........ $ 360 2006........ 373 2007........ 364 2008........ 371 2009........ 366 2010-2014... 1,818 ----------- Total....... $ 3,652 =========== Multiemployer Plans As a result of acquiring several terminal operations, primarily our acquisition of Kinder Morgan Bulk Terminals, Inc. effective July 1, 1998, we participate in several multi-employer pension plans for the benefit of employees who are union members. We do not administer these plans and contribute to them in accordance with the provisions of negotiated labor contracts. Other benefits include a self-insured health and welfare insurance plan and an employee health plan where employees may contribute for their dependents' health care costs. Amounts charged to expense for these plans were $5.5 million for the year ended 2004 and $4.9 million for the year ended 2003. Kinder Morgan Savings Plan The Kinder Morgan Savings Plan permits all full-time employees of KMGP Services Company, Inc. and KMI to contribute between 1% and 50% of base compensation, on a pre-tax basis, into participant accounts. In addition to a mandatory contribution equal to 4% of base compensation per year for most plan participants, KMGP Services Company, Inc. and KMI may make discretionary contributions in years when specific performance objectives are met. Certain employees' contributions are based on collective bargaining agreements. Our mandatory contributions are made each pay period on behalf of each eligible employee. Any discretionary contributions are made during the first quarter following the performance year. All employer 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. No discretionary contributions were made to individual accounts for 2004. At its July 2004 meeting, the compensation committee of the KMI board of directors approved that contingent upon its approval at it's July 2005 meeting, each eligible employee will receive an additional 1% company contribution based on eligible base pay to his or her Savings Plan account each pay period beginning with the first pay period after the July 2005 Committee meeting. The 1% contribution will be in the form of KMI common stock (the same as the current 4% contribution). The 1% contribution will be in addition to, and will not change or otherwise impact, the annual 4% contribution that eligible employees currently receive. It may be converted to any other Savings Plan investment fund at any time and it will vest on the second anniversary of the employee's date of hire. Since this additional 1% company contribution is discretionary, compensation committee approval will be required annually for each contribution. The total amount charged to expense for our Savings Plan was $6.5 million during 2004 and $5.9 million during 2003. 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. 136 <PAGE> Cash Balance Retirement Plan Employees of KMGP Services Company, Inc. and KMI are also eligible to participate in a Cash Balance Retirement Plan. Certain employees continue to accrue benefits through a career-pay formula, "grandfathered" according to age and years of service on December 31, 2000, or collective bargaining arrangements. All other employees accrue benefits through a personal retirement account in the Cash Balance Retirement Plan. Employees with prior service and not grandfathered converted to the Cash Balance Retirement Plan on January 1, 2001, and were credited with the current fair value of any benefits they had previously accrued through the defined benefit plan. Under the plan, we make contributions on behalf of participating employees equal to 3% of eligible compensation every pay period. In addition, discretionary contributions are made to the plan based on our and KMI's performance. No discretionary contributions were made for 2004 performance. Interest is credited to the personal retirement accounts at the 30-year U.S. Treasury bond rate, or an approved substitute, in effect each year. Employees become fully vested in the plan after five years, and they may take a lump sum distribution upon termination of employment or retirement. 11. Partners' Capital As of December 31, 2004 and 2003, our partners' capital consisted of the following limited partner units: December 31, December 31, 2004 2003 ----------- ----------- Common units.................. 147,537,908 134,729,258 Class B units................. 5,313,400 5,313,400 i-units....................... 54,157,641 48,996,465 ----------- ----------- Total limited partner units. 207,008,949 189,039,123 =========== =========== The total limited partner units represent our limited partners' interest, an effective 98% economic interest in us, exclusive of our general partner's incentive distribution rights. Our general partner has an effective 2% interest in us, excluding its incentive distribution rights. As of December 31, 2004, our common unit total consisted of 133,182,173 units held by third parties, 12,631,735 units held by KMI and its consolidated affiliates (excluding our general partner) and 1,724,000 units held by our general partner. Our Class B units were held entirely by KMI and our i-units were held entirely by KMR. Our total common units outstanding at December 31, 2003, consisted of 121,773,523 units held by third parties, 11,231,735 units held by KMI and its consolidated affiliates (excluding our general partner) and 1,724,000 units held by our general partner. Our Class B units were held entirely by KMI and our i-units were held entirely by KMR. In June 2003, we issued, in a public offering, 4,600,000 of our common units, including 600,000 units upon exercise by the underwriters of an over-allotment option, at a price of $39.35 per share, less commissions and underwriting expenses. After commissions and underwriting expenses, we received net proceeds of $173.3 million for the issuance of these common units. We used the proceeds to reduce the borrowings under our commercial paper program. On February 9, 2004, we issued, in a public offering, 5,300,000 of our common units at a price of $46.80 per unit, less commissions and underwriting expenses. After commissions and underwriting expenses, we received net proceeds of $237.8 million for the issuance of these common units. We used the proceeds to reduce the borrowings under our commercial paper program. On November 10, 2004, we issued, in a public offering, 5,500,000 of our common units. On December 8, 2004, we issued an additional 575,000 units upon exercise by the underwriters of an over-allotment option. We issued these 6,075,000 units at a price of $46.00 per unit, less commissions and underwriting expenses. After commissions and underwriting expenses, we received net proceeds of $268.3 million and we used the proceeds to reduce the borrowings under our commercial paper program. 137 <PAGE> All of our Class B units were issued in December 2000 to KMI. The Class B units are similar to our common units except that they are not eligible for trading on the New York Stock Exchange. Our i-units are a separate class of limited partner interests in us. All of our i-units are owned by KMR and are not publicly traded. In accordance with its limited liability company agreement, KMR's activities are restricted to being a limited partner in us, and controlling and managing our business and affairs and the business and affairs of our operating limited partnerships and their subsidiaries. Through the combined effect of the provisions in our partnership agreement and the provisions of KMR's limited liability company agreement, the number of outstanding KMR shares and the number of i-units will at all times be equal. On March 25, 2004, KMR issued an additional 360,664 of its shares at a price of $41.59 per share, less closing fees and commissions. The net proceeds from the offering were used to buy additional i-units from us. After closing and commission expenses, we received net proceeds of $14.9 million for the issuance of 360,664 i-units. We used the proceeds from the i-unit issuance to reduce the borrowings under our commercial paper program. On November 10, 2004, KMR issued an additional 1,300,000 of its shares at a price of $41.29 per share, less closing fees and commissions. The net proceeds from the offering were used to buy additional i-units from us. We received proceeds of $52.6 million for the issuance of 1,300,000 i-units. We used the proceeds from the i-unit issuance to reduce the borrowings under our commercial paper program. Under the terms of our partnership agreement, we agreed that we will not, except in liquidation, make a distribution on an i-unit other than in additional i-units or a security that has in all material respects the same rights and privileges as our i-units. The number of i-units we distribute to KMR is based upon the amount of cash we distribute to the owners of our common units. When cash is paid to the holders of our common units, we will issue additional i-units to KMR. The fraction of an i-unit paid per i-unit owned by KMR will have a value based on the cash payment on the common unit as described following. The cash equivalent of distributions of i-units will be treated as if it had actually been distributed for purposes of determining the distributions to our general partner. We will not distribute the cash to the holders of our i-units but will retain the cash for use in our business. If additional units are distributed to the holders of our common units, we will issue an equivalent amount of i-units to KMR based on the number of i-units it owns. Based on the preceding, KMR received a distribution of 929,105 i-units on November 12, 2004. These additional i-units distributed were based on the $0.73 per unit distributed to our common unitholders on that date. During the year ended December 31, 2004, KMR received distributions of 3,500,512 i-units. These additional i-units distributed were based on the $2.81 per unit distributed to our common unitholders during 2004. For the purposes of maintaining partner capital accounts, our partnership agreement specifies that items of income and loss shall be allocated among the partners, other than owners of i-units, in accordance with their percentage interests. Normal allocations according to percentage interests are made, however, only after giving effect to any priority income allocations in an amount equal to the incentive distributions that are allocated 100% to our general partner. Incentive distributions are generally defined as all cash distributions paid to our general partner that are in excess of 2% of the aggregate value of cash and i-units being distributed. 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, 2004, 2003 and 2002, we declared distributions of $2.87, $2.63 and $2.435 per unit, respectively. Our distributions to unitholders for 2004, 2003 and 2002 required incentive distributions to our general partner in the amount of $390.7 million, $322.8 million and $267.4 million, respectively. The increased incentive distributions paid for 2004 over 2003 and 2003 over 2002 reflect the increase in amounts distributed per unit as well as the issuance of additional units. Distributions for the fourth quarter of each year are declared and paid during the first quarter of the following year. On January 18, 2005, we declared a cash distribution of $0.74 per unit for the quarterly period ended December 31, 2004. This distribution was paid on February 14, 2005, to unitholders of record as of January 31, 2005. Our common unitholders and Class B unitholders received cash. KMR, our sole i-unitholder, received a distribution in the form of additional i-units based on the $0.74 distribution per common unit. The number of i-units distributed 138 <PAGE> was 955,936. For each outstanding i-unit that KMR held, a fraction of an i-unit (0.017651) was issued. The fraction was determined by dividing: o $0.74, the cash amount distributed per common unit by o $41.924, the average of KMR's limited liability shares' closing market prices from January 12-26, 2005, the ten consecutive trading days preceding the date on which the shares began to trade ex-dividend under the rules of the New York Stock Exchange. This February 14, 2005 distribution required an incentive distribution to our general partner in the amount of $106.0 million. Since this distribution was declared after the end of the quarter, no amount is shown in our December 31, 2004 balance sheet as a distribution payable. 12. Related Party Transactions General and Administrative Expenses KMGP Services Company, Inc., a subsidiary of our general partner, provides employees and Kinder Morgan Services LLC, a wholly owned subsidiary of KMR, provides centralized payroll and employee benefits services to us, our operating partnerships and subsidiaries, Kinder Morgan G.P., Inc. and KMR (collectively, the "Group"). Employees of KMGP Services Company, Inc. are assigned to work for one or more members of the Group. The direct costs of all compensation, benefits expenses, employer taxes and other employer expenses for these employees are allocated and charged by Kinder Morgan Services LLC to the appropriate members of the Group, and the members of the Group reimburse for their allocated shares of these direct costs. There is no profit or margin charged by Kinder Morgan Services LLC to the members of the Group. The administrative support necessary to implement these payroll and benefits services is provided by the human resource department of KMI, and the related administrative costs are allocated to members of the Group in accordance with existing expense allocation procedures. The effect of these arrangements is that each member of the Group bears the direct compensation and employee benefits costs of its assigned or partially assigned employees, as the case may be, while also bearing its allocable share of administrative costs. Pursuant to our limited partnership agreement, we provide reimbursement for our share of these administrative costs and such reimbursements will be accounted for as described above. Additionally, we reimburse KMR with respect to costs incurred or allocated to KMR in accordance with our limited partnership agreement, the delegation of control agreement among our general partner, KMR, us and others, and KMR's limited liability company agreement. The named executive officers of our general partner and KMR and other employees that provide management or services to both KMI and the Group are employed by KMI. Additionally, other KMI employees assist in the operation of our Natural Gas Pipeline assets. These KMI employees' expenses are allocated without a profit component between KMI and the appropriate members of the Group. Partnership Distributions Kinder Morgan G.P., Inc. Kinder Morgan G.P., Inc. serves as our sole general partner. Pursuant to our partnership agreements, our general partner's interests represent a 1% ownership interest in us, and a direct 1.0101% ownership interest in each of our five operating partnerships. Collectively, our general partner owns an effective 2% interest in our operating partnerships, excluding incentive distributions rights as follows: o its 1.0101% direct general partner ownership interest (accounted for as minority interest in our consolidated financial statements); and o its 0.9899% ownership interest indirectly owned via its 1% ownership interest in us. 139 <PAGE> As of December 31, 2004, our general partner owned 1,724,000 common units, representing approximately 0.83% of our outstanding limited partner units. Our partnership agreement requires that we distribute 100% of available cash, as defined in our 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, 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 SFPP, L.P. in respect of its remaining 0.5% interest in SFPP. Our general partner is granted discretion by our partnership agreement, which discretion has been delegated to KMR, subject to the approval of our general partner in certain cases, to establish, maintain and adjust reserves for future operating expenses, debt service, maintenance capital expenditures, rate refunds and distributions for the next four quarters. These reserves are not restricted by magnitude, but only by type of future cash requirements with which they can be associated. When KMR determines our quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level. Our general partner and owners of our common units and Class B units receive distributions in cash, while KMR, the sole owner of our i-units, receives distributions in additional i-units. The cash equivalent of distributions of i-units is treated as if it had actually been distributed for purposes of determining the distributions to our general partner. We do not distribute cash to i-unit owners but retain the cash for use in our business. Available cash is initially distributed 98% to our limited partners and 2% to our general partner. These distribution percentages are modified to provide for incentive distributions to be paid to our general partner in the event that quarterly distributions to unitholders exceed certain specified targets. Available cash for each quarter is distributed: o first, 98% to the owners of all classes of units pro rata and 2% to our general partner until the owners of all classes of units have received a total of $0.15125 per unit in cash or equivalent i-units for such quarter; o second, 85% of any available cash then remaining to the owners of all classes of units pro rata and 15% to our general partner until the owners of all classes of units have received a total of $0.17875 per unit in cash or equivalent i-units for such quarter; o third, 75% of any available cash then remaining to the owners of all classes of units pro rata and 25% to our general partner until the owners of all classes of units have received a total of $0.23375 per unit in cash or equivalent i-units for such quarter; and o fourth, 50% of any available cash then remaining to the owners of all classes of units pro rata, to owners of common units and Class B units in cash and to owners of i-units in the equivalent number of i-units, 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 value of cash and i-units being distributed. Our general partner's declared incentive distributions for the years ended December 31, 2004, 2003 and 2002 were $390.7 million, $322.8 million and $267.4 million, respectively. Kinder Morgan, Inc. KMI, through its subsidiary Kinder Morgan (Delaware), Inc., remains the sole stockholder of our general partner. As of December 31, 2004, KMI directly owned 8,838,095 common units and 5,313,400 Class B units, indirectly owned 5,517,640 common units through its consolidated affiliates, including our general partner, and owned 15,135,460 KMR shares, representing an indirect ownership interest of 15,135,460 i-units. Together, these units represented approximately 16.8% of our outstanding limited partner units. Including both its general and limited 140 <PAGE> partner interests in us, at the 2004 distribution level, KMI received approximately 51% of all quarterly distributions from us, of which approximately 41% is attributable to its general partner interest and 10% is attributable to its limited partner interest. The actual level of distributions KMI will receive in the future will vary with the level of distributions to the limited partners determined in accordance with our partnership agreement. Kinder Morgan Management, LLC As of December 31, 2004, KMR, our general partner's delegate, remained the sole owner of our 54,157,641 i-units. Asset Acquisitions and Sales 2004 Kinder Morgan, Inc. Asset Contributions In June 2004, we bought two LM6000 gas-fired turbines and two boilers from a subsidiary of KMI for their estimated fair market value of $21.1 million, which we paid in cash. This equipment was a portion of the equipment that became surplus as a result of KMI's decision to exit the power development business and will be employed in conjunction with our CO2 business segment. Effective November 1, 2004, we acquired all of the partnership interests in TransColorado Gas Transmission Company from two wholly-owned subsidiaries of KMI. TransColorado Gas Transmission Company, a Colorado general partnership referred to in this report as TransColorado, owned assets valued at approximately $284.5 million. As consideration for TransColorado, we paid to KMI $211.2 million in cash and approximately $64.0 million in units, consisting of 1,400,000 common units. We also assumed liabilities of approximately $9.3 million. The purchase price for this transaction was determined by the boards of directors of KMR and our general partner, and KMI based on valuation parameters used in the acquisition of similar assets. The transaction was approved unanimously by the independent members of the boards of directors of both KMR and our general partner, and KMI, with the benefit of advice of independent legal and financial advisors, including the receipt of fairness opinions from separate investment banks, specifically Goldman, Sachs & Co. and Morgan Stanley & Co. In conjunction with our acquisition of TransColorado Gas Transmission Company, KMI became a guarantor of approximately $210.8 million of our debt. 1999 and 2000 Kinder Morgan, Inc. Asset Contributions In conjunction with our acquisition of Natural Gas Pipelines assets from KMI on December 31, 1999 and 2000, KMI became a guarantor of approximately $522.7 million of our debt. Thus, taking into consideration the guarantee of debt associated with our TransColorado acquisition discussed above, KMI was a guarantor of a total of approximately $733.5 million of our debt as of December 31, 2004. KMI would be obligated to perform under this guarantee only if we and/or our assets were unable to satisfy our obligations. 2004 Asset Sales In November 2004, Kinder Morgan Operating L.P. "A" sold a natural gas gathering system to Kinder Morgan, Inc.'s retail division for $75,000. The gathering system primarily consisted of approximately 23,000 miles of 6-inch diameter pipeline located in Campbell County, Wyoming that was no longer being used by Kinder Morgan Operating L.P. "A". Operations KMI or its subsidiaries operate and maintain for us the assets comprising our Natural Gas Pipelines business segment. Natural Gas Pipeline Company of America, a subsidiary of KMI, operates Trailblazer Pipeline Company's assets under a long-term contract pursuant to which Trailblazer Pipeline Company incurs the costs and expenses related to NGPL's operating and maintaining the assets. Trailblazer Pipeline Company provides the funds for its own capital expenditures. NGPL does not profit from or suffer loss related to its operation of Trailblazer Pipeline Company's assets. 141 <PAGE> The remaining assets comprising our Natural Gas Pipelines business segment are operated under other agreements between KMI and us. Pursuant to the applicable underlying agreements, we pay KMI either a fixed amount or actual costs incurred as reimbursement for the corporate general and administrative expenses incurred in connection with the operation of these assets. On January 1, 2003, KMI began operating additional pipeline assets, including our North System and Cypress pipeline, which are part of our Products Pipelines business segment. The amounts paid to KMI for corporate general and administrative costs, including amounts related to Trailblazer Pipeline Company, were $8.8 million of fixed costs and $13.1 million of actual costs incurred for 2004, and $8.7 million of fixed costs and $10.8 million of actual costs incurred for 2003. We estimate the total reimbursement for corporate general and administrative costs to be paid to KMI in respect of all pipeline assets operated by KMI and its subsidiaries for us for 2005 will be approximately $24.7 million, which includes $5.5 million of fixed costs (adjusted for inflation) and $19.2 million of actual costs. We believe the amounts paid to KMI for the services they provided each year fairly reflect the value of the services performed. However, due to the nature of the allocations, these reimbursements may not exactly match the actual time and overhead spent. We believe the fixed amounts that were agreed upon at the time the contracts were entered into were reasonable estimates of the corporate general and administrative expenses to be incurred by KMI and its subsidiaries in performing such services. We also reimburse KMI and its subsidiaries for operating and maintenance costs and capital expenditures incurred with respect to our assets. From time to time in the ordinary course of business, we buy and sell pipeline and related services from KMI and its subsidiaries. Such transactions are conducted in accordance with all applicable laws and regulations and on an arms' length basis consistent with our policies governing such transactions. Certain of our business activities expose us to risks associated with changes in the market price of natural gas, natural gas liquids, crude oil and carbon dioxide. We perform risk management activities that involve the use of energy financial instruments to reduce these risks and protect our profit margins. Our risk management policies prohibit us from engaging in speculative trading. Commodity-related activities of our risk management group are monitored by our risk management committee, which is a separately designated standing committee comprised of eleven executive-level employees of KMI or KMGP Services Company, Inc. whose job responsibilities involve operations exposed to commodity market risk and other external risks in the ordinary course of business. For more information on our risk management activities see Note 14. Notes Receivable Plantation Pipe Line Company We own a 51.17% equity interest in Plantation Pipe Line Company. An affiliate of ExxonMobil owns the remaining 48.83% interest. In July 2004, Plantation repaid a $10 million note outstanding and $175 million in outstanding commercial paper borrowings with funds of $190 million borrowed from its owners. We loaned Plantation $97.2 million, which corresponds to our 51.17% ownership interest, in exchange for a seven year note receivable bearing interest at the rate of 4.72% per annum. As of December 31, 2004, the principal amount receivable from this note was $96.3 million. We have included $2.2 million of this balance within "Accounts, notes and interest receivable-Related Parties" on our consolidated balance sheet. The remaining $94.1 million receivable is included within "Notes receivable-Related Parties" on our consolidated balance sheet. Coyote Gas Treating, LLC We own a 50% equity interest in Coyote Gas Treating, LLC, referred to in this report as Coyote Gulch. Coyote Gulch is a joint venture, and Enterprise Field Services LLC owns the remaining 50% equity interest. We are the managing partner of Coyote Gulch. In June 2001, Coyote repaid the $34.2 million in outstanding borrowings under its 364-day credit facility with funds borrowed from its owners. We loaned Coyote $17.1 million, which corresponds to our 50% ownership interest, in exchange for a one-year note receivable bearing interest payable monthly at LIBOR plus a margin of 0.875%. On June 30, 2002 and June 30, 2003, the note was extended for one year. On June 30, 2004, the term of the note was made month-to-month, and as of December 31, 2004, we included the principal amount of $17.1 million related to this note within "Notes Receivable-Related Parties" on our 142 <PAGE> consolidated balance sheet. As of December 31, 2003, we included the $17.1 million receivable related to this note within "Accounts, notes and interest receivable-Related Parties" on our consolidated balance sheet. Red Cedar Gas Gathering Company We own a 49% equity interest in the Red Cedar Gas Gathering Company. Red Cedar is a joint venture and the Southern Ute Indian Tribe owns the remaining 51% equity interest. On December 22, 2004, we entered into a $10 million unsecured revolving credit facility due July 1, 2005, with the Southern Ute Indian Tribe and us, as lenders, and Red Cedar, as borrower. Subject to the terms of the agreement, the lenders may severally, but not jointly, make advances to Red Cedar up to a maximum outstanding principal amount of $10 million. However, as of April 1, 2005, through July 1, 2005, the maximum outstanding principal amount will be automatically reduced to $5 million. In January 2005, Red Cedar borrowed funds of $4 million from its owners pursuant to this credit agreement and we loaned Red Cedar $1.96 million, which corresponds to our 49% ownership interest. The interest on all advances made under this agreement will be calculated as simple interest on the combined outstanding balance of the credit agreement at 6% per annum based upon a 360 day year. Other Generally, KMR makes all decisions relating to the management and control of our business. Our general partner owns all of KMR's voting securities and is its sole managing member. KMI, through its wholly owned and controlled subsidiary Kinder Morgan (Delaware), Inc., owns all the common stock of our general partner. Certain conflicts of interest could arise as a result of the relationships among KMR, our general partner, KMI and us. The directors and officers of KMI have fiduciary duties to manage KMI, including selection and management of its investments in its subsidiaries and affiliates, in a manner beneficial to the shareholders of KMI. In general, KMR has a fiduciary duty to manage us in a manner beneficial to our unitholders. The partnership agreements for us and our operating partnerships contain provisions that allow KMR to take into account the interests of parties in addition to us in resolving conflicts of interest, thereby limiting its fiduciary duty to our unitholders, as well as provisions that may restrict the remedies available to our unitholders for actions taken that might, without such limitations, constitute breaches of fiduciary duty. The partnership agreements provide that in the absence of bad faith by KMR, the resolution of a conflict by KMR will not be a breach of any duties. The duty of the directors and officers of KMI to the shareholders of KMI may, therefore, come into conflict with the duties of KMR and its directors and officers to our unitholders. The Audit Committee of KMR's board of directors will, at the request of KMR, review (and is one of the means for resolving) conflicts of interest that may arise between KMI or its subsidiaries, on the one hand, and us, on the other hand. 13. Leases and Commitments Capital Leases We acquired certain leases classified as capital leases as part of our acquisition of Kinder Morgan River Terminals LLC in October 2004. We lease our Memphis, Tennessee port facility under an agreement accounted for as a capital lease. The lease is for 24 years and expires in 2017. Additionally, we have approximately ten equipment leases accounted for as capital leases which expire from 2005 to 2007. Amortization of assets recorded under capital leases is included with depreciation expense. The components of property, plant and equipment recorded under capital leases are as follows (in thousands): December 31, ------------ 2004 ----------- Leasehold improvements........... $ 4,089 Machinery and equipment.......... 150 ----------- 4,239 Less: Accumulated amortization... (2,056) ----------- $ 2,183 =========== 143 <PAGE> Future commitments under capital lease obligations as of December 31, 2004 are as follows (in thousands): Year Commitment ---- ----------- 2005...................... $ 228 2006...................... 180 2007...................... 169 2008...................... 168 2009...................... 168 Thereafter................ 1,327 ----------- 2,240 Less: Amount representing interest (957) ----------- Present value of minimum capital lease payments $ 1,283 =========== Operating Leases Including probable elections to exercise renewal options, the remaining terms on our operating leases range from one to 64 years. Future commitments related to these leases as of December 31, 2004 are as follows (in thousands): Year Commitment ---- ---------- 2005...................... $ 30,450 2006...................... 26,240 2007...................... 23,571 2008...................... 19,748 2009...................... 15,381 Thereafter................ 48,788 ---------- Total minimum payments.... $ 164,178 ========== We have not reduced our total minimum payments for future minimum sublease rentals aggregating approximately $0.6 million. Total lease and rental expenses, including related variable charges were $39.3 million for 2004, $25.3 million for 2003 and $21.6 million for 2002. Common Unit Option Plan During 1998, we established a common unit option plan, which provides that key personnel of KMGP Services Company, Inc. and KMI are eligible to receive grants of options to acquire common units. The number of common units authorized under the option plan is 500,000. The option plan terminates in March 2008. The options granted generally have a term of seven years, vest 40% on the first anniversary of the date of grant and 20% on each of the next three anniversaries, and have exercise prices equal to the market price of the common units at the grant date. As of December 31, 2003, options to purchase 129,050 common units were held by employees of KMI or KMGP Services Company, Inc. at an average exercise price of $17.46 per unit. Outstanding options to purchase 20,000 common units were held by two of Kinder Morgan G.P., Inc.'s three non-employee directors at an average exercise price of $20.58 per unit. As of December 31, 2004, outstanding options to purchase 95,400 common units were held by employees of KMI or KMGP Services Company, Inc. at an average exercise price of $17.44 per unit. Outstanding options to purchase 20,000 common units were held by two of Kinder Morgan G.P., Inc.'s three non-employee directors at an average exercise price of $20.58 per unit. As of December 31, 2004, all 115,400 outstanding options were fully vested. During 2003, options to purchase 134,550 common units were exercised at an average price of $17.06 per unit. The common units underlying these options had an average fair market value of $38.85 per unit. During 2004, 33,650 options to purchase common units were exercised at an average price of $17.50 per unit. The common units underlying these options had an average fair market value of $45.92 per unit. We apply Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations in accounting for common unit options granted under our common unit option plan. Accordingly, we record expense for our common unit option plan equal to the excess of the market price of the underlying common units at the date of grant over the exercise price of the common unit award, if any. Such excess is commonly referred to as the intrinsic value. All of our common unit options were issued with the exercise price 144 <PAGE> equal to the market price of the underlying common units at the grant date and therefore, no compensation expense has been recorded. We have not granted common unit options since May 2000. 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, has not been provided because the impact is not material. Directors' Unit Appreciation Rights Plan On April 1, 2003, KMR's compensation committee established our Directors' Unit Appreciation Rights Plan. Pursuant to this plan, each of KMR's three non-employee directors was eligible to receive common unit appreciation rights. Upon the exercise of unit appreciation rights, we will pay, within thirty days of the exercise date, the participant an amount of cash equal to the excess, if any, of the aggregate fair market value of the unit appreciation rights exercised as of the exercise date over the aggregate award price of the rights exercised. The fair market value of one unit appreciation right as of the exercise date will be equal to the closing price of one common unit on the New York Stock Exchange on that date. The award price of one unit appreciation right will be equal to the closing price of one common unit on the New York Stock Exchange on the date of grant. Proceeds, if any, from the exercise of a unit appreciation right granted under the plan will be payable only in cash (that is, no exercise will result in the issuance of additional common units) and will be evidenced by a unit appreciation rights agreement. All unit appreciation rights granted vest on the six-month anniversary of the date of grant. If a unit appreciation right is not exercised in the ten year period following the date of grant, the unit appreciation right will expire and not be exercisable after the end of such period. In addition, if a participant ceases to serve on the board for any reason prior to the vesting date of a unit appreciation right, such unit appreciation right will immediately expire on the date of cessation of service and may not be exercised. On April 1, 2003, the date of adoption of the plan, each of KMR's three non-employee directors were granted 7,500 unit appreciation rights. In addition, 10,000 unit appreciation rights were granted to each of KMR's three non-employee directors on January 21, 2004, at the first meeting of the board in 2004. As of December 31, 2004, 52,500 unit appreciation rights had been granted. No unit appreciation rights were exercised during 2004. During the first board meeting of 2005, the plan was terminated and replaced by the Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors. Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors On January 18, 2005, KMR's compensation committee established the Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan to compensate KMR's non-employee directors for 2005. The plan is administered by KMR's compensation committee and KMR's board has sole discretion to terminate the plan at any time. The primary purpose of this plan was to promote our interests and the interests of our unitholders by aligning the compensation of the non-employee members of the board of directors of KMR with unitholders' interests. Further, since KMR's success is dependent on its operation and management of our business and our resulting performance, the plan is expected to align the compensation of the non-employee members of the board with the interests of KMR's shareholders. The plan recognizes that the compensation to be paid to each non-employee director is fixed by the KMR board, generally annually, and that the compensation is expected to include an annual retainer payable in cash and other cash compensation. Pursuant to the plan, in lieu of receiving the other cash compensation, each non-employee director may elect to receive common units. Each election shall be generally at or around the first board meeting in January of each calendar year and will be effective for the entire calendar year. The initial election under this plan was made effective January 20, 2005. A non-employee director may make a new election each calendar year. The total number of common units authorized under this compensation plan is 100,000. Each annual election shall be evidenced by an agreement, the Common Unit Compensation Agreement, between us and each non-employee director, and this agreement will contain the terms and conditions of each award. Pursuant to this agreement, all common units issued under this plan are subject to forfeiture restrictions that expire six months from the date of issuance. Until the forfeiture restrictions lapse, common units issued under the plan may not be sold, assigned, transferred, exchanged, or pledged by a non-employee director. In the event the 145 <PAGE> director's service as a director of KMR is terminated prior to the lapse of the forfeiture restriction either for cause, or voluntary resignation, each director shall, for no consideration, forfeit to us all common units to the extent then subject to the forfeiture restrictions. Common units with respect to which forfeiture restrictions have lapsed shall cease to be subject to any forfeiture restrictions, and we will provide each director a certificate representing the units as to which the forfeiture restrictions have lapsed. In addition, each non-employee director shall have the right to receive distributions with respect to the common units awarded to him under the plan, to vote such common units and to enjoy all other unitholder rights, including during the period prior to the lapse of the forfeiture restrictions. The number of common units to be issued to a non-employee director electing to receive the other cash compensation in the form of common units will equal such other cash compensation awarded, divided by the closing price of the common units on the New York Stock Exchange on the day the cash compensation is awarded (such price, the fair market value), rounded down to the nearest 50 common units. The common units will be issuable as specified in the Common Unit Compensation Agreement. A non-employee director electing to receive the other cash compensation in the form of common units will receive cash equal to the difference between (i) the other cash compensation awarded to such non-employee director and (ii) the number of common units to be issued to such non-employee director multiplied by the fair market value of a common unit. This cash payment shall be payable in four equal installments (together with the annual cash retainer) generally around March 31, June 30, September 30 and December 31 of the calendar year in which such cash compensation is awarded. On January 18, 2005, the date of adoption of the plan, each of KMR's three non-employee directors was awarded a cash retainer of $40,000 that will be paid quarterly during 2005, and other cash compensation of $79,750. Effective January 20, 2005, each non-employee director elected to receive the other cash compensation of $79,750 in the form of our common units and was issued 1,750 common units pursuant to the plan and its agreements (based on the $45.55 closing market price of our common units on January 18, 2005, as reported on the New York Stock Exchange). Also, consistent with the plan, the $37.50 of other cash compensation that did not equate to a whole common unit, based on the January 18, 2005 $45.55 closing price, will be paid to each of the non-employee directors as described above. No other compensation is to be paid to the non-employee directors during 2005. Contingent Debt We apply the disclosure provisions of Financial Accounting Standards Board Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" to our agreements that contain guarantee or indemnification clauses. These disclosure provisions expand those required by SFAS No. 5, "Accounting for Contingencies," by requiring a guarantor to disclose certain types of guarantees, even if the likelihood of requiring the guarantor's performance is remote. The following is a description of our contingent debt agreements. Cortez Pipeline Company Debt Pursuant to a certain Throughput and Deficiency Agreement, the partners of Cortez Pipeline Company (Kinder Morgan CO2 Company, L.P. - 50% partner; a subsidiary of Exxon Mobil Corporation - 37% partner; and Cortez Vickers Pipeline Company - 13% partner) are required, on a several, percentage ownership basis, to contribute capital to Cortez Pipeline Company in the event of a cash deficiency. The Throughput and Deficiency Agreement contractually supports the borrowings of Cortez Capital Corporation, a wholly-owned subsidiary of Cortez Pipeline Company, by obligating the partners of Cortez Pipeline Company to fund cash deficiencies at Cortez Pipeline Company, including cash deficiencies relating to the repayment of principal and interest on borrowings by Cortez Capital Corporation. Parent companies of the respective Cortez Pipeline Company partners further severally guarantee, on a percentage basis, the obligations of the Cortez Pipeline Company partners under the Throughput and Deficiency Agreement. Due to our indirect ownership of Cortez Pipeline Company through Kinder Morgan CO2 Company, L.P., we severally guarantee 50% of the debt of Cortez Capital Corporation. Shell Oil Company shares our several guaranty obligations jointly and severally through December 31, 2006. 146 <PAGE> As of December 31, 2004, the debt facilities of Cortez Capital Corporation consisted of: o $85 million of Series D notes due May 15, 2013; o a $125 million short-term commercial paper program; and o a $125 million five-year committed revolving credit facility due December 22, 2009 (to support the above-mentioned $125 million commercial paper program). As of December 31, 2004, Cortez Capital Corporation had $116.7 million of commercial paper outstanding with an average interest rate of 2.2623%, the average interest rate on the Series D notes was 7.0835% and there were no borrowings under the credit facility. Plantation Pipe Line Company Debt On April 30, 1997, Plantation Pipe Line Company entered into a $10 million, ten-year floating-rate term credit agreement. We, as an owner of Plantation Pipe Line Company, severally guaranteed this debt on a pro rata basis equivalent to our respective 51.17% ownership interest. During 1999, this agreement was amended to reduce the maturity date by three years. In April 2004, we extended the maturity to July 20, 2004. In July 2004, Plantation repaid the $10 million note outstanding and $175 million in outstanding commercial paper with funds of $190 million borrowed from its owners. We loaned Plantation $97.2 million, which corresponds to our 51.17% ownership interest, in exchange for a seven year note receivable bearing interest at the rate of 4.72% per annum. The note provides for semiannual payments of principal and interest on December 31 and June 30 each year beginning on December 31, 2004 based on a 25 year amortization schedule, with a final principal payment of $156.6 million due July 20, 2011. We funded our loan of $97.2 million with borrowings under our commercial paper program. An affiliate of ExxonMobil owns the remaining 48.83% equity interest in Plantation and funded the remaining $92.8 million on similar terms. Red Cedar Gas Gathering Company Debt In October 1998, Red Cedar Gas Gathering Company sold $55 million in aggregate principal amount of Senior Notes due October 31, 2010. The $55 million was sold in 10 different notes in varying amounts with identical terms. The Senior Notes are collateralized by a first priority lien on the ownership interests, including our 49% ownership interest, in Red Cedar Gas Gathering Company. The Senior Notes are also guaranteed by us and the other owner of Red Cedar Gas Gathering Company jointly and severally. The principal is to be repaid in seven equal installments beginning on October 31, 2004 and ending on October 31, 2010. As of December 31, 2004, $47.1 million in principal amount of notes were outstanding. Nassau County, Florida Ocean Highway and Port Authority Debt Nassau County, Florida Ocean Highway and Port Authority is a political subdivision of the State of Florida. During 1990, Ocean Highway and Port Authority issued its Adjustable Demand Revenue Bonds in the aggregate principal amount of $38.5 million for the purpose of constructing certain port improvements located in Fernandino Beach, Nassau County, Florida. A letter of credit was issued as security for the Adjustable Demand Revenue Bonds and was guaranteed by the parent company of Nassau Terminals LLC, the operator of the port facilities. In July 2002, we acquired Nassau Terminals LLC and became guarantor under the letter of credit agreement. In December 2002, we issued a $28 million letter of credit under our credit facilities and the former letter of credit guarantee was terminated. Principal payments on the bonds are made on the first of December each year and reductions are made to the letter of credit. As of December 31, 2004, the value of this letter of credit outstanding under our credit facility was $25.9 million. 147 <PAGE> 14. Risk Management Hedging Activities Certain of our business activities expose us to risks associated with changes in the market price of natural gas, natural gas liquids, crude oil and carbon dioxide. We use energy financial instruments to reduce our risk of changes in the prices of natural gas, natural gas liquids and crude oil markets (and carbon dioxide to the extent contracts are tied to crude oil prices) as discussed below. These risk management instruments are also called derivatives, which are defined as financial instruments or contracts whose value is derived from some other financial measure called the underlying, and includes payment provisions called the notional amount. The value of a derivative (for example, options, swaps, futures, etc.) is a function of the underlying (for example, commodity prices) and the notional amount (for example, payment in cash, commodities, etc.), and while the underlying changes due to changes in market conditions, the notional amount remains constant throughout the life of the derivative contract. Current accounting standards require derivatives to be reflected as assets or liabilities at their fair market values and the fair value of our 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, including: commodity futures and options contracts, fixed-price swaps, and basis swaps. Pursuant to our management's approved policy, we are to engage in these activities as a hedging mechanism against price volatility associated with: o pre-existing or anticipated physical natural gas, natural gas liquids and crude oil sales; o pre-existing or anticipated physical carbon dioxide sales that have pricing tied to crude oil prices; o natural gas purchases; and o system use and storage. Our risk management activities are primarily used in order to protect our profit margins and our risk management policies prohibit us from engaging in speculative trading. Commodity-related activities of our risk management group are monitored by our risk management committee, which is charged with the review and enforcement of our management's risk management policy. Specifically, our risk management committee is a separately designated standing committee comprised of eleven executive-level employees of KMI or KMGP Services Company, Inc. whose job responsibilities involve operations exposed to commodity market risk and other external risks in the ordinary course of business. Our risk management committee is chaired by our Chief Financial Officer and is charged with the following three responsibilities: o establish and review risk limits consistent with our risk tolerance philosophy; o recommend to the audit committee of our general partner's delegate any changes, modifications, or amendments to our trading policy; and o address and resolve any other high-level risk management issues. Our derivatives hedge the commodity price risks derived from our normal business activities, which include the sale of natural gas, natural gas liquids, oil and carbon dioxide, and these derivatives have been designated by us as cash flow hedges as defined by SFAS No. 133. SFAS No. 133 designates derivatives that hedge exposure to variable cash flows of forecasted transactions as cash flow hedges and the effective portion of the derivative's gain or loss is initially reported as a component of other comprehensive income (outside earnings) and subsequently is reclassified into earnings when the forecasted transaction affects earnings. If the transaction results in an asset or liability, amounts in accumulated other comprehensive income should be reclassified into earnings when the asset or liability affects earnings through cost of sales, depreciation, interest expense, etc. To be considered effective, 148 <PAGE> changes in the value of the derivative or its resulting cash flows must substantially offset changes in the value or cash flows of the item being hedged. The ineffective portion of the gain or loss and any component excluded from the computation of the effectiveness of the derivative instrument is reported in earnings immediately. The gains and losses included in "Accumulated other comprehensive loss" in our accompanying consolidated balance sheets are reclassified into earnings as the hedged sales and purchases take place. Approximately $171.9 million of the Accumulated other comprehensive loss balance of $457.3 million representing unrecognized net losses on derivative activities as of December 31, 2004 is expected to be reclassified into earnings during the next twelve months. During the year ended December 31, 2004, we reclassified $192.3 million of Accumulated other comprehensive income into earnings as a result of hedged sales and purchases during the period. This amount includes the accumulated other comprehensive loss balance of $155.8 million representing unrecognized net losses on derivative activities as of December 31, 2003. For each of the years ended December 31, 2004, 2003 and 2002, no gains or losses included in "Accumulated other comprehensive loss" were reclassified into earnings as a result of the discontinuance of cash flow hedges due to a determination that the forecasted transactions would no longer occur by the end of the originally specified time period. We recognized a gain of $0.1 million during 2004, a gain of $0.5 million during 2003 and a gain of $0.7 million during 2002 as a result of ineffective hedges. All of these amounts are reported within the caption "Gas purchases and other costs of sales" in our accompanying consolidated statements of income. For each of the years ended December 31, 2004, 2003 and 2002, we did not exclude any component of the derivative instruments' gain or loss from the assessment of hedge effectiveness. The differences between the current market value and the original physical contracts value associated with our hedging activities are included within "Other current assets", "Accrued other current liabilities", "Deferred charges and other assets" and "Other long-term liabilities and deferred credits" in our accompanying consolidated balance sheets. The following table summarizes the net fair value of our energy financial instruments associated with our risk management activities and included on our accompanying consolidated balance sheets as of December 31, 2004 and December 31, 2003 (in thousands): December December 31, 31, 2004 2003 December 31, December 31, 2004 2003 --------------- ------------- Derivatives-net asset/(liability) Other current assets...................... $ 41,010 $ 18,157 Deferred charges and other assets......... 17,408 2,722 Accrued other current liabilities......... (218,967) (90,426) Other long-term liabilities and deferred credits................................. $ (309,035) $ (101,463) As of December 31, 2004, we had an outstanding $50 million letter of credit issued to Morgan Stanley in support of our hedging activities. In late February 2005, we increased this letter of credit to $125 million. Given our portfolio of businesses as of December 31, 2004, our principal uses of derivative energy financial instruments will be to mitigate the risk associated with market movements in the price of energy commodities. Our net short natural gas derivatives position primarily represents our hedging of anticipated future natural gas purchases and sales. Our net short crude oil derivatives position represents our crude oil derivative purchases and sales made to hedge anticipated oil purchases and sales. Finally, our net short natural gas liquids derivatives position reflects the hedging of our forecasted natural gas liquids purchases and sales. As of December 31, 2004, the maximum length of time over which we have hedged our exposure to the variability in future cash flows associated with commodity price risk is through December 2010. As of December 31, 2004, our commodity contracts and over-the-counter swaps and options (in thousands) consisted of the following: 149 <PAGE> <TABLE> <CAPTION> Over the Counter Swaps and Commodity Options Contracts Contracts Total --------- ---------- ------ (Dollars in thousands) <S> <C> <C> <C> Deferred Net (Loss) Gain........................... $ 3,614 $ (473,308) $ (469,694) Contract Amounts -- Gross.......................... $ 48,018 $ 1,314,281 $ 1,362,299 Contract Amounts -- Net............................ $ (15,320) $ (937,566) $ (952,886) (Number of contracts(1)) Natural Gas Notional Volumetric Positions: Long.............. 293 1,339 1,632 Notional Volumetric Positions: Short............. (556) (1,822) (2,378) Net Notional Totals to Occur in 2005............. (263) (638) (901) Net Notional Totals to Occur in 2006 and Beyond.. -- (155) (155) Crude Oil Notional Volumetric Positions: Long.............. -- 429 429 Notional Volumetric Positions: Short............. -- (41,541) (41,541) Net Notional Totals to Occur in 2005............. -- (16,389) (16,389) Net Notional Totals to Occur in 2006 and Beyond.. -- (24,723) (24,723) Natural Gas Liquids Notional Volumetric Positions: Long.............. -- -- -- Notional Volumetric Positions: Short............. -- (298) (298) Net Notional Totals to Occur in 2005............. -- (298) (298) Net Notional Totals to Occur in 2006 and Beyond.. -- -- -- </TABLE> - ---------- (1) A term of reference describing a unit of commodity trading. One natural gas contract equals 10,000 MMBtus. One crude oil or natural gas liquids contract equals 1,000 barrels. Our over-the-counter swaps and options are with a number of parties, who principally have investment grade credit ratings. We both owe money and are owed money under these financial instruments; however, as of both December 31, 2004 and December 31, 2003, we were essentially in a net payable position and had virtually no amounts owed to us from other parties. In addition, defaults by counterparties under over-the-counter swaps and options could expose us to additional commodity price risks in the event that we are unable to enter into replacement contracts for such swaps and options on substantially the same terms. Alternatively, we may need to pay significant amounts to the new counterparties to induce them to enter into replacement swaps and options on substantially the same terms. While we enter into derivative transactions principally with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that from time to time losses will result from counterparty credit risk in the future. 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. Our margin deposits associated with commodity contract positions were $1.6 million as of December 31, 2004 and $10.3 million as of December 31, 2003. Our margin deposits associated with over-the-counter swap partners were $2.8 million as of December 31, 2004 and $7.7 million as of December 31, 2003. Certain of our business activities expose us to foreign currency fluctuations. However, due to the limited size of this exposure, we do not believe the risks associated with changes in foreign currency will have a material adverse effect on our business, financial position, results of operations or cash flows. Interest Rate Swaps In order to maintain a cost effective capital structure, it is our policy to borrow funds using a mix of fixed rate and variable rate debt. As of December 31, 2004 and 2003, we were a party to interest rate swap agreements with notional principal amounts of $2.3 billion and $2.1 billion, respectively. We entered into these agreements for the purpose of hedging the interest rate risk associated with our fixed and variable rate debt obligations. 150 <PAGE> As of December 31, 2004, a notional principal amount of $2.2 billion of these agreements effectively converts the interest expense associated with the following series of our senior notes from fixed rates to variable rates based on an interest rate of LIBOR plus a spread: o $200 million principal amount of our 8.0% senior notes due March 15, 2005; o $200 million principal amount of our 5.35% senior notes due August 15, 2007; o $250 million principal amount of our 6.30% senior notes due February 1, 2009; o $200 million principal amount of our 7.125% senior notes due March 15, 2012; o $250 million principal amount of our 5.0% senior notes due December 15, 2013; o $200 million principal amount of our 5.125% senior notes due November 15, 2014; o $300 million principal amount of our 7.40% senior notes due March 15, 2031; o $200 million principal amount of our 7.75% senior notes due March 15, 2032; and o $400 million principal amount of our 7.30% senior notes due August 15, 2033. These swap agreements have termination dates that correspond to the maturity dates of the related series of senior notes, therefore, as of December 31, 2004, the maximum length of time over which we have hedged a portion of our exposure to the variability in the value of this debt due to interest rate risk is through August 15, 2033. The swap agreements related to our 7.40% senior notes contain mutual cash-out provisions at the then-current economic value every seven years. The swap agreements related to our 7.125% senior notes contain cash-out provisions at the then-current economic value in March 2009. The swap agreements related to our 7.75% senior notes and our 7.30% senior notes contain mutual cash-out provisions at the then-current economic value every five or seven years. These interest rate swaps have been designated as fair value hedges as defined by SFAS No. 133. SFAS No. 133 designates derivatives that hedge a recognized asset or liability's exposure to changes in their fair value as fair value hedges and the gain or loss on fair value hedges are to be recognized in earnings in the period of change together with the offsetting loss or gain on the hedged item attributable to the risk being hedged. The effect of that accounting is to reflect in earnings the extent to which the hedge is not effective in achieving offsetting changes in fair value. As of December 31, 2004, we also had swap agreements that effectively convert the interest expense associated with $100 million of our variable rate debt to fixed rate debt. Half of these agreements, converting $50 million of our variable rate debt to fixed rate debt, mature on August 1, 2005, and the remaining half mature on September 1, 2005. These swaps are designated as a cash flow hedge of the risk associated with changes in the designated benchmark interest rate (in this case, one-month LIBOR) related to forecasted payments associated with interest on an aggregate of $100 million of our portfolio of commercial paper. Our interest rate swaps meet the conditions required to assume no ineffectiveness under SFAS No. 133 and, therefore, we have accounted for them using the "shortcut" method prescribed for fair value hedges by SFAS No. 133. Accordingly, we adjust the carrying value of each swap to its fair value each quarter, with an offsetting entry to adjust the carrying value of the debt securities whose fair value is being hedged. We record interest expense equal to the variable rate payments or fixed rate payments under the swaps. Interest expense is accrued monthly and paid semi-annually. The differences between fair value and the original carrying value associated with our interest rate swap agreements are included within "Deferred charges and other assets" and "Other long-term liabilities and deferred credits" in our accompanying consolidated balance sheets. The offsetting entry to adjust the carrying value of the 151 <PAGE> debt securities whose fair value was being hedged is recognized as "Market value of interest rate swaps" on our accompanying consolidated balance sheets. The following table summarizes the net fair value of our interest rate swap agreements associated with our interest rate risk management activities and included on our accompanying consolidated balance sheets as of December 31, 2004 and December 31, 2003 (in thousands): December 31, December 31, 2004 2003 --------------- ------------ Derivatives-net asset/(liability) Deferred charges and other assets............ $ 132,210 $ 129,618 Other long-term liabilities and deferred credits...................................... (2,057) (8,154) ----------- ------------ Market value of interest rate swaps........ $ 130,153 $ 121,464 =========== ============ We are exposed to credit related losses in the event of nonperformance by counterparties to these interest rate swap agreements. While we enter into derivative transactions primarily with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that from time to time losses will result from counterparty credit risk. 15. Reportable Segments We divide our operations into four reportable business segments: o Products Pipelines; o Natural Gas Pipelines; o CO2; and o Terminals. Each segment uses the same accounting policies as those described in the summary of significant accounting policies (see Note 2). We evaluate performance principally based on each segments' earnings before depreciation, depletion and amortization, which exclude general and administrative expenses, third-party debt costs and interest expense, unallocable interest income and minority interest. Our reportable segments are strategic business units that offer different products and services. Each segment is managed separately because each segment involves different products and marketing strategies. Our Products Pipelines segment derives its revenues primarily from the transportation and terminaling of refined petroleum products, including gasoline, diesel fuel, jet fuel and natural gas liquids. Our Natural Gas Pipelines segment derives its revenues primarily from the transmission, storage, gathering and sale of natural gas. Our CO2 segment derives its revenues primarily from the transportation and marketing of carbon dioxide used as a flooding medium for recovering crude oil from mature oil fields and from the production and sale of crude oil from fields in the Permian Basin of West Texas. Our Terminals segment derives its revenues primarily from the transloading and storing of refined petroleum products and dry and liquid bulk products, including coal, petroleum coke, cement, alumina, salt, and chemicals. Financial information by segment follows (in thousands): <TABLE> <CAPTION> 2004 2003 2002 -------------- -------------- ------------- <S> <C> <C> <C> Revenues Products Pipelines............................ $ 645,249 $ 585,376 $ 576,542 Natural Gas Pipelines......................... 6,252,921 5,316,853 3,086,187 CO2........................................... 492,834 248,535 146,280 Terminals..................................... 541,857 473,558 428,048 ------------- ------------- ------------- Total consolidated revenues................... $ 7,932,861 $ 6,624,322 $ 4,237,057 ============= ============= ============= </TABLE> 152 <PAGE> <TABLE> <CAPTION> 2004 2003 2002 -------------- -------------- ------------- <S> <C> <C> <C> Operating expenses(a) Products Pipelines............................. $ 191,425 $ 169,526 $ 169,782 Natural Gas Pipelines.......................... 5,862,159 4,967,531 2,784,278 CO2............................................ 173,382 82,055 50,524 Terminals...................................... 272,766 229,054 213,929 ------------- ------------- ------------- Total consolidated operating expenses.......... $ 6,499,732 $ 5,448,166 $ 3,218,513 ============= ============= ============= Depreciation, depletion and amortization Products Pipelines........................... $ 71,263 $ 67,345 $ 64,388 Natural Gas Pipelines........................ 53,112 53,785 48,411 CO2.......................................... 121,361 60,827 29,196 Terminals.................................... 42,890 37,075 30,046 ------------- ------------- ------------- Total consol. depreciation, depletion and amortiz.................................... $ 288,626 $ 219,032 $ 172,041 ============= ============= ============= Earnings from equity investments Products Pipelines............................ $ 29,050 $ 30,948 $ 28,998 Natural Gas Pipelines......................... 19,960 24,012 23,887 CO2........................................... 34,179 37,198 36,328 Terminals..................................... 1 41 45 ------------- ------------- ------------- Total consolidated equity earnings............ $ 83,190 $ 92,199 $ 89,258 ============= ============= ============= Amortization of excess cost of equity investments Products Pipelines............................ $ 3,281 $ 3,281 $ 3,281 Natural Gas Pipelines......................... 277 277 277 CO2........................................... 2,017 2,017 2,017 Terminals..................................... -- -- -- -------------- -------------- ------------- Total consol. amortization of excess cost of invests..................................... $ 5,575 $ 5,575 $ 5,575 ============= ============= ============= Interest income Products Pipelines............................. $ 2,091 $ -- $ -- Natural Gas Pipelines.......................... -- -- -- CO2............................................ -- -- -- Terminals...................................... -- -- -- -------------- -------------- ------------- Total segment interest income.................. 2,091 -- -- Unallocated interest income.................... 1,199 1,420 1,819 ------------- ------------- ------------- Total consolidated interest income............. $ 3,290 $ 1,420 $ 1,819 ============= ============= ============= Other, net-income (expense)(b) Products Pipelines............................ $ (28,025) $ 6,471 $ (14,000) Natural Gas Pipelines......................... 9,434 1,082 36 CO2........................................... 4,152 (40) 112 Terminals..................................... 18,255 88 15,550 ------------- ------------- ------------- Total segment Other, net-income (expense)...... 3,816 7,601 1,698 Loss from early extinguishment of debt......... (1,562) -- -- -------------- -------------- ------------- Total consolidated Other, net-income (expense). $ 2,254 $ 7,601 $ 1,698 ============= ============= ============= Income tax benefit (expense) Products Pipelines............................. $ (12,075) $ (11,669) $ (10,154) Natural Gas Pipelines.......................... (1,895) (1,066) (378) CO2............................................ (147) (39) -- Terminals(c)................................... (5,609) (3,857) (4,751) -------------- -------------- ------------- Total consolidated income tax benefit(expense). $ (19,726) $ (16,631) $ (15,283) ============= ============= ============= Segment earnings Products Pipelines............................. $ 370,321 $ 370,974 $ 343,935 Natural Gas Pipelines.......................... 364,872 319,288 276,766 CO2............................................ 234,258 140,755 100,983 Terminals...................................... 238,848 203,701 194,917 ------------- ------------- ------------- Total segment earnings(d)...................... 1,208,299 1,034,718 916,601 Interest and corporate administrative expenses(e).................................. (376,721) (337,381) (308,224) ------------- ------------- ------------- Total consolidated net income.................. $ 831,578 $ 697,337 $ 608,377 ============= ============= ============= </TABLE> 153 <PAGE> <TABLE> <CAPTION> 2004 2003 2002 -------------- -------------- ------------- <S> <C> <C> <C> Segment earnings before depreciation, depletion, amortization and amortization of excess cost of equity investments(f) Products Pipelines............................. $ 444,865 $ 441,600 $ 411,604 Natural Gas Pipelines.......................... 418,261 373,350 325,454 CO2............................................ 357,636 203,599 132,196 Terminals...................................... 281,738 240,776 224,963 ------------- ------------- ------------- Total segment earnings before DD&A............. 1,502,500 1,259,325 1,094,217 Consolidated depreciation and amortization..... (288,626) (219,032) (172,041) Consolidated amortization of excess cost of invests...................................... (5,575) (5,575) (5,575) Interest and corporate administrative expenses. (376,721) (337,381) (308,224) ------------- ------------- ------------- Total consolidated net income.................. $ 831,578 $ 697,337 $ 608,377 ============= ============= ============= Capital expenditures Products Pipelines........................... $ 213,746 $ 94,727 $ 62,199 Natural Gas Pipelines........................ 106,358 101,679 194,485 CO2.......................................... 302,935 272,177 163,183 Terminals.................................... 124,223 108,396 122,368 ------------- ------------- ------------- Total consolidated capital expenditures(g)... $ 747,262 $ 576,979 $ 542,235 ============= ============= ============= Investments at December 31 Products Pipelines........................... $ 223,196 $ 226,680 $ 220,203 Natural Gas Pipelines........................ 174,296 164,924 157,778 CO2.......................................... 15,503 12,591 71,283 Terminals.................................... 260 150 2,110 ------------- ------------- ------------- Total consolidated investments............... $ 413,255 $ 404,345 $ 451,374 ============= ============= ============= Assets at December 31 Products Pipelines........................... $ 3,651,657 $ 3,198,107 $ 3,088,799 Natural Gas Pipelines........................ 3,691,457 3,253,792 3,121,674 CO2.......................................... 1,527,810 1,177,645 613,980 Terminals.................................... 1,576,333 1,368,279 1,165,096 ------------- ------------- ------------- Total segment assets......................... 10,447,257 8,997,823 7,989,549 Corporate assets(h).......................... 105,685 141,359 364,027 ------------- ------------- ------------- Total consolidated assets.................... $ 10,552,942 $ 9,139,182 $ 8,353,576 ============= ============= ============= </TABLE> (a) Includes natural gas purchases and other costs of sales, operations and maintenance expenses, fuel and power expenses and taxes, other than income taxes. (b) 2004 amounts include environmental liability adjustments resulting in a $30.6 million expense to our Products Pipelines business segment, a $7.6 million earnings increase to our Natural Gas Pipelines business segment, a $4.1 million earnings increase to our CO2 business segment and an $18.7 million earnings increase to our Terminals business segment. 2002 amounts include environmental liability adjustments resulting in a $15.7 million expense to our Products Pipelines business segment and a $16.0 million earnings increase to our Terminals business segment. (c) 2004 amount includes expenses of $0.1 million related to environmental expense adjustments. (d) Includes revenues, earnings from equity investments, income taxes, allocable interest income and other, net, less operating expenses, depreciation, depletion and amortization, and amortization of excess cost of equity investments. (e) Includes unallocated interest income, interest and debt expense, general and administrative expenses, minority interest expense, loss from early extinguishment of debt (2004 only) and cumulative effect adjustment from a change in accounting principle (2003 only). (f) Includes revenues, earnings from equity investments, income taxes, allocable interest income and other, net, less operating expenses. (g) Includes sustaining capital expenditures of $119,244 in 2004, $92,837 in 2003 and $76,967 in 2002. Sustaining capital expenditures are defined as capital expenditures which do not increase the capacity of an asset. (h) Includes cash, cash equivalents and certain unallocable deferred charges. 154 <PAGE> We do not attribute interest and debt expense to any of our reportable business segments. For each of the years ended December 31, 2004, 2003 and 2002, we reported (in thousands) total consolidated interest expense of $196,172, $182,777 and $178,279, respectively. Our total operating revenues are derived from a wide customer base. For each of the years ended December 31, 2004, 2003 and 2002, only one customer accounted for more than 10% of our total consolidated revenues. Total transactions within our Natural Gas Pipelines segment with CenterPoint Energy accounted for 14.3%, 16.8% and 15.6% of our total consolidated revenues during 2004, 2003 and 2002, respectively. 16. Litigation and Other Contingencies The tariffs we charge for transportation on our interstate common carrier pipelines are subject to rate regulation by the Federal Energy Regulatory Commission, referred to in this report as FERC, under the Interstate Commerce Act. The Interstate Commerce Act requires, among other things, that interstate petroleum products pipeline rates be just and reasonable and nondiscriminatory. Pursuant to FERC Order No. 561, effective January 1, 1995, interstate 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, expanded the circumstances under which interstate 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, 2004, 2003 and 2002, the application of the indexing methodology did not significantly affect tariff rates on our interstate petroleum products pipelines. SFPP, L.P. Federal Energy Regulatory Commission Proceedings SFPP, L.P., referred to in this report as SFPP, is the subsidiary limited partnership that owns our Pacific operations, excluding CALNEV Pipe Line LLC and related terminals acquired from GATX Corporation. Tariffs charged by SFPP are subject to certain proceedings at the FERC involving shippers' complaints regarding the interstate rates, as well as practices and the jurisdictional nature of certain facilities and services, on our Pacific operations' pipeline systems. OR92-8, et al. proceedings. FERC Docket No. OR92-8-000 et al., is a consolidated proceeding that began in September 1992 and includes a number of shipper complaints against certain rates and practices on SFPP's East Line (from El Paso, Texas to Phoenix, Arizona) and West Line (from Los Angeles, California to Tucson, Arizona), as well as SFPP's gathering enhancement fee at Watson Station in Carson, California. The complainants in the case are El Paso Refinery, L.P. (which settled with SFPP in 1996), Chevron Products Company, Navajo Refining Company (now Navajo Refining Company, L.P.), ARCO Products Company (now part of BP West Coast Products, LLC), Texaco Refining and Marketing Inc., Refinery Holding Company LP (now named Western Refining Company, L.P.), Mobil Oil Corporation (now part of ExxonMobil Oil Corporation) and Tosco Corporation (now part of ConocoPhillips Company). The FERC has ruled that the complainants have the burden of proof in this proceeding. A FERC administrative law judge held hearings in 1996, and issued an initial decision in September 1997. The initial decision held that all but one of SFPP's West Line rates were "grandfathered" under the Energy Policy Act of 1992 and therefore deemed to be just and reasonable; it further held that complainants had failed to prove "substantially changed circumstances" with respect to those rates and that they therefore could not be challenged in the Docket No. OR92-8 et al. proceedings, either for the past or prospectively. However, the initial decision also made rulings generally adverse to SFPP on certain cost of service issues relating to the evaluation of East Line rates, which are not "grandfathered" under the Energy Policy Act. Those issues included the capital structure to be used in computing SFPP's "starting rate base," the level of income tax allowance SFPP may include in rates and the recovery of civil and regulatory litigation expenses and certain pipeline reconditioning costs incurred by SFPP. The initial decision also held SFPP's Watson Station gathering enhancement service was subject to FERC jurisdiction and ordered SFPP to file a tariff for that service. 155 <PAGE> The FERC subsequently reviewed the initial decision, and issued a series of orders in which it adopted certain rulings made by the administrative law judge, changed others and modified a number of its own rulings on rehearing. Those orders began in January 1999, with FERC Opinion No. 435, and continued through June 2003. The FERC affirmed that all but one of SFPP's West Line rates are "grandfathered" and that complainants had failed to satisfy the threshold burden of demonstrating "substantially changed circumstances" necessary to challenge those rates. The FERC further held that the one West Line rate that was not grandfathered did not need to be reduced. The FERC consequently dismissed all complaints against the West Line rates in Docket Nos. OR92-8 et al. without any requirement that SFPP reduce, or pay any reparations for, any West Line rate. The FERC initially modified the initial decision's ruling regarding the capital structure to be used in computing SFPP's "starting rate base" to be more favorable to SFPP, but later reversed that ruling. The FERC also made certain modifications to the calculation of the income tax allowance and other cost of service components, generally to SFPP's disadvantage. On multiple occasions, the FERC required SFPP to file revised East Line rates based on rulings made in the FERC's various orders. SFPP was also directed to submit compliance filings showing the calculation of the revised rates, the potential reparations for each complainant and in some cases potential refunds to shippers. SFPP filed such revised East Line rates and compliance filings in March 1999, July 2000, November 2001 (revised December 2001), October 2002 and February 2003 (revised March 2003). Most of those filings were protested by particular SFPP shippers. The FERC has held that certain of the rates SFPP filed at the FERC's directive should be reduced retroactively and/or be subject to refund; SFPP has challenged the FERC's authority to impose such requirements in this context. While the FERC initially permitted SFPP to recover certain of its litigation, pipeline reconditioning and environmental costs, either through a surcharge on prospective rates or as an offset to potential reparations, it ultimately limited recovery in such a way that SFPP was not able to make any such surcharge or take any such offset. Similarly, the FERC initially ruled that SFPP would not owe reparations to any complainant for any period prior to the date on which that party's complaint was filed, but ultimately held that each complainant could recover reparations for a period extending two years prior to the filing of its complaint (except for Navajo, which was limited to one month of pre-complaint reparations under a settlement agreement with SFPP's predecessor). The FERC also ultimately held that SFPP was not required to pay reparations or refunds for Watson Station gathering enhancement fees charged prior to filing a FERC tariff for that service. In April 2003, SFPP paid complainants and other shippers reparations and/or refunds as required by FERC's orders. In August 2003, SFPP paid shippers an additional refund as required by FERC's most recent order in the Docket No. OR92-8 et al. proceedings. We made aggregate payments of $44.9 million in 2003 for reparations and refunds pursuant to a FERC order. Beginning in 1999, SFPP, the complainants and intervenor Ultramar Diamond Shamrock Corporation (now part of Valero Energy Corporation) filed petitions for review of FERC's Docket OR92-8 et al. orders in the United States Court of Appeals for the District of Columbia Circuit. Certain of those petitions were dismissed by the Court of Appeals as premature, and the remaining petitions were held in abeyance pending completion of agency action. However, in December 2002, the Court of Appeals returned to its active docket all petitions to review the FERC's orders in the case through November 2001 and severed petitions regarding later FERC orders. The severed orders were held in abeyance for later consideration. Briefing in the Court of Appeals was completed in August 2003, and oral argument took place on November 12, 2003. On July 20, 2004, the U.S. Court of Appeals for the District of Columbia Circuit issued an opinion affirming the FERC orders under review on most issues, vacating the tax provision that the FERC had allowed SFPP to include under the FERC's "Lakehead" policy giving a tax allowance to partnership pipelines and remanding for further FERC proceedings on other issues. The court held that, in the context of the Docket No. OR92-8, et al. proceedings, all of SFPP's West Line rates were grandfathered other than the charge for use of SFPP's Watson Station gathering enhancement facility and the rate for turbine fuel movements to Tucson under SFPP Tariff No. 18. It concluded that the FERC had a reasonable 156 <PAGE> basis for concluding that the addition of a West Line origin point at East Hynes, California did not involve a new "rate" for purposes of the Energy Policy Act. It rejected arguments from West Line Shippers that certain protests and complaints had challenged West Line rates prior to the enactment of the Energy Policy Act. The court also held that complainants had failed to satisfy their burden of demonstrating substantially changed circumstances, and therefore could not challenge grandfathered West Line rates in the Docket No. OR92-8 et al. proceedings. It specifically rejected arguments that other shippers could "piggyback" on the special Energy Policy Act exception permitting Navajo to challenge grandfathered West Line rates, which Navajo had withdrawn under a settlement with SFPP. The court remanded the changed circumstances issue "for further consideration" by the FERC in light of the court's decision, described below, regarding SFPP's tax allowance. The FERC had previously held in the OR96-2 proceeding that the tax allowance policy should not be used as a stand-alone factor in determining when there have been substantially changed circumstances. The court upheld the FERC's rulings on most East Line rate issues. However, it found the FERC's reasoning inadequate on some issues, including the tax allowance. The court held the FERC had sufficient evidence to use SFPP's December 1988 stand-alone capital structure to calculate its starting rate base as of June 1985. It rejected SFPP arguments that would have resulted in a higher starting rate base. The court analyzed at length the tax allowance for pipelines that are organized as partnerships. It concluded that the FERC had provided "no rational basis" on the record before it for giving SFPP a tax allowance, and denied recovery by SFPP of "income taxes not incurred and not paid." The court accepted the FERC's treatment of regulatory litigation costs, including the limitation of recoverable costs and their offset against "unclaimed reparations" - that is, reparations that could have been awarded to parties that did not seek them. The court also accepted the FERC's denial of any recovery for the costs of civil litigation by East Line shippers against SFPP based on the 1992 re-reversal of the six-inch line between Tucson and Phoenix. However, the court did not find adequate support for the FERC's decision to allocate the limited litigation costs that SFPP was allowed to recover in its rates equally between the East Line and the West Line, and ordered the FERC to explain that decision further on remand. The court held the FERC had failed to justify its decision to deny SFPP any recovery of funds spent to recondition pipe on the East Line, for which SFPP had spent nearly $6 million between 1995 and 1998. It concluded that the Commission's reasoning was inconsistent and incomplete, and remanded for further explanation, noting that "SFPP's shippers are presently enjoying the benefits of what appears to be an expensive pipeline reconditioning program without sharing in any of its costs." The court affirmed the FERC's rulings on reparations in all respects. It held the Arizona Grocery doctrine did not apply to orders requiring SFPP to file "interim" rates, and that "FERC only established a final rate at the completion of the OR92-8 proceedings." It held that the Energy Policy Act did not limit complainants' ability to seek reparations for up to two years prior to the filing of complaints against rates that are not grandfathered. It rejected SFPP's arguments that the FERC should not have used a "test period" to compute reparations, that it should have offset years in which there were underrecoveries against those in which there were overrecoveries, and that it should have exercised its discretion against awarding any reparations in this case. The court also rejected: o Navajo's argument that its prior settlement with SFPP's predecessor did not limit its right to seek reparations; o Valero's argument that it should have been permitted to recover reparations in the Docket No. OR92-8 et al. proceedings rather than waiting to seek them, as appropriate, in the Docket No. OR96-2 et al. proceedings; o arguments that the former ARCO and Texaco had challenged East Line rates when they filed a complaint in January 1994 and should therefore be entitled to recover East Line reparations; and 157 <PAGE> o Chevron's argument that its reparations period should begin two years before its September 1992 protest regarding the six-inch line reversal rather than its August 1993 complaint against East Line rates. On September 2, 2004, BP West Coast Products, ChevronTexaco, ConocoPhillips and ExxonMobil filed a petition for rehearing and rehearing en banc asking the Court of Appeals to reconsider its ruling that West Line rates were not subject to investigation at the time the Energy Policy Act was enacted. On September 3, 2004, SFPP filed a petition for rehearing asking the Court to confirm that the FERC has the same discretion to address the income tax allowance issue on remand that administrative agencies normally have when their decisions are set aside by reviewing courts because they have failed to provide a reasoned basis for their conclusions. On October 4, 2004, the Court of Appeals denied both petitions without further comment. On November 2, 2004, the Court of Appeals issued its mandate remanding the proceedings to the FERC. SFPP and shipper parties subsequently filed various pleadings with the FERC regarding the proper nature and scope of the remand proceedings. The FERC has not yet issued an order regarding the Docket No. OR92-8 remand proceedings, but on December 2, 2004, it issued a Notice of Inquiry and opened a new proceeding (Docket No. PL05-5) to consider how broadly the court's ruling on the tax allowance issue should affect the range of entities the FERC regulates. A number of parties filed comments in response to that notice on January 21, 2005. On December 17, 2004, the Court of Appeals issued orders directing that the petitions for review relating to FERC orders issued after November 2001, which had previously been severed from the main Court of Appeals docket, should continue to be held in abeyance pending completion of the remand proceedings before the FERC. On January 3, 2005, SFPP filed a petition for a writ of certiorari asking the United States Supreme Court to review the Court of Appeals' ruling that the Arizona Grocery doctrine does not apply to "interim" rates, and that "FERC only established a final rate at the completion of the OR92-8 proceedings." BP West Coast Products and ExxonMobil also filed a petition for certiorari, on December 30, 2004, seeking review of the Court of Appeals' ruling that there was no pending investigation of West Line rates at the time of enactment of the Energy Policy Act (and thus that those rates remained grandfathered). Oppositions to both petitions are currently due on March 7, 2005. We are continuing to review the potential impact of the Court of Appeals decision and prepare for proceedings before the FERC on the issues that have been remanded to it. In addition to participating in the FERC's proceedings on remand, we may also seek review by the United States Supreme Court on one or more issues. Sepulveda proceedings. In December 1995, Texaco filed a complaint at FERC (Docket No. OR96-2) alleging that movements on SFPP's Sepulveda pipelines (Line Sections 109 and 110) to Watson Station, in the Los Angeles basin, were subject to FERC's jurisdiction under the Interstate Commerce Act, and claimed that the rate for that service was unlawful. Several other West Line shippers filed similar complaints and/or motions to intervene. Following a hearing in March 1997, a FERC administrative law judge issued an initial decision holding that the movements on the Sepulveda pipelines were not subject to FERC jurisdiction. On August 5, 1997, the FERC reversed that decision. On October 6, 1997, SFPP filed a tariff establishing the initial interstate rate for movements on the Sepulveda pipelines at the pre-existing rate of five cents per barrel. Several shippers protested that rate. In December 1997, SFPP filed an application for authority to charge a market-based rate for the Sepulveda service, which application was protested by several parties. On September 30, 1998, the FERC issued an order finding that SFPP lacks market power in the Watson Station destination market and set a hearing to determine whether SFPP possessed market power in the origin market. Following a hearing, on December 21, 2000, an administrative law judge found that SFPP possessed market power over the Sepulveda origin market. On February 28, 2003, the FERC issued an order upholding that decision. SFPP filed a request for rehearing of that order on March 31, 2003. The FERC denied SFPP's request for rehearing on July 9, 2003. As part of its February 28, 2003 order denying SFPP's application for market-based ratemaking authority, the FERC remanded to the ongoing litigation in Docket No. OR96-2, et al. the question of whether SFPP's current rate 158 <PAGE> for service on the Sepulveda line is just and reasonable. A hearing in this proceeding is scheduled to commence on February 15, 2005. OR96-2; OR97-2; OR98-1. et al. proceedings. In October 1996, Ultramar Diamond Shamrock Corporation filed a complaint at FERC (Docket No. OR97-2) challenging SFPP's West Line rates, claiming they were unjust and unreasonable and no longer subject to grandfathering. In October 1997, ARCO, Mobil and Texaco filed a complaint at the FERC (Docket No. OR98-1) challenging the justness and reasonableness of all of SFPP's interstate rates, raising claims against SFPP's East and West Line rates similar to those that have been at issue in Docket Nos. OR92-8, et al. discussed above, but expanding them to include challenges to SFPP's grandfathered interstate rates from the San Francisco Bay area to Reno, Nevada and from Portland to Eugene, Oregon - the North Line and Oregon Line. In November 1997, Ultramar filed a similar, expanded complaint (Docket No. OR98-2). Tosco Corporation filed a similar complaint in April 1998. The shippers seek both reparations and prospective rate reductions for movements on all of SFPP's lines. The FERC accepted the complaints and consolidated them into one proceeding (Docket No. OR96-2, et al.), but held them in abeyance pending a FERC decision on review of the initial decision in Docket Nos. OR92-8, et al. In a companion order to Opinion No. 435, the FERC gave the complainants an opportunity to amend their complaints in light of Opinion No. 435, which the complainants did in January 2000. In August 2000, Navajo and Western filed complaints against SFPP's East Line rates and Ultramar filed an additional complaint updating its pre-existing challenges to SFPP's interstate pipeline rates. These complaints were consolidated with the ongoing proceeding in Docket No. OR96-2, et al. A hearing in this consolidated proceeding was held from October 2001 to March 2002. A FERC administrative law judge issued his initial decision on June 24, 2003. The initial decision found that, for the years at issue, the complainants had shown substantially changed circumstances for rates on SFPP's West, North and Oregon Lines and for SFPP's fee for gathering enhancement service at Watson Station and thus found that those rates should not be "grandfathered" under the Energy Policy Act of 1992. The initial decision also found that most of SFPP's rates at issue were unjust and unreasonable. On March 26, 2004, the FERC issued an order on the phase one initial decision. The FERC's phase one order reversed the initial decision by finding that SFPP's rates for its North and Oregon Lines should remain "grandfathered" and amended the initial decision by finding that SFPP's West Line rates (i) to Yuma, Tucson and CalNev, as of 1995, and (ii) to Phoenix, as of 1997, should no longer be "grandfathered" and are not just and reasonable. The FERC's phase one order did not address prospective West Line rates and whether reparations are necessary. As discussed below, those issues have been addressed in the non-binding phase two initial decision recently issued by the presiding administrative law judge. The FERC's phase one order also did not address the "grandfathered" status of the Watson Station fee, noting that it would address that issue once it was ruled on by the United States Court of Appeals for the District of Columbia Circuit in its review of the FERC's Opinion No. 435 orders. Several of the participants in the proceeding requested rehearing of the FERC's phase one order. FERC action on those requests is pending. In addition, several participants, including SFPP, filed petitions with the United States Court of Appeals for the District of Columbia Circuit for review of the FERC's phase one order. On August 13, 2004, the FERC filed a motion to dismiss the pending petitions for review of the phase one order, which Petitioners, including SFPP, answered on August 30, 2004. On December 20, 2004, the Court referred the FERC's motion to the merits panel and directed the parties to address the issues in that motion on brief, thus effectively dismissing the FERC's motion. In the same order, the Court granted a motion to hold the petitions for review of the FERC's phase one order in abeyance and directed the parties to file motions to govern future proceeding 30 days after FERC disposition of the pending rehearing requests. The FERC's phase one order also held that SFPP failed to seek authorization for the accounting entries necessary to reflect in SFPP's books, and thus in its annual report to FERC ("FERC Form 6"), the purchase price adjustment ("PPA") arising from SFPP's 1998 acquisition by us. The phase one order directed SFPP to file for permission to reflect the PPA in its FERC Form 6 for the calendar year 1998 and each subsequent year. In its April 26, 2004 compliance filing, SFPP noted that it had previously requested such permission and that the FERC's regulations require an oil pipeline to include a PPA in its Form 6 without first seeking FERC permission to do so. Several parties protested SFPP's compliance filing. SFPP answered those protests, and FERC action on this matter is pending. 159 <PAGE> On September 9, 2004, the presiding administrative law judge issued his non-binding initial decision in the phase two portion of this proceeding. If affirmed by the FERC, the phase two initial decision would establish the basis for prospective rates and the calculation of reparations for complaining shippers with respect to the West Line and East Line. However, as with the phase one initial decision, the phase two initial decision must be fully reviewed by the FERC, which may accept, reject or modify the decision. A FERC order on phase two of the case is not expected before the second quarter of 2005. Any such order may be subject to further FERC review, review by the United States Court of Appeals for the District of Columbia Circuit, or both. We are not able to predict with certainty the final outcome of the pending FERC proceedings involving SFPP, should they be carried through to their conclusion, or whether we can reach a settlement with some or all of the complainants. The final outcome will depend, in part, on the outcomes of the appeals of these proceedings and the OR92-8, et al. proceedings taken by SFPP, complaining shippers, and an intervenor. We estimated, as of December 31, 2003, that shippers' claims for reparations totaled approximately $154 million and that prospective rate reductions would have an aggregate average annual impact of approximately $45 million. As the timing for implementation of rate reductions and the payment of reparations is extended, total estimated reparations and the interest accruing on the reparations increase. For each calendar quarter of delay in the implementation of rate reductions sought, we estimate that reparations and accrued interest accumulates by approximately $9 million. We now assume that any potential rate reductions will be implemented no earlier than the third quarter of 2005 and that reparations and accrued interest thereon will be paid no earlier than the third quarter of 2006; however, the timing, and nature, of any rate reductions and reparations that may be ordered will likely be affected by the FERC's income tax allowance inquiry in Docket No. PL05-5 and the FERC's disposition of issues remanded by the D.C. Circuit in the BP West Coast decision. If the phase two initial decision were to be largely adopted by the FERC, the estimated reparations and rate reductions would be larger than noted above; however, we continue to estimate the combined annual impact of the rate reductions and the capital costs associated with financing the payment of reparations sought by shippers and accrued interest thereon to be approximately 15 cents of distributable cash flow per unit. We believe, however, that the ultimate resolution of these complaints will be for amounts substantially less than the amounts sought. Chevron complaint OR02-4 proceedings. On February 11, 2002, Chevron, an intervenor in the Docket No. OR96-2, et al. proceeding, filed a complaint against SFPP in Docket No. OR02-4 along with a motion to consolidate the complaint with the Docket No. OR96-2, et al. proceeding. On May 21, 2002, the FERC dismissed Chevron's complaint and motion to consolidate. Chevron filed a request for rehearing, which the FERC dismissed on September 25, 2002. In October 2002, Chevron filed a request for rehearing of the FERC's September 25, 2002 Order, which the FERC denied on May 23, 2003. On July 1, 2003, Chevron filed a petition for review of this denial at the U.S. Court of Appeals for the District of Columbia Circuit. On August 18, 2003, SFPP filed a motion to dismiss Chevron's petition on the basis that Chevron lacks standing to bring its appeal and that the case is not ripe for review. Chevron answered on September 10, 2003. SFPP's motion was pending, when the Court of Appeals, on December 8, 2003, granted Chevron's motion to hold the case in abeyance pending the outcome of the appeal of the Docket No. OR92-8, et al. proceeding. On January 8, 2004, the Court of Appeals granted Chevron's motion to have its appeal of the FERC's decision in Docket No. OR03-5 (see below) consolidated with Chevron's appeal of the FERC's decision in the Docket No. OR02-4 proceeding. On December 10, 2004, the Court dismissed Chevron's petition for review in Docket No. OR03-5 and set Chevron's appeal of the FERC's orders in OR02-4 for briefing. On January 4, 2005, the Court granted Chevron's request to hold such briefing in abeyance until after final disposition of the OR96-2 proceeding. Chevron continues to participate in the Docket No. OR96-2 et al. proceeding as an intervenor. OR03-5 proceedings. On June 30, 2003, Chevron filed another complaint against SFPP - substantially similar to its previous complaint - and moved to consolidate the complaint with the Docket No. OR96-2, et al. proceeding. This complaint was docketed as Docket No. OR03-5. Chevron requested that this new complaint be treated as if it were an amendment to its complaint in Docket No. OR02-4, which was previously dismissed by the FERC. By this request, Chevron sought to, in effect, back-date its complaint, and claim for reparations, to February 2002. SFPP answered Chevron's complaint on July 22, 2003, opposing Chevron's requests for consolidation and for the back-dating of its complaint. On October 28, 2003, the FERC accepted Chevron's complaint, but held it in abeyance 160 <PAGE> pending the outcome of the Docket No. OR96-2, et al. proceeding. The FERC denied Chevron's request for consolidation and for back-dating. On November 21, 2003, Chevron filed a petition for review of the FERC's October 28, 2003 Order at the Court of Appeals for the District of Columbia Circuit. On January 8, 2004, the Court of Appeals granted Chevron's motion to have its appeal consolidated with Chevron's appeal of the FERC's decision in the Docket No. OR02-4 proceeding and to have the two appeals held in abeyance pending the outcome of the appeal of the Docket No. OR92-8, et al. proceeding. On August 13, 2004, the FERC filed a motion to dismiss the pending petitions for review of the FERC's orders in the OR02-4 and OR03-5 proceedings. SFPP filed a motion to dismiss Chevron's petitions for review on August 18, 2004. On December 10, 2004, the Court granted the motions to dismiss. OR04-3 proceeding. On September 21, 2004, America West Airlines, Inc., Southwest Airlines, Co., Northwest Airlines, Inc. and Continental Airlines, Inc. (collectively "Airlines") filed a complaint against SFPP at the FERC. The Airlines' complaint alleges that the rates on SFPP's West Line and SFPP's charge for its gathering enhancement service at Watson Station are not just and reasonable. The Airlines seek rate reductions and reparations for two years prior to the filing of their complaint. BP West Coast Products LLC and ExxonMobil Oil Corporation, ConocoPhillips Company, Navajo Refining Company, L.P., and ChevronTexaco Products Company all filed timely motions to intervene in this proceeding. Valero Marketing and Supply Company filed a motion to intervene one day after the deadline. SFPP answered the Airlines' complaint on October 12, 2004. On October 29, 2004, the Airlines filed a response to SFPP's answer and on November 12, 2004, SFPP replied to the Airlines' response. FERC action on the complaint is pending. OR05-4 proceeding. On December 22, 2004, BP West Coast Products LLC and ExxonMobil Oil Corporation filed a complaint against SFPP at the FERC. The complaint alleges that SFPP's interstate rates are not just and reasonable, that certain rates found grandfathered by the FERC are not entitled to such status, and, if so entitled, that "substantially changed circumstances" have occurred, removing such protection. The complainants seek rate reductions and reparations for two years prior to the filing of their complaint and ask that the complaint be consolidated with the Airlines' complaint in the OR04-3 proceeding. ConocoPhillips Company, Navajo Refining Company, L.P., and Western Refining Company, L.P. all filed timely motions to intervene in this proceeding. SFPP answered the complaint on January 24, 2005. FERC action on the complaint is pending. OR05-5 proceeding. On December 29, 2004, ConocoPhillips filed a complaint against SFPP at the FERC. The complaint alleges that SFPP's interstate rates are not just and reasonable, that certain rates found grandfathered by the FERC are not entitled to such status, and, if so entitled, that "substantially changed circumstances" have occurred, removing such protection. ConocoPhillips seeks rate reductions and reparations for two years prior to the filing of their complaint. BP West Coast Products LLC and ExxonMobil Oil Corporation, Navajo Refining Company, L.P., and Western Refining Company, L.P. all filed timely motions to intervene in this proceeding. SFPP answered the complaint on January 28, 2005. FERC action on the complaint is pending. California Public Utilities Commission Proceeding ARCO, Mobil and Texaco filed a complaint against SFPP with the California Public Utilities Commission on April 7, 1997. The complaint challenges rates charged by SFPP for intrastate transportation of refined petroleum products through its pipeline system in the State of California and requests prospective rate adjustments. On October 1, 1997, the complainants filed testimony seeking prospective rate reductions aggregating approximately $15 million per year. On August 6, 1998, the CPUC issued its decision dismissing the complainants' challenge to SFPP's intrastate rates. On June 24, 1999, the CPUC granted limited rehearing of its August 1998 decision for the purpose of addressing the proper ratemaking treatment for partnership tax expenses, the calculation of environmental costs and the public utility status of SFPP's Sepulveda Line and its Watson Station gathering enhancement facilities. In pursuing these rehearing issues, complainants sought prospective rate reductions aggregating approximately $10 million per year. 161 <PAGE> On March 16, 2000, SFPP filed an application with the CPUC seeking authority to justify its rates for intrastate transportation of refined petroleum products on competitive, market-based conditions rather than on traditional, cost-of-service analysis. On April 10, 2000, ARCO and Mobil filed a new complaint with the CPUC asserting that SFPP's California intrastate rates are not just and reasonable based on a 1998 test year and requesting the CPUC to reduce SFPP's rates prospectively. The amount of the reduction in SFPP rates sought by the complainants is not discernible from the complaint. The rehearing complaint was heard by the CPUC in October 2000 and the April 2000 complaint and SFPP's market-based application were heard by the CPUC in February 2001. All three matters stand submitted as of April 13, 2001, and resolution of these submitted matters may occur within the first or second quarters of 2005. The CPUC subsequently issued a resolution approving a 2001 request by SFPP to raise its California rates to reflect increased power costs. The resolution approving the requested rate increase also required SFPP to submit cost data for 2001, 2002, and 2003, and to assist the CPUC in determining whether SFPP's overall rates for California intrastate transportation services are reasonable. The resolution reserves the right to require refunds, from the date of issuance of the resolution, to the extent the CPUC's analysis of cost data to be submitted by SFPP demonstrates that SFPP's California jurisdictional rates are unreasonable in any fashion. On February 21, 2003, SFPP submitted the cost data required by the CPUC, which submittal was protested by Valero Marketing and Supply Company, Ultramar Inc., BP West Coast Products LLC, Exxon Mobil Oil Corporation and Chevron Products Company. Issues raised by the protest, including the reasonableness of SFPP's existing intrastate transportation rates, were the subject of evidentiary hearings conducted in December 2003 and may be resolved by the CPUC in the first or second quarter of 2005. On November 22, 2004, SFPP filed an application with the CPUC requesting a $9 million increase in existing intrastate rates to reflect the in-service date of SFPP's replacement and expansion of its Concord-to-Sacramento pipeline. The requested rate increase, which automatically became effective as of December 22, 2004 pursuant to California Public Utilities Code Section 455.3, is being collected subject to refund, pending resolution of protests to the application by Valero Marketing and Supply Company, Ultramar Inc., BP West Coast Products LLC, Exxon Mobil Oil Corporation and ChevronTexaco Products Company. The CPUC is expected to resolve the matter by the fourth quarter of 2005. We currently believe the CPUC complaints seek approximately $15 million in tariff reparations and prospective annual tariff reductions, the aggregate average annual impact of which would be approximately $31 million. There is no way to quantify the potential extent to which the CPUC could determine that SFPP's existing California rates are unreasonable. With regard to the amount of dollars potentially subject to refund as a consequence of the CPUC resolution requiring the provision by SFPP of cost-of-service data, such refunds could total about $6 million per year from October 2002 to the anticipated date of a CPUC decision. SFPP believes the submission of the required, representative cost data required by the CPUC indicates that SFPP's existing rates for California intrastate services remain reasonable and that no refunds are justified. We believe that the resolution of such matters will not have a material adverse effect on our business, financial position, results of operations or cash flows. Trailblazer Pipeline Company Rate Case As required by its last rate case settlement, Trailblazer Pipeline Company made a general rate case filing at the FERC on November 29, 2002. The filing provides for a small rate decrease and a number of non-rate tariff changes. By an order issued December 31, 2002, the FERC effectively bifurcated the proceeding. The FERC accepted the rate decrease effective January 1, 2003, subject to refund and a hearing. The FERC suspended most of the non-rate tariff changes until June 1, 2003, subject to refund and a technical conference procedure. 162 <PAGE> Trailblazer sought rehearing of the FERC rate decrease order with respect to the refund condition. On April 15, 2003, the FERC granted Trailblazer's rehearing request to remove the refund condition that had been imposed in the FERC's December 31, 2002 order. Certain intervenors have sought rehearing as to the FERC's acceptance of certain non-rate tariff provisions. The technical conference on non-rate tariff issues was held on February 6, 2003. The non-rate tariff issues include: o capacity award procedures; o credit procedures; o imbalance penalties; and o the maximum length of bid terms considered for evaluation in the right of first refusal process. Comments on the non-rate tariff issues as discussed at the technical conference were filed by parties in March 2003. On May 23, 2003, the FERC issued an order deciding non-rate tariff issues and denying rehearing of its prior order. In the May 23, 2003 order, the FERC: o accepted Trailblazer's proposed capacity award procedures with very limited changes; o accepted Trailblazer's credit procedures subject to very extensive changes, consistent with numerous recent orders involving other pipelines; o accepted a compromise agreed to by Trailblazer and the active parties under which existing shippers must match competing bids in the right of first refusal process for up to ten years (in lieu of the current five years); and o accepted Trailblazer's withdrawal of daily imbalance charges. More specifically, the May 23, 2003 order: o allowed shortened notice periods for suspension of service, but required at least thirty days notice for service termination; o limited prepayments and any other assurance of future performance, such as a letter of credit, to three months of service charges except for new facilities; o required the pipeline to pay interest on prepayments or allow those funds to go into an interest-bearing escrow account; and o required much more specificity about credit criteria and procedures in tariff provisions. Certain shippers and Trailblazer sought rehearing of the May 23, 2003 order. Trailblazer made its compliance filing on June 20, 2003. The tariff changes under the May 23, 2003 order were made effective as of May 23, 2003, except that Trailblazer filed to make the revised credit procedures effective August 15, 2003. In an order issued July 13, 2004, the FERC accepted Trailblazer's compliance filing of June 20, 2003, but required some minor changes, and denied the rehearing requests. On August 6, 2004, Trailblazer made the compliance filing to the FERC's July 13, 2004 order. On February 11, 2005, the FERC issued an order approving the August 6, 2004 compliance filing. With respect to the rate review portion of the case, direct testimony was filed by the FERC Staff and the Indicated Shippers on May 22, 2003 and cross-answering testimony was filed by the Indicated Shippers on June 19, 2003. Trailblazer's answering testimony was filed on July 29, 2003. 163 <PAGE> On September 22, 2003, Trailblazer filed an offer of settlement with the FERC with respect to the rate review portion of the case. Under the proposed settlement, Trailblazer's rate would be reduced effective January 1, 2004, from $0.12 to $0.09 per dekatherm of natural gas, and Trailblazer would file a new rate case to be effective January 1, 2010. On January 23, 2004, the FERC issued an order approving, with modification, the settlement that was filed on September 22, 2003. The FERC modified the settlement to expand the scope of severance of contesting parties to present and future direct interests, including capacity release agreements. The settlement had provided the scope of the severance to be limited to present direct interests. On February 20, 2004, Trailblazer filed a letter with the FERC accepting the modifications to the settlement. As of March 1, 2004, all members of the Indicated Shippers group opposing the settlement had filed to withdraw their opposition. On April 9, 2004, the FERC accepted tariff sheets setting out the settlement rates and, recognizing that the settlement is now unopposed, dismissed the pending initial decision on Trailblazer's rates as moot. The settlement rates were put into effect January 1, 2004. On March 26, 2004, Trailblazer refunded approximately $0.9 million to shippers covering the period January 1, 2004 through February 29, 2004 pursuant to the terms of the rate case settlement. On July 13, 2004, the FERC issued an order requiring Trailblazer to refund additional amounts to shippers previously contesting the settlement. Trailblazer issued these additional refunds, totaling approximately $73,000 on July 23, 2004. The FERC issued an order approving the refund report on December 1, 2004, and no issues remain outstanding in this proceeding. Fuel Tracking Filing On March 31, 2004, Trailblazer made its annual filing to revise its fuel tracker percentage (its fuel rate) applicable to its expansion shippers. In the filing, Trailblazer proposed to reduce its fuel rate from the previous level of 2.0% to 1.57%. On April 12, 2004, Marathon Oil Company filed a protest stating that Trailblazer overstated projected volumes at the Station 601 compressor facility and proposed that the volumes at the station be reduced, which would result in a reduction of the fuel rate to 1.20%. On April 30, 2004, the FERC issued an order allowing Trailblazer to place its proposed 1.57% fuel rate into effect, subject to refund, on May 1, 2004. The order also established a comment procedure, pursuant to which Trailblazer filed comments supporting its proposal on May 20, 2004 and Marathon filed reply comments on June 1, 2004. On July 9, 2004, the FERC issued an order adopting Marathon's position. Trailblazer implemented the 1.20% fuel rate on August 1, 2004. In addition, in September 2004, Trailblazer refunded approximately $600,000 to affected shippers for the period May 1, 2004 to July 31, 2004; the period in which Trailblazer's rejected fuel rate was billed to shippers. On October 8, 2004, Trailblazer filed with the FERC its refund report supporting the September 2004 refunds. On November 9, 2004, the FERC accepted the refund report as filed and no issues remain outstanding in this proceeding. FERC Order 637 On August 15, 2000, Trailblazer Pipeline Company made a filing to comply with the FERC's Order Nos. 637 and 637-A. Trailblazer's compliance filing reflected changes in: o segmentation; o scheduling for capacity release transactions; o receipt and delivery point rights; o treatment of system imbalances; o operational flow orders; o penalty revenue crediting; and o right of first refusal language. 164 <PAGE> On October 15, 2001, the FERC issued its order on Trailblazer's Order No. 637 compliance filing. The FERC approved Trailblazer's proposed language regarding operational flow orders and rights of first refusal, but required Trailblazer to make changes to its tariff related to the other issues listed above. On November 14, 2001, Trailblazer made its compliance filing pursuant to the FERC's October 15, 2001 order and also filed for rehearing of the October 15, 2001 order. On April 16, 2003, the FERC issued its order on Trailblazer's compliance filing and rehearing order. The FERC denied Trailblazer's requests for rehearing and approved its compliance filing subject to modifications. Trailblazer made those modifications in a compliance filing submitted to the FERC on May 16, 2003. On March 24, 2004, the FERC issued an order directing Trailblazer to make relatively minor changes to its filing of May 16, 2003. Trailblazer submitted its compliance filing on April 8, 2004. The FERC issued an order accepting the April 8, 2004 filing on August 5, 2004. Under the FERC's orders, limited aspects of Trailblazer's plan (revenue crediting) were effective as of May 1, 2003. The entire Order No. 637 plan went into effect on December 1, 2003. Trailblazer anticipates no adverse impact on its business as a result of the implementation of Order No. 637. No issues remain outstanding as to Trailblazer's Order 637 compliance program. Standards of Conduct Rulemaking FERC Order No. 2004 On November 25, 2003, the FERC issued Order No. 2004, adopting new Standards of Conduct to become effective February 9, 2004. Every interstate natural gas pipeline was required to file a compliance plan by that date and was required to be in full compliance with the Standards of Conduct by June 1, 2004. The primary change from existing regulation is to make such standards applicable to an interstate natural gas pipeline's interaction with many more affiliates (referred to as "energy affiliates"), including intrastate/Hinshaw natural gas pipelines (in general, a Hinshaw pipeline is a pipeline that receives gas at or within a state boundary, is regulated by an agency of that state, and all the gas it transports is consumed within that state), processors and gatherers and any company involved in natural gas or electric markets (including natural gas marketers) even if they do not ship on the affiliated interstate natural gas pipeline. Local distribution companies are excluded, however, if they do not make sales to customers not physically attached to their system. The Standards of Conduct require, among other things, separate staffing of interstate pipelines and their energy affiliates (but support functions and senior management at the central corporate level may be shared) and strict limitations on communications from an interstate pipeline to an energy affiliate. Kinder Morgan Interstate Gas Transmission LLC filed for clarification and rehearing of Order No. 2004 on December 29, 2003. In the request for rehearing, Kinder Morgan Interstate Gas Transmission LLC asked that intrastate/Hinshaw pipeline affiliates not be included in the definition of energy affiliates. On February 19, 2004, Kinder Morgan Interstate Gas Transmission LLC and Trailblazer Pipeline Company filed exemption requests with the FERC. The pipelines seek a limited exemption from the requirements of Order No. 2004 for the purpose of allowing their affiliated Hinshaw and intrastate pipelines, which are subject to state regulation and do not make any sales to customers not physically attached to their system, to be excluded from the rule's definition of energy affiliate. Separation from these entities would be the most burdensome requirement of the new rules for us. On April 16, 2004, the FERC issued Order No. 2004-A. The FERC extended the effective date of the new Standards of Conduct from June 1, 2004, to September 1, 2004. Otherwise, the FERC largely denied rehearing of Order No. 2004, but provided further clarification or adjustment in several areas. The FERC continued the exemption for local distribution companies which do not make off-system sales, but clarified that the local distribution company exemption still applies if the local distribution company is also a Hinshaw pipeline. The FERC also clarified that a local distribution company can engage in certain sales and other energy affiliate activities to the limited extent necessary to support sales to customers located on its distribution system, and sales necessary to remain in balance under pipeline tariffs, without becoming an energy affiliate. The FERC declined to exempt natural gas producers. The FERC also declined to exempt natural gas intrastate and Hinshaw pipelines, processors and gatherers, but did clarify that such entities will not be energy affiliates if they do not participate in gas or electric commodity markets, interstate capacity markets (as capacity holder, agent or manager), or in financial transactions related to such markets. 165 <PAGE> The FERC also clarified further the personnel and functions which can be shared by interstate natural gas pipelines and their energy affiliates, including senior officers and risk management personnel, and the permissible role of holding or parent companies and service companies. The FERC also clarified that day-to-day operating information can be shared by interconnecting entities. Finally, the FERC clarified that an interstate natural gas pipeline and its energy affiliate can discuss potential new interconnects to serve the energy affiliate, but subject to very onerous posting and record-keeping requirements. On July 21, 2004, Kinder Morgan Interstate Gas Transmission LLC and Trailblazer Pipeline Company filed additional joint requests with the interstate natural gas pipelines owned by KMI asking for limited exemptions from certain requirements of FERC Order 2004 and asking for an extension of the deadline for full compliance with Order 2004 until 90 days after the FERC has completed action on the pipelines' various rehearing and exemption requests. These exemptions request relief from the independent functioning and information disclosure requirements of Order 2004. The exemption requests propose to treat as energy affiliates, within the meaning of Order 2004, two groups of employees: o individuals in the Choice Gas Commodity Group within KMI's retail operations; and o commodity sales and purchase personnel within our Texas intrastate natural gas operations. Order 2004 regulations governing relationships between interstate pipelines and their energy affiliates would apply to relationships with these two groups. Under these proposals, certain critical operating functions could continue to be shared. On August 2, 2004, the FERC issued Order No. 2004-B. In this order, the FERC extended the effective date of the new Standards of Conduct from September 1, 2004 to September 22, 2004. Also in this order, among other actions, the FERC denied the request for rehearing made by the interstate pipelines of KMI and us to clarify the applicability of the local distribution company and parent company exemptions to them. In addition, the FERC denied the interstate pipelines' request for a 90 day extension of time to comply with Order 2004. On September 20, 2004, the FERC issued an order which conditionally granted the July 21, 2004 joint requests for limited exemptions from the requirements of the Standards of Conduct described above. In that order, FERC directed Kinder Morgan Interstate Gas Transmission LLC, Trailblazer Pipeline Company and the affiliated interstate pipelines owned by KMI to submit compliance plans regarding these exemptions within 30 days. These compliance plans were filed on October 19, 2004, and set out certain steps taken by us to assure that employees in the Choice Gas Commodity Group of KMI and the commodity sales and purchase personnel of our Texas intrastate organizations do not have access to restricted interstate natural gas pipeline information or receive preferential treatment as to interstate natural gas pipeline services. The FERC will not enforce compliance with the independent functioning requirement of the Standards of Conduct as to these employees until 30 days after it acts on these compliance filings. In all other respects, we were required to comply with the Standards of Conduct as of September 22, 2004. We have implemented compliance with the Standards of Conduct as of September 22, 2004, subject to the exemptions described in the prior paragraph. Compliance includes, among other things, the posting of compliance procedures and organizational information for each interstate pipeline on its Internet website, the posting of discount and tariff discretion information and the implementation of independent functioning for energy affiliates not covered by the prior paragraph (electric and gas gathering, processing or production affiliates). On December 21, 2004, the FERC issued Order No. 2004-C. In this order, the FERC granted rehearing on certain issues and also clarified certain provisions in the previous FERC 2004 orders. The primary impact on us from Order 2004-C is the granting of rehearing and allowing local distribution companies to participate in hedging activity related to on-system sales and still qualify for exemption from being an energy affiliate. 166 <PAGE> FERC Policy statement re: Use of Gas Basis Differentials for Pricing On July 25, 2003, the FERC issued a Modification to Policy Statement stating that FERC regulated natural gas pipelines will, on a prospective basis, no longer be permitted to use gas basis differentials to price negotiated rate transactions. Effectively, we will no longer be permitted to use commodity price indices to structure transactions on our FERC regulated natural gas pipelines. Negotiated rates based on commodity price indices in existing contracts will be permitted to remain in effect until the end of the contract period for which such rates were negotiated. Moreover, in subsequent orders in individual pipeline cases, the FERC has allowed negotiated rate transactions using pricing indices so long as revenue is capped by the applicable maximum rate(s). Rehearing on this aspect of the Modification to Policy Statement has been sought by several pipelines, but the FERC has not yet acted on rehearing. Price indexed contracts currently constitute an insignificant portion of our contracts on our FERC regulated natural gas pipelines; consequently, we do not believe that this Modification to Policy Statement will have a material impact on our operations, financial results or cash flows. Accounting for Integrity Testing Costs On November 5, 2004, the FERC issued a Notice of Proposed Accounting Release that would require FERC jurisdictional entities to recognize costs incurred in performing pipeline assessments that are a part of a pipeline integrity management program as maintenance expense in the period incurred. The proposed accounting ruling was in response to the FERC's finding of diverse practices within the pipeline industry in accounting for pipeline assessment activities. The proposed ruling would standardize these practices. Specifically, the proposed ruling clarifies the distinction between costs for a "one-time rehabilitation project to extend the useful life of the system," which could be capitalized, and costs for an "on-going inspection and testing or maintenance program," which would be accounted for as maintenance and charged to expense in the period incurred. Comments, along with responses to specific questions posed by FERC concerning the Notice of Proposed Accounting Release, were due January 19, 2005. We filed our comments on January 19, 2005, asking the FERC to modify the accounting release to allow capitalization of pipeline assessment costs associated with projects involving 100 feet or more of pipeline being replaced or recoated (including discontinuous sections) and to adopt an effective date for the final rule which is no earlier than January 1, 2006. Selective Discounting On November 22, 2004, the FERC issued a notice of inquiry seeking comments on its policy of selective discounting. Specifically, the FERC is asking parties to submit comments and respond to inquiries regarding the FERC's practice of permitting pipelines to adjust their ratemaking throughput downward in rate cases to reflect discounts given by pipelines for competitive reasons - when the discount is given to meet competition from another gas pipeline. Comments are due March 2, 2005. Other Regulatory As discussed above, under "SFPP, L.P. - Federal Regulatory Commission Proceedings," on July 20, 2004, the United States Court of Appeals for the District of Columbia Circuit issued its opinion in BP West Coast Products, LLC v. Federal Energy Regulatory Commission, No. 99-1020, On Petitions for Review of Orders of the Federal Energy Regulatory Commission (Circuit opinion), addressing in part the tariffs of SFPP, L.P. Among other things, the Circuit Court opinion vacated the income tax allowance portion of the FERC opinion and order allowing recovery in SFPP's rates for income taxes and remanded this and other matters for further proceedings consistent with the Circuit Court opinion. By its terms, the opinion only pertains to SFPP, L.P. and it is based on the record in that case. However, on December 2, 2004, the FERC issued a Notice of Inquiry seeking comments on the implications of the July 20, 2004 opinion of the Court of Appeals for the District of Columbia Circuit in BP West Coast Producers, LLC, v. FERC. In reviewing a series of orders involving SFPP, L.P., the court held, among other things, that the FERC had not adequately justified its policy of providing an oil pipeline limited partnership with an income tax allowance equal to the proportion of its limited partnership interests owned by corporate partners. The FERC is seeking comments on whether the court's ruling applies only to the specific facts of the SFPP, L.P. proceeding, or also extends to other capital structures involving partnerships and other forms of ownership. Comments were due 167 <PAGE> January 21, 2005. In addition to the matters described above, we may face additional challenges to our rates in the future. Shippers on our pipelines do have rights to challenge the rates we charge under certain circumstances prescribed by applicable regulations. There can be no assurance that we will not face challenges to the rates we receive for services on our pipeline systems in the future. In addition, since many of our assets are subject to regulation, we are subject to potential future changes in applicable rules and regulations that may have an adverse effect on our business, financial position, results of operations or cash flows. Union Pacific Railroad Company Easements SFPP, L.P. and Union Pacific Railroad Company (the successor to Southern Pacific Transportation Company) are engaged in two proceedings 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 UPRR should be adjusted pursuant to existing contractual arrangements for each of the ten year periods beginning January 1, 1994 and January 1, 2004 (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; and Union Pacific Railroad Company vs. Santa Fe Pacific Pipelines, Inc., SFPP, L.P., Kinder Morgan Operating L.P. "D", Kinder Morgan G.P., Inc., et al., Superior Court of the State of California for the County of Los Angeles, filed July 28, 2004). In the second quarter of 2003, the trial court set the rent for years 1994 - 2003 at approximately $5.0 million per year as of January 1, 1994, subject to annual inflation increases throughout the ten year period. UPRR has appealed this matter to the California Court of Appeals, and oral arguments were heard on January 25, 2005. On August 17, 2004, SFPP was served with a lawsuit seeking to determine the rent for the ten year period commencing January 1, 2004. A trial date has not been set. Carbon Dioxide Litigation Kinder Morgan CO2 Company, L.P., Kinder Morgan G.P., Inc., and Cortez Pipeline Company are among the named defendants in Shores, et al. v. Mobil Oil Corp., et al., No. GC-99-01184 (Statutory Probate Court, Denton County, Texas filed December 22, 1999) and First State Bank of Denton, et al. v. Mobil Oil Corp., et al., No. 8552-01 (Statutory Probate Court, Denton County, Texas filed March 29, 2001). These cases were originally filed as class actions on behalf of classes of overriding royalty interest owners (Shores) and royalty interest owners (Bank of Denton) for damages relating to alleged underpayment of royalties on carbon dioxide produced from the McElmo Dome Unit. Although classes were initially certified at the trial court level, appeals resulted in the decertification and/or abandonment of the class claims. In December 2004, the trial judge orally announced his intention to dismiss both cases in response to motions filed by defendants. Orders of dismissal have been submitted but have not, as yet, been entered. On May 13, 2004, William Armor, one of the former plaintiffs in the Shores matter whose claims were dismissed for improper venue by the Court of Appeals, filed a new case alleging the same claims (in summary, seeking damages for underpayment of royalties based on alleged breaches of contractual duties and covenants, agency duties, civil conspiracy, and related claims) against the same defendants previously sued in the Shores case, including Kinder Morgan CO2 Company, L.P. and Kinder Morgan Energy Partners, L.P. Armor v. Shell Oil Company, et al, No. 04-03559 (14th Judicial District, Dallas County Court filed May 13, 2004). Defendants filed their answers and special exceptions on June 4, 2004. Trial, if necessary, has been scheduled for July 25, 2005. Shell CO2 Company, Ltd., predecessor in interest to Kinder Morgan CO2 Company, L.P., is among the named counter-claim defendants in Shell Western E&P Inc. v. Gerald O. Bailey and Bridwell Oil Company; No. 98-28630 (215th Judicial District Court, Harris County, Texas filed June 17, 1998) (the "SWEPI Action"). The counter-claim plaintiffs are overriding royalty interest owners in the McElmo Dome Unit and have sued seeking damages for underpayment of royalties on carbon dioxide produced from the McElmo Dome Unit. The counter-claim plaintiffs have asserted claims for fraud/fraudulent inducement, real estate fraud, negligent misrepresentation, breach of fiduciary duty, breach of contract, negligence, negligence per se, unjust enrichment, violation of the Texas Securities Act, and open account. Counter-claim plaintiffs seek actual damages, punitive damages, an accounting, and declaratory relief. The trial court granted a series of summary judgment motions filed by counter-claim defendants 168 <PAGE> on all of counter-plaintiffs' counter-claims except for the fraud-based claims. In 2004, one of the counter-plaintiffs (Gerald Bailey) amended his counter-suit to allege purported claims as a private relator under the False Claims Act and antitrust claims. The federal government elected to not intervene in the False Claims Act counter-suit. Kinder Morgan CO2 Company, L.P. intends to seek dismissal of the False Claims Act and antitrust claims through appropriate motions. No current trial date is set. On March 1, 2004, Bridwell Oil Company, one of the named defendants/ counter-claim plaintiffs in the SWEPI Action, filed a new matter in which it asserts claims which are virtually identical to the counter-claims it asserts against Shell CO2 Company, Ltd. in the SWEPI Action. Bridwell Oil Co. v. Shell Oil Co. et al, No. 160,199-B (78th Judicial District, Wichita County Court filed March 1, 2004). The defendants in this action include Kinder Morgan CO2 Company, L.P., Kinder Morgan Energy Partners, L.P., various Shell entities, ExxonMobil entities, and Cortez Pipeline Company. On June 25, 2004, defendants filed answers, special exceptions, pleas in abatement, and motions to transfer venue back to the Harris County District Court. The presiding judge in the Wichita County case stated, in a December 10, 2004 letter decision, that he intended to abate the case pending resolution of the SWEPI Action. A proposed order has been submitted but, as yet, has not been entered. Kinder Morgan CO2 Company, L.P. and Cortez Pipeline Company are among the named defendants in Celeste C. Grynberg, et al. v. Shell Oil Company, et al., No. 98-CV-43 (Colo. Dist. Ct., Montezuma County filed March 2, 1998). This case involves claims by overriding royalty interest owners in the McElmo Dome and Doe Canyon Units seeking damages for underpayment of royalties on carbon dioxide produced from the McElmo Dome Unit, failure to develop carbon dioxide reserves at the Doe Canyon Unit, and failure to develop hydrocarbons at both McElmo Dome and Doe Canyon. The plaintiffs also possess a small working interest at Doe Canyon. Plaintiffs claim breaches of contractual and potential fiduciary duties owed by the defendants and also allege other theories of liability including breach of covenants, civil theft, conversion, fraud/fraudulent concealment, violation of the Colorado Organized Crime Control Act, deceptive trade practices, and violation of the Colorado Antitrust Act. In addition to actual or compensatory damages, plaintiffs seek treble damages, punitive damages, and declaratory relief relating to the Cortez Pipeline tariff and the method of calculating and paying royalties on McElmo Dome carbon dioxide. Plaintiffs' motion for summary judgment concerning alleged underpayment of McElmo Dome overriding royalties is currently pending before the Court. The parties are continuing to engage in discovery. No trial date is currently set. J. Casper Heimann, Pecos Slope Royalty Trust and Rio Petro LTD, individually and on behalf of all other private royalty and overriding royalty owners in the Bravo Dome Carbon Dioxide Unit, New Mexico similarly situated v. Kinder Morgan CO2 Company, L.P., No. 04-26-CL (8th Judicial District Court, Union County New Mexico). This case involves a purported class action against Kinder Morgan CO2 Company, L.P. alleging that defendant has failed to pay the full royalty and overriding royalty ("royalty interests") on the true and proper settlement value of compressed carbon dioxide produced from the Bravo Dome Unit in the period beginning January 1, 2000. The complaint purports to assert claims for violation of the New Mexico Unfair Practices Act, constructive fraud, breach of contract and of the covenant of good faith and fair dealing, breach of the implied covenant to market, and claims for an accounting, unjust enrichment, and injunctive relief. The purported class is comprised of current and former owners, during the period January 2000 to the present, who have private property royalty interests burdening the oil and gas leases held by the defendant, excluding the Commissioner of Public Lands, the United States of America, and those private royalty interests that are not unitized as part of the Bravo Dome Unit. The plaintiffs allege that they were members of a class previously certified as a class action by the United States District Court for the District of New Mexico in the matter Doris Feerer, et al. v. Amoco Production Company, et al., USDC N.M. Civ. No. 95-0012 (the "Feerer Class Action"). Plaintiffs allege that defendant's method of paying royalty interests is contrary to the settlement of the Feerer Class Action. Defendant has filed a Motion to Compel Arbitration of this matter pursuant to the arbitration provisions contained in the Feerer Class Action Settlement Agreement, which motion is currently pending. No date for arbitration or trial is currently set. In addition to the matters listed above, various audits and administrative inquiries concerning Kinder Morgan CO2 Company L.P.'s royalty and tax payments on carbon dioxide produced from the McElmo Dome Unit are currently ongoing. These audits and inquiries involve various federal agencies, the State of Colorado, the Colorado oil and gas commission, and Colorado county taxing authorities. 169 <PAGE> RSM Production Company, et al. v. Kinder Morgan Energy Partners, L.P., et al. (Cause No. 4519, in the District Court, Zapata County Texas, 49th Judicial District). On October 15, 2001, Kinder Morgan Energy Partners, L.P. was served with the First Supplemental Petition filed by RSM Production Corporation on behalf of the County of Zapata, State of Texas and Zapata County Independent School District as plaintiffs. Kinder Morgan Energy Partners, L.P. was sued in addition to 15 other defendants, including two other Kinder Morgan affiliates. Certain entities we acquired in the Kinder Morgan Tejas acquisition are also defendants in this matter. The Petition alleges that these taxing units relied on the reported volume and analyzed heating content of natural gas produced from the wells located within the appropriate taxing jurisdiction in order to properly assess the value of mineral interests in place. The suit further alleges that the defendants undermeasured the volume and heating content of that natural gas produced from privately owned wells in Zapata County, Texas. The Petition further alleges that the County and School District were deprived of ad valorem tax revenues as a result of the alleged undermeasurement of the natural gas by the defendants. On December 15, 2001, the defendants filed motions to transfer venue on jurisdictional grounds. On June 12, 2003, plaintiff served discovery requests on certain defendants. On July 11, 2003, defendants moved to stay any responses to such discovery. United States of America, ex rel., Jack J. Grynberg v. K N Energy (Civil Action No. 97-D-1233, filed in the U.S. District Court, District of Colorado). This action was filed on June 9, 1997 pursuant to the federal False Claims 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). Certain entities we acquired in the Kinder Morgan Tejas acquisition are also defendants in this matter. 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. In 1999, these cases were consolidated by the Judicial Panel for Multidistrict Litigation, and transferred to the District of Wyoming. The multidistrict litigation matter is called In Re Natural Gas Royalties Qui Tam Litigation, Docket No. 1293. Motions to dismiss were filed and an oral argument on the motion to dismiss occurred on March 17, 2000. On July 20, 2000, the United States of America filed a motion to dismiss those claims by Grynberg that deal with the manner in which defendants valued gas produced from federal leases, referred to as valuation claims. Judge Downes denied the defendant's motion to dismiss on May 18, 2001. The United States' motion to dismiss most of plaintiff's valuation claims has been granted by the court. Grynberg has appealed that dismissal to the 10th Circuit, which has requested briefing regarding its jurisdiction over that appeal. Subsequently, Grynberg's appeal was dismissed for lack of appellate jurisdiction. Discovery to determine issues related to the Court's subject matter jurisdiction arising out of the False Claims Act is complete. Briefing has been completed and oral arguments on jurisdiction have been set before the Special Master for March 17 and 18, 2005. On May 7, 2003, Grynberg sought leave to file a Third Amended Complaint, which adds allegations of undermeasurement related to carbon dioxide production. Defendants have filed briefs opposing leave to amend. Neither the Court nor the Special Master has ruled on Grynberg's Motion to Amend. Mel R. Sweatman and Paz Gas Corporation v. Gulf Energy Marketing, LLC, et al. On July 25, 2002, we were served with this suit for breach of contract, tortious interference with existing contractual relationships, conspiracy to commit tortious interference and interference with prospective business relationship. Mr. Sweatman and Paz Gas Corporation claim that, in connection with our acquisition of Tejas Gas, LLC, we wrongfully caused gas volumes to be shipped on our Kinder Morgan Texas Pipeline system instead of our Kinder Morgan Tejas system. Mr. Sweatman and Paz Gas Corporation allege that this action eliminated profit on Kinder Morgan Tejas, a portion of which Mr. Sweatman and Paz Gas Corporation claim they are entitled to receive under an agreement with a subsidiary of ours acquired in the Tejas Gas acquisition. We filed a motion to remove the case from venue in Dewitt County, Texas to Harris County, Texas, and our motion was denied in a venue hearing in November 2002. 170 <PAGE> In a Second Amended Original Petition, Sweatman and Paz assert new and distinct allegations against us, principally that we were a party to an alleged commercial bribery committed by us, Gulf Energy Marketing, and Intergen inasmuch as we, in our role as acquirer of Kinder Morgan Tejas, allegedly paid Intergen to not renew the underlying Entex contracts belonging to the Tejas/Paz joint venture. Moreover, new and distinct allegations of breach of fiduciary and bribery of a fiduciary are also raised in this amended petition for the first time. The parties have engaged in some discovery and depositions. At this stage of discovery, we believe that our actions were justified and defensible under applicable Texas law and that the decision not to renew the underlying gas sales agreements was made unilaterally by persons acting on behalf of Entex. The plaintiffs have moved for summary judgment asking the court to declare that a fiduciary relationship existed for purposes of Sweatman's claims. We have moved for summary judgment on the grounds that: o there is no cause-in-fact of the gas sales nonrenewals attributable to us; and o the defense of legal justification applies to the claims for tortuous interference. In September 2003 and then again in November 2003, Sweatman and Paz filed their third and fourth amended petitions, respectively, asserting all of the claims for relief described above. In addition, the plaintiffs asked that the court impose a constructive trust on (i) the proceeds of the sale of Tejas and (ii) any monies received by any Kinder Morgan entity for sales of gas to any Entex/Reliant entity following June 30, 2002 that replaced volumes of gas previously sold under contracts to which Sweatman and Paz had a participating interest pursuant to the joint venture agreement between Tejas, Sweatman and Paz. In October 2003, the court granted, and then rescinded its order after a motion to reconsider heard on February 13, 2004, a motion for partial summary judgment on the issue of the existence of a fiduciary duty. On October 27, 2004, the court granted a motion for partial summary judgment in the defendants' favor, finding that, as a matter of law, Sweatman's interests in four of the five gas sales contracts at issue terminated in 1992 after those contracts were amended in their material terms, and thus falling outside the joint venture itself. In various form, the plaintiffs have amended their petition to allege various oral and implied joint venture agreements as well as an oral partnership agreement. The claimants are asking for the imposition of a constructive trust on the proceeds of gas sales contracts with Entex and its affiliates that were entered into after the gas sales at issue were unilaterally terminated by Entex on March 28. 2002, for which Sweatman blames us and our agents and representatives. We believe this suit is without merit and we intend to defend the case vigorously. We have moved for partial summary judgment on all of Sweatman's claims, asserting that even in the light most favorable to Sweatman's assertions, there is no issue of material fact on whether Sweatman even owned an interest in the underlying gas sales agreements in dispute. That motion was heard on August 13, 2004, and was granted on October 26, 2004 as to four of the five gas sales contracts at issue, leaving for further determination at a later time any remaining claims based upon other theories of recovery not dependent upon the four gas sales agreements being joint venture property. We have also filed a no-evidence motion for summary judgment on the plaintiffs' defamation claims. Trial of the case is set preferentially for February 21, 2005. Maher et ux. v. Centerpoint Energy, Inc., Centerpoint Energy Resources Corp., Entex Gas Marketing Company, Kinder Morgan Texas Pipeline, L.P., Kinder Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc., Kinder Morgan Tejas Pipeline, L.P., Kinder Morgan Tejas Pipeline, GP, Inc., Kinder Morgan Texas Pipeline GP, Inc., Tejas Gas, LLC, Midcon Corp., Gulf Energy Marketing, LLC, Houston Pipeline Company, L.P, HPL GP, LLC, and AEP Gas Marketing, L.P., No. 30875 (District Court, Wharton County Texas). On October 21, 2002, Kinder Morgan Texas Pipeline, L.P. and Kinder Morgan Energy Partners, L.P. were served with the above-entitled Complaint. A First Amended Complaint was served on October 23, 2002, adding additional defendants Kinder Morgan G.P., Inc., Kinder Morgan Tejas Pipeline GP, Inc., Kinder Morgan Texas Pipeline GP, Inc., Tejas Gas, LLC and HPL GP, LLC. A Second Amended Complaint was filed on January 6, 2003, which added additional proposed plaintiff class representatives. A Third Amended Complaint was filed on February 4, 2005, which dropped the purported class action allegations and added additional defendants, Midcon Corp. and Gulf Energy Marketing, LLC. The Complaint purports to bring an action on behalf of three plaintiffs who 171 <PAGE> purchased natural gas for residential purposes from the so-called "Reliant Defendants" in Texas at any time during the period encompassing "at least the last ten years." The Complaint alleges that Reliant Energy Resources Corp., by and through its affiliates, has artificially inflated the price charged to residential consumers for natural gas that it allegedly purchased from the non-Reliant defendants, including the above-listed Kinder Morgan entities. The Complaint further alleges that in exchange for Reliant Energy Resources Corp.'s purchase of natural gas at above market prices, the non-Reliant defendants, including the above-listed Kinder Morgan entities, sell natural gas to Entex Gas Marketing Company at prices substantially below market, which in turn sells such natural gas to commercial and industrial consumers and gas marketers at market price. The Complaint purports to assert claims for fraud, violations of the Texas Deceptive Trade Practices Act, and violations of the Texas Utility Code against some or all of the Defendants, and civil conspiracy against all of the defendants, and seeks relief in the form of, among other things, actual, exemplary and statutory damages, civil penalties, interest, attorneys' fees and a constructive trust ab initio on any and all sums which allegedly represent overcharges by Reliant and Reliant Energy Resources Corp. On November 18, 2002, the Kinder Morgan defendants filed a Motion to Transfer Venue and, Subject Thereto, Original Answer to the original Complaint. On February 10, 2005, the Centerpoint defendants removed the case to the United States District Court for the Southern District of Texas, Houston Division. Based on the information available to date and our preliminary investigation, the Kinder Morgan defendants believe that the claims against them are without merit and intend to defend against them vigorously. Weldon Johnson and Guy Sparks , individually and as Representative of Others Similarly Situated v. Centerpoint Energy, Inc. et. al., No. 04-327-2 (Circuit Court, Miller County Arkansas). On October 8, 2004, plaintiffs filed the above-captioned matter against numerous defendants including Kinder Morgan Texas Pipeline L.P.; Kinder Morgan Energy Partners, L.P.; Kinder Morgan G.P., Inc.; KM Texas Pipeline, L.P.; Kinder Morgan Texas Pipeline G.P., Inc.; Kinder Morgan Tejas Pipeline G.P., Inc.; Kinder Morgan Tejas Pipeline, L.P.; Gulf Energy Marketing, LLC; Tejas Gas, LLC; and Midcon Corp. (the "Kinder Morgan Defendants"). The Complaint purports to bring a class action on behalf of those who purchased natural gas from the Centerpoint defendants from October 1, 1994 to the date of class certification. The Complaint alleges that Centerpoint Energy, Inc., by and through its affiliates, has artificially inflated the price charged to residential consumers for natural gas that it allegedly purchased from the non-Centerpoint defendants, including the above-listed Kinder Morgan entities. The Complaint further alleges that in exchange for Centerpoint's purchase of such natural gas at above market prices, the non-Centerpoint defendants, including the above-listed Kinder Morgan entities, sell natural gas to Centerpoint's non-regulated affiliates at prices substantially below market, which in turn sells such natural gas to commercial and industrial consumers and gas marketers at market price. The Complaint purports to assert claims for fraud, unlawful enrichment and civil conspiracy against all of the defendants, and seeks relief in the form of actual, exemplary and punitive damages, interest, and attorneys' fees. The Complaint was served on the Kinder Morgan Defendants on October 21, 2004. On November 18, 2004, the Centerpoint Defendants removed the case to the United States District Court, Western District of Arkansas, Texarkana Division, Civ. Action No. 04-4154. On January 26, 2005, the Plaintiffs moved to remand the case back to state court, which motion is currently pending. On December 17, 2004, the Kinder Morgan Defendants filed a Motion to Dismiss the Complaint, which motion is also currently pending. Based on the information available to date and our preliminary investigation, the Kinder Morgan Defendants believe that the claims against them are without merit and intend to defend against them vigorously. Marie Snyder, et al v. City of Fallon, United States Department of the Navy, Exxon Mobil Corporation, Kinder Morgan Energy Partners, L.P., Speedway Gas Station and John Does I-X, No. cv-N-02-0251-ECR-RAM (United States District Court, District of Nevada)("Snyder"); Frankie Sue Galaz, et al v. United States of America, City of Fallon, Exxon Mobil Corporation, Kinder Morgan Energy Partners, L.P., Berry Hinckley, Inc., and John Does I-X, No. cv-N-02-0630-DWH-RAM (United States District Court, District of Nevada)("Galaz I"); Frankie Sue Galaz, et al v. City of Fallon, Exxon Mobil Corporation, Kinder Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc., Kinder Morgan Las Vegas, LLC, Kinder Morgan Operating Limited Partnership "D", Kinder Morgan Services LLC, Berry Hinkley and Does I-X, No. CV03-03613 (Second Judicial District Court, State of Nevada, County of Washoe) ("Galaz II); Frankie Sue Galaz, et al v. The United States of America, the 172 <PAGE> City of Fallon, Exxon Mobil Corporation, Kinder Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc., Kinder Morgan Las Vegas, LLC, Kinder Morgan Operating Limited Partnership "D", Kinder Morgan Services LLC, Berry Hinkley and Does I-X, No.CVN03-0298-DWH-VPC (United States District Court, District of Nevada)("Galaz III) On July 9, 2002, we were served with a purported Complaint for Class Action in the Snyder case, in which the plaintiffs, on behalf of themselves and others similarly situated, assert that a leukemia cluster has developed in the City of Fallon, Nevada. The Complaint alleges that the plaintiffs have been exposed to unspecified "environmental carcinogens" at unspecified times in an unspecified manner and are therefore "suffering a significantly increased fear of serious disease." The plaintiffs seek a certification of a class of all persons in Nevada who have lived for at least three months of their first ten years of life in the City of Fallon between the years 1992 and the present who have not been diagnosed with leukemia. The Complaint purports to assert causes of action for nuisance and "knowing concealment, suppression, or omission of material facts" against all defendants, and seeks relief in the form of "a court-supervised trust fund, paid for by defendants, jointly and severally, to finance a medical monitoring program to deliver services to members of the purported class that include, but are not limited to, testing, preventative screening and surveillance for conditions resulting from, or which can potentially result from exposure to environmental carcinogens," incidental damages, and attorneys' fees and costs. The defendants responded to the Complaint by filing Motions to Dismiss on the grounds that it fails to state a claim upon which relief can be granted. On November 7, 2002, the United States District Court granted the Motion to Dismiss filed by the United States, and further dismissed all claims against the remaining defendants for lack of Federal subject matter jurisdiction. Plaintiffs filed a Motion for Reconsideration and Leave to Amend, which was denied by the Court on December 30, 2002. Plaintiffs filed a Notice of Appeal to the United States Court of Appeals for the 9th Circuit. On March 15, 2004, the 9th Circuit affirmed the dismissal of this case. On December 3, 2002, plaintiffs filed an additional Complaint for Class Action in the Galaz I matter asserting the same claims in the same court on behalf of the same purported class against virtually the same defendants, including us. On February 10, 2003, the defendants filed Motions to Dismiss the Galaz I Complaint on the grounds that it also fails to state a claim upon which relief can be granted. This motion to dismiss was granted as to all defendants on April 3, 2003. Plaintiffs have filed a Notice of Appeal to the United States Court of Appeals for the 9th Circuit. On November 17, 2003, the 9th Circuit dismissed the appeal, upholding the District Court's dismissal of the case. On June 20, 2003, plaintiffs filed an additional Complaint for Class Action (the "Galaz II" matter) asserting the same claims in Nevada State trial court on behalf of the same purported class against virtually the same defendants, including us (and excluding the United States Department of the Navy). On September 30, 2003, the Kinder Morgan defendants filed a Motion to Dismiss the Galaz II Complaint along with a Motion for Sanctions. On April 13, 2004, plaintiffs' counsel voluntarily stipulated to a dismissal with prejudice of the entire case in State Court. The court has accepted the stipulation and the parties are awaiting a final order from the court dismissing the case with prejudice. Also on June 20, 2003, the plaintiffs in the previously filed Galaz matters (now dismissed) filed yet another Complaint for Class Action in the United States District Court for the District of Nevada (the "Galaz III" matter) asserting the same claims in United States District Court for the District of Nevada on behalf of the same purported class against virtually the same defendants, including us. The Kinder Morgan defendants filed a Motion to Dismiss the Galaz III matter on August 15, 2003. On October 3, 2003, the plaintiffs filed a Motion for Withdrawal of Class Action, which voluntarily drops the class action allegations from the matter and seeks to have the case proceed on behalf of the Galaz family only. On December 5, 2003, the District Court granted the Kinder Morgan defendants' Motion to Dismiss, but granted plaintiff leave to file a second Amended Complaint. Plaintiff filed a Second Amended Complaint on December 13, 2003, and a Third Amended Complaint on January 5, 2004. The Kinder Morgan defendants filed a Motion to Dismiss the Third Amended Complaint on January 13, 2004. The Motion to Dismiss was granted with prejudice on April 30, 2004. On May 7, 2004, Plaintiff filed a Notice of Appeal in the United States Court of Appeals for the 9th Circuit, which appeal is currently pending. 173 <PAGE> Richard Jernee, et al v. Kinder Morgan Energy Partners, et al, No. CV03-03482 (Second Judicial District Court, State of Nevada, County of Washoe) ("Jernee"). On May 30, 2003, a separate group of plaintiffs, individually and on behalf of Adam Jernee, filed a civil action in the Nevada State trial court against us and several Kinder Morgan related entities and individuals and additional unrelated defendants ("Jernee"). Plaintiffs in the Jernee matter claim that defendants negligently and intentionally failed to inspect, repair and replace unidentified segments of their pipeline and facilities, allowing "harmful substances and emissions and gases" to damage "the environment and health of human beings." Plaintiffs claim that "Adam Jernee's death was caused by leukemia that, in turn, is believed to be due to exposure to industrial chemicals and toxins." Plaintiffs purport to assert claims for wrongful death, premises liability, negligence, negligence per se, intentional infliction of emotional distress, negligent infliction of emotional distress, assault and battery, nuisance, fraud, strict liability, and aiding and abetting, and seek unspecified special, general and punitive damages. The Kinder Morgan defendants filed Motions to Dismiss the complaint on November 20, 2003, which Motions are currently pending. In addition, plaintiffs and the defendant City of Fallon have appealed the Trial Court's ruling on initial procedural matters concerning proper venue. On March 29, 2004, the Nevada Supreme Court stayed the action pending resolution of these procedural matters on appeal. This appeal is currently pending. Floyd Sands, et al v. Kinder Morgan Energy Partners, et al, No. CV03-05326 (Second Judicial District Court, State of Nevada, County of Washoe) ("Sands"). On August 28, 2003, a separate group of plaintiffs, represented by the counsel for the plaintiffs in the Jernee matter, individually and on behalf of Stephanie Suzanne Sands, filed a civil action in the Nevada State trial court against us and several Kinder Morgan related entities and individuals and additional unrelated defendants ("Sands"). Plaintiffs in the Sands matter claim that defendants negligently and intentionally failed to inspect, repair and replace unidentified segments of their pipeline and facilities, allowing "harmful substances and emissions and gases" to damage "the environment and health of human beings." Plaintiffs claim that Stephanie Suzanne Sands' death was caused by leukemia that, in turn, is believed to be due to exposure to industrial chemicals and toxins. Plaintiffs purport to assert claims for wrongful death, premises liability, negligence, negligence per se, intentional infliction of emotional distress, negligent infliction of emotional distress, assault and battery, nuisance, fraud, strict liability, and aiding and abetting, and seek unspecified special, general and punitive damages. The Kinder Morgan defendants were served with the Complaint on January 10, 2004. On February 26, 2004, the Kinder Morgan defendants filed a Motion to Dismiss and a Motion to Strike, which motions are currently pending. In addition, plaintiffs and the defendant City of Fallon have appealed the Trial Court's ruling on initial procedural matters concerning proper venue and a peremptory challenge of the trial judge by the plaintiffs. On April 27, 2004, the Nevada Supreme Court stayed the action pending resolution of these procedural matters on appeal. This appeal is currently pending. Based on the information available to date, our own preliminary investigation, and the positive results of investigations conducted by State and Federal agencies, we believe that the claims against us in these matters are without merit and intend to defend against them vigorously. Meritage Homes Corp., Monterey Homes Construction, Inc., and Monterey Homes Arizona, Inc. v. Kinder Morgan Energy Partners, L.P. and SFPP Limited Partnership, No. CIV 05 021 TUCCKJ, United States District Court, Arizona. On January 28, 2005, Meritage Homes Corp. and its above-named affiliates filed a Complaint in the above-entitled action against us and SFPP, LP. The Plaintiffs are homebuilders who constructed a subdivision known as Silver Creek II located in Tucson, Arizona. Plaintiffs allege that, as a result of a July 30, 2003 pipeline rupture and accompanying release of petroleum products, soil and groundwater adjacent to, on and underlying portions of Silver Creek II became contaminated. Plaintiffs allege that they have incurred and continue to incur costs, damages and expenses associated with the delay of closings of home sales within Silver Creek II and damage to their reputation and goodwill as a result of the rupture and release. Plaintiffs' Complaint purports to assert claims for negligence, breach of contract, trespass, nuisance, strict liability, subrogation and indemnity, and negligence per se. Plaintiffs seek "no less than $1,500,000 in compensatory damages and necessary response costs," a declaratory judgment, interest, punitive damages and attorneys' fees and costs. We dispute the legal and factual bases for many of Plaintiffs' claimed compensatory damages, deny that punitive damages are appropriate under the facts, and intend to vigorously defend this action. 174 <PAGE> Walnut Creek, California Pipeline Rupture On November 9, 2004, Mountain Cascade, Inc., a third-party contractor on a water main replacement project hired by East Bay Municipal Utility District, struck and ruptured an underground petroleum pipeline owned and operated by SFPP, LP in Walnut Creek, California. An explosion occurred immediately following the rupture that resulted in five fatalities and several injuries to employees or contractors of Mountain Cascade. The incident is currently under investigation by Cal/OSHA and the California State Fire Marshall's Office, and we are cooperating with such investigations. Juana Lilian Arias, et. al v. Kinder Morgan, Inc., Kinder Morgan Energy Partners, L.P., Mountain Cascade, Inc., and Does 1-30, No. RG05195567 (Superior Court, Alameda County, California). The above-referenced complaint for personal injuries and wrongful death was filed on January 26, 2005. Plaintiffs allege that Victor Javier Rodriguez was killed as a result of the rupture by Mountain Cascade, Inc. of SFPP, LP's petroleum pipeline in Walnut Creek, California and the resulting explosion and fire. Plaintiffs allege that defendants failed to properly locate and mark the location of the petroleum pipeline. The complaint purports to assert claims for negligence, unfair competition, strict liability and intentional misrepresentation. Plaintiffs seek unspecified general damages, incidental damages, economic damages, disgorgement of profits, exemplary damages, interest, attorneys' fees and costs. Marilu Angeles, et. al v. Kinder Morgan, Inc., Kinder Morgan Energy Partners, L.P., Mountain Cascade, Inc., Does 1-30 and Mariel Hernandez, No. RG05195680 (Superior Court, Alameda County, California). The above-referenced complaint for personal injuries and wrongful death was filed on January 26, 2005. Plaintiffs allege that Israel Hernandez was killed as a result of the rupture by Mountain Cascade, Inc. of SFPP, LP's petroleum pipeline in Walnut Creek, California and the resulting explosion and fire. Plaintiffs allege that defendants failed to properly locate and mark the location of the petroleum pipeline. The complaint purports to assert claims for negligence, unfair competition, strict liability and intentional misrepresentation. Plaintiffs seek unspecified general damages, incidental damages, economic damages, disgorgement of profits, exemplary damages, interest, attorneys' fees and costs. Jeremy and Johanna Knox v. Mountain Cascade, Inc, Kinder Morgan Energy Partners of Houston, Inc., and Does 1 to 50, No. C 05-00281 (Superior Court, Contra Costa County, California). The above-referenced complaint for personal injuries was filed on February 2, 2005. Plaintiffs allege that Jeremy Knox was injured as a result of the rupture by Mountain Cascade, Inc. of SFPP, LP's petroleum pipeline in Walnut Creek, California and the resulting explosion and fire. Plaintiffs allege that defendants failed to properly locate and mark the location of the petroleum pipeline. Plaintiffs assert claims for negligence, loss of consortium, and exemplary damages in an unspecified amount. Based upon our initial investigation of the cause of the rupture of SFPP, LP's petroleum pipeline by Mountain Cascade, Inc. and the resulting explosion and fire, we intend to deny liability for the resulting deaths, injuries and damages, to vigorously defend against such claims, and to seek contribution and indemnity from the responsible parties. Marion County, Mississippi Litigation In 1968, Plantation Pipe Line Company discovered a release from its 12-inch pipeline in Marion County, Mississippi. The pipeline was immediately repaired. In 1998 and 1999, 62 lawsuits were filed on behalf of 263 plaintiffs in the Circuit Court of Marion County, Mississippi. The majority of the claims are based on alleged exposure from the 1968 release, including claims for property damage and personal injury. During the fourth quarter of 2004, a settlement was reached and settlements have been completed between almost all of the plaintiffs and Plantation. Five remaining plaintiffs that did not participate in the settlements described above have indicated in writing a willingness to settle with Plantation. It is anticipated that all of the 175 <PAGE> proceedings to complete the settlements will be completed by the end of the first quarter of 2005. We believe that the ultimate resolution of these Marion County, Mississippi cases will not have a material effect on our business, financial position, results of operations or cash flows. Exxon Mobil Corporation v. GATX Corporation, Kinder Morgan Liquids Terminals, Inc. and ST Services, Inc. On April 23, 2003, Exxon Mobil Corporation filed the Complaint in the Superior Court of New Jersey, Gloucester County. We filed our answer to the Complaint on June 27, 2003, in which we denied ExxonMobil's claims and allegations as well as included counterclaims against ExxonMobil. The lawsuit relates to environmental remediation obligations at a Paulsboro, New Jersey liquids terminal owned by ExxonMobil from the mid-1950s through November 1989, by GATX Terminals Corp. from 1989 through September 2000, and owned currently by ST Services, Inc. Prior to selling the terminal to GATX Terminals, ExxonMobil performed an environmental site assessment of the terminal required prior to sale pursuant to state law. During the site assessment, ExxonMobil discovered items that required remediation and the New Jersey Department of Environmental Protection issued an order that required ExxonMobil to perform various remediation activities to remove hydrocarbon contamination at the terminal. ExxonMobil, we understand, is still remediating the site and has not been removed as a responsible party from the state's cleanup order; however, ExxonMobil claims that the remediation continues because of GATX Terminals' storage of a fuel additive, MTBE, at the terminal during GATX Terminals' ownership of the terminal. When GATX Terminals sold the terminal to ST Services, the parties indemnified one another for certain environmental matters. When GATX Terminals was sold to us, GATX Terminals' indemnification obligations, if any, to ST Services may have passed to us. Consequently, at issue is any indemnification obligations we may owe to ST Services in respect to environmental remediation of MTBE at the terminal. The Complaint seeks any and all damages related to remediating MTBE at the terminal, and, according to the New Jersey Spill Compensation and Control Act, treble damages may be available for actual dollars incorrectly spent by the successful party in the lawsuit for remediating MTBE at the terminal. The parties have recently completed discovery. In October 2004, the judge assigned to the case dismissed himself from the case based on a conflict, and the new judge has ordered the parties to participate in mandatory mediation. The mediation is scheduled for March 2005. Exxon Mobil Corporation v. Enron Gas Processing Co., Enron Corp., as party in interest for Enron Helium Company, a division of Enron Corp., Enron Liquids Pipeline Co., Enron Liquids Pipeline Operating Limited Partnership, Kinder Morgan Operating L.P. "A," and Kinder Morgan, Inc., No. 2000-45252 (189th Judicial District Court, Harris County, Texas) On September 1, 2000, Plaintiff Exxon Mobil Corporation filed its Original Petition and Application for Declaratory Relief against Kinder Morgan Operating L.P. "A," Enron Liquids Pipeline Operating Limited Partnership n/k/a Kinder Morgan Operating L.P. "A," Enron Liquids Pipeline Co. n/k/a Kinder Morgan G.P., Inc., Enron Gas Processing Co. n/k/a ONEOK Bushton Processing, Inc., and Enron Helium Company. Plaintiff added Enron Corp. as party in interest for Enron Helium Company in its First Amended Petition and added Kinder Morgan, Inc. as a Defendant. The claims against Enron Corp. were severed into a separate cause of action. Plaintiff's claims are based on a Gas Processing Agreement entered into on September 23, 1987 between Mobil Oil Corp. and Enron Gas Processing Company relating to gas produced in the Hugoton Field in Kansas and processed at the Bushton Plant, a natural gas processing facility located in Kansas. Plaintiff also asserts claims relating to the Helium Extraction Agreement entered between Enron Helium Company (a division of Enron Corp.) and Mobil Oil Corporation dated March 14, 1988. Plaintiff alleges that Defendants failed to deliver propane and to allocate plant products to Plaintiff as required by the Gas Processing Agreement and originally sought damages of approximately $5.9 million. Plaintiff filed its Third Amended Petition on February 25, 2003. In its Third Amended Petition, Plaintiff alleges claims for breach of the Gas Processing Agreement and the Helium Extraction Agreement, requests a declaratory judgment and asserts claims for fraud by silence/bad faith, fraudulent inducement of the 1997 Amendment to the Gas Processing Agreement, civil conspiracy, fraud, breach of a duty of good faith and fair dealing, negligent misrepresentation and conversion. As of April 7, 2003, Plaintiff alleged economic damages for the period from November 1987 through March 1997 in the amount of $30.7 million. On May 2, 2003, Plaintiff added claims for the period from April 1997 through February 2003 in the amount of $12.9 million. On June 23, 2003, Plaintiff filed a Fourth Amended Petition that reduced its total claim for economic damages to $30.0 million. On October 5, 2003, 176 <PAGE> Plaintiff filed a Fifth Amended Petition that purported to add a cause of action for embezzlement. On February 10, 2004, Plaintiff filed its Eleventh Supplemental Responses to Requests for Disclosure that restated its alleged economic damages for the period of November 1987 through December 2003 as approximately $37.4 million. The matter went to trial on June 21, 2004. On June 30, 2004, the jury returned a unanimous verdict in favor of all defendants as to all counts. Final Judgment was entered in favor of the defendants on August 19, 2004. The Plaintiff has stated that it is currently reviewing its appellate options. Although no assurances can be given, we believe that we have meritorious defenses to all of these actions, that, to the extent an assessment of the matter is possible, we have established an adequate reserve to cover potential liability, and that these matters will not have a material adverse effect on our business, financial position, results of operations or cash flows. Proposed Office of Pipeline Safety Civil Penalty and Compliance Order On July 15, 2004, the U.S. Department of Transportation's Office of Pipeline Safety ("OPS") issued a Proposed Civil Penalty and Proposed Compliance Order (the "Proposed Order") concerning alleged violations of certain federal regulations concerning our pipeline Integrity Management Program. The violations alleged in the Proposed Order are based upon the results of inspections of our Integrity Management Program at our products pipelines facilities in Orange, California and Doraville, Georgia conducted in April and June of 2003, respectively. As a result of the alleged violations, the OPS seeks to have us implement a number of changes to our Integrity Management Program and also seeks to impose a proposed civil penalty of $325,000. We have already addressed a number of the concerns identified by the OPS and intend to continue to work with the OPS to ensure that our Integrity Management Program satisfies all applicable regulations. However, we dispute some of the OPS findings and disagree that civil penalties are appropriate, and therefore have requested an administrative hearing on these matters according to the U.S. Department of Transportation regulations. A hearing date is expected to occur in the second quarter of 2005. Environmental Matters We are subject to environmental cleanup and enforcement actions from time to time. In particular, the federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) generally imposes joint and several liability for cleanup and enforcement costs on current or predecessor owners and operators of a site, among others, 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 law and regulations, risks of additional costs and liabilities are inherent in pipeline, terminal and carbon dioxide field and oil field operations, and there can be no assurance that we will not incur significant costs and liabilities. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities to us. We are currently involved in the following governmental proceedings related to compliance with environmental regulations associated with our assets and have established a reserve to address the costs associated with the cleanup: o several ground water hydrocarbon remediation efforts under administrative orders or related state remediation programs issued by the California Regional Water Quality Control Board and several other state agencies for assets associated with SFPP, L.P.; o groundwater and soil remediation efforts under administrative orders issued by various regulatory agencies on those assets purchased from GATX Corporation, comprising Kinder Morgan Liquids Terminals LLC, CALNEV Pipe Line LLC and Central Florida Pipeline LLC; o groundwater and soil remediation efforts under administrative orders or related state remediation programs issued by various regulatory agencies on those assets purchased from ExxonMobil; ConocoPhillips; and Charter Triad, comprising Kinder Morgan Southeast Terminals, LLC.; and 177 <PAGE> o groundwater and soil remediation efforts under administrative orders or related state remediation programs issued by various regulatory agencies on those assets comprising Plantation Pipe Line Company, including a ground water remediation effort taking place between Chevron, Plantation Pipe Line Company and the Alabama Department of Environmental Management. Tucson, Arizona On July 30, 2003, SFPP, L.P. suffered a sudden and accidental rupture of one of its liquid products pipelines in the vicinity of Tucson, Arizona. The rupture resulted in the release of petroleum product into the soil and groundwater in the immediate vicinity of the rupture. On September 11, 2003, the Arizona Department of Environmental Quality ("ADEQ") issued a Notice of Violation indicating that ADEQ "has reason to believe" that SFPP violated certain Arizona statutes and rules due to the discharge of petroleum product to the environment as a result of the pipeline rupture. ADEQ asserted that such alleged violations could result in the imposition of civil penalties against SFPP. SFPP timely responded to the Notice of Violation, disputed its validity, and provided the information requested in the Notice of Violation. According to ADEQ written policy, a Notice of Violation is not an enforcement action, and is instead "an enforcement compliance assurance tool used by ADEQ." ADEQ's policy also states that although ADEQ has the "authority to issue appealable administrative orders compelling compliance, a Notice of Violation has no such force or effect." On November 13, 2003, ADEQ sent a second Notice of Violation with respect to the pipeline rupture and release, stating that ADEQ had reason to believe that a violation of additional Arizona regulations had resulted from the discharge of petroleum, because the petroleum had reached groundwater. ADEQ asserted that such alleged violations could result in the imposition of civil penalties against SFPP. SFPP timely responded to this second Notice of Violation, disputed its validity, and provided the information requested in the second Notice of Violation. On January 19, 2005, SFPP, L.P. and ADEQ announced a settlement with the terms of the settlement set forth in a consent judgment filed with the Maricopa County Superior Court. Under the terms of the settlement, we will pay $500,000 to the State of Arizona in full settlement of any possible claims by the state arising out of the release. The settlement expressly provides that we do not admit any wrongdoing or violation of environmental law. We are currently evaluating the long term costs of the cleanup. A substantial portion of those costs are recoverable through insurance. Cordelia, California On April 28, 2004, we discovered a spill of diesel fuel into a marsh near Cordelia, California from a section of pipeline on our Pacific Operations. Current estimates indicate that the size of the spill was approximately 2,450 barrels. Upon discovery of the spill and notification to regulatory agencies, a unified response was implemented with the United States Coast Guard, the California Department of Fish and Game, the Office of Spill Prevention and Response ("OSPR") and us. The damaged section of the pipeline has been removed and replaced, and the pipeline resumed operations on May 2, 2004. We have completed recovery of free flowing diesel from the marsh and completed an enhanced biodegradation program for removal of the remaining constituents bound up in soils. The property has been turned back to the owners for its stated purpose. There will be ongoing monitoring under the oversight of the California Regional Water Quality Control Board until the site conditions demonstrate there are no further actions required. The circumstances surrounding the release and impact thereof are currently under review by the OSPR and the United States Environmental Protection Agency. San Diego, California In June 2004, we entered into discussions with the City of San Diego with respect to impacted groundwater beneath the City's stadium property in San Diego resulting from operations at the Mission Valley terminal facility. The City has requested that SFPP work with the City as they seek to re-develop options for the stadium area including future use of both groundwater aquifer and real estate development. The City of San Diego and SFPP are working cooperatively towards a settlement and a long term plan as SFPP continues to remediate the impacted 178 <PAGE> groundwater. We do not expect the cost of any settlement and remediation plan to be material. This site has been, and currently is, under the regulatory oversight and order of the California Regional Water Quality Control Board. Baker, California In November 2004, our CALNEV pipeline, which transports refined petroleum products from Colton, California to Las Vegas, Nevada, experienced a failure in the line from external damage, resulting in a release of gasoline that affected approximately two acres of land in the high desert administered by The Bureau of Land Management, an agency within the U.S. Department of the Interior. Remediation has been conducted and continues for product in the soils. All agency requirements have been met and the site will be closed upon completion of the soil remediation. Oakland, California In February 2005, we were contacted by the U.S. Coast Guard regarding a potential release of jet fuel in the Oakland, California area. Our northern California team responded and discovered that one of our product pipelines had been damaged by a third party, which resulted in a release of jet fuel which migrated to the storm drain system. We have coordinated the remediation of the impacts from this release. Other Environmental On March 30, 2004, the Texas Commission on Environmental Quality (TCEQ) issued a Notice of Enforcement Action related to our CO2 segment's Snyder Gas Plant. We are currently in final settlement discussions with TCEQ regarding this issue and do not expect the cost of any settlement to be material. 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. Furthermore, our review of assets related to Kinder Morgan Interstate Gas Transmission LLC indicates possible environmental impacts from petroleum and used oil releases into the soil and groundwater at nine sites. Additionally, our review of assets related to Kinder Morgan Texas Pipeline and Kinder Morgan Tejas indicates possible environmental impacts from petroleum releases into the soil and groundwater at nine sites. Further delineation and remediation of any environmental impacts from these matters will be conducted. Reserves have been established to address these issues. Additionally, we are involved with and have been identified as a potentially responsible party in several federal and state superfund sites. Environmental reserves have been established for those sites where our contribution is probable and reasonably estimable. Although no assurance can be given, we believe that the ultimate resolution of the environmental matters set forth in this note will not have a material adverse effect on our business, financial position, results of operations or cash flows. Many factors may change in the future affecting our reserve estimates, such as regulatory changes, groundwater and land use near our sites, and changes in cleanup technology. As of December 31, 2004, we have accrued an environmental reserve of $40.9 million. Our reserve estimates range in value from approximately $40.9 million to approximately $77.6 million, and we have recorded a liability equal to the low end of the range. 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, results of operations or cash flows. 179 <PAGE> 17. Recent Accounting Pronouncements FASB Staff Position Nos. FAS 106-1 and FAS 106-2 In January 2004, the Financial Accounting Standards Board issued FASB Staff Position FAS 106-1, "Accounting and Disclosure Requirements Related to the New Medicare Prescription Drug, Improvement and Modernization Act of 2003", referred to in this report as the Act. This Staff Position permits a sponsor of a post-retirement health care plan that provides a prescription drug benefit to make a one-time election to postpone accounting for the effects of the Act. In May 2004, the FASB issued Staff Position FAS 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003," which supersedes Staff Position FAS 106-1 effective July 1, 2004. Staff Position FAS 106-2 provides transitional guidance for accounting for the effects of the Act on the accumulated projected benefit obligation and periodic post-retirement health care benefit expense. This Staff Position does not have any immediate effect on our consolidated financial statements. EITF 03-06 In March 2004, the Emerging Issues Task Force issued Statement No. 03-06, or EITF 03-06, "Participating Securities and the Two-Class Method under Financial Accounting Standards Board Statement No. 128, Earnings Per Share." EITF 03-06 addresses a number of questions regarding the computation of earnings per share by companies that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the company when, and if, it declares dividends on its common stock. The Statement also provides further guidance in applying the two-class method of calculating earnings per share, clarifying what constitutes a participating security and how to apply the two-class method of computing earnings per share once it is determined that a security is participating, including how to allocate undistributed earnings to such a security. EITF 03-06 was effective for fiscal periods beginning after March 31, 2004. The adoption of EITF 03-06 did not result in a change in our earnings per unit for any of the periods presented or prior periods. SFAS No. 151 In November 2004, the FASB issued SFAS No. 151, "Inventory Costs," an amendment of Accounting Research Bulletin No. 43, Chapter 4, "Inventory Pricing." This Statement clarifies that abnormal amounts of idle facility expense, freight, handling costs, and wasted materials (spoilage) should be recognized as current-period charges. In addition, the Statement requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. The provisions of this Statement are to be applied prospectively and are effective for inventory costs incurred during fiscal years beginning after June 15, 2005. We do not expect the adoption of this Statement to have any immediate effect on our consolidated financial statements. SFAS No. 123R In December 2004, the FASB issued SFAS No. 123R (revised 2004), "Share-Based Payment." This Statement amends SFAS No. 123, "Accounting for Stock-Based Compensation," and requires companies to expense the value of employee stock options and similar awards. Significant provisions of SFAS No. 123R include the following: o share-based payment awards result in a cost that will be measured at fair value on the awards' grant date, based on the estimated number of awards that are expected to vest. Compensation cost for awards that vest would not be reversed if the awards expire without being exercised; o when measuring fair value, companies can choose an option-pricing model that appropriately reflects their specific circumstances and the economics of their transactions; o companies will recognize compensation cost for share-based payment awards as they vest, including the related tax effects. Upon settlement of share-based payment awards, the tax effects will be recognized in the income statement or additional paid-in capital; and 180 <PAGE> o public companies are allowed to select from three alternative transition methods - each having different reporting implications. In October 2004, the FASB decided to delay by six months the effective date for public companies to implement SFAS No. 123R (revised 2004). The new Statement is now effective for public companies for interim and annual periods beginning after June 15, 2005. Public companies with calendar year-ends will be required to adopt SFAS No. 123R in the third quarter of 2005. We are currently reviewing the effects of this accounting Statement; however, we have not granted common unit options since May 2000 and we do not expect the adoption of this Statement to have any immediate effect on our consolidated financial statements. SFAS No. 152 In December 2004, the FASB issued SFAS No. 152, "Accounting for Real Estate Time-Sharing Transactions." This Statement amends SFAS No. 66, "Accounting for Sales of Real Estate" to reference the financial accounting and reporting guidance for real estate time-sharing transactions that is provided in American Institute of Certified Public Accountants Statement of Position No. 04-2, "Accounting for Real Estate Time-Sharing Transactions", or SOP 04-2. SFAS No. 152 also amends SFAS No. 67, "Accounting for Costs and Initial Rental Operations of Real Estate Projects," to state that the guidance for (a) incidental operations and (b) costs incurred to sell real estate projects does not apply to real estate time-sharing transactions. The accounting for those operations and costs is subject to the guidance of SOP 04-2. SFAS No. 152 is effective for financial statement for fiscal years beginning after June 15, 2005. We do not expect the adoption of this Statement to have any immediate effect on our consolidated financial statements. SFAS No. 153 In December 2004, the FASB issued SFAS No. 153, "Exchanges of Nonmonetary Assets." This Statement amends Accounting Principles Board Opinion No. 29, "Accounting for Nonmonetary Transactions," which is based on the principal that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. However, APB No. 29 included certain exceptions to that principal. SFAS No. 153 amends APB No. 29 to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this Statement shall be effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. Earlier application is permitted and the Statement shall be applied prospectively. We do not expect the adoption of this Statement to have any immediate effect on our consolidated financial statements. 18. Quarterly Financial Data (Unaudited) <TABLE> <CAPTION> Basic Diluted Operating Operating Net Income Net Income Revenues Income Net Income per Unit per Unit -------- ------ ---------- -------- -------- (In thousands, except per unit amounts) <S> <C> <C> <C> <C> <C> 2004 First Quarter..... $1,822,256 $ 225,142 $ 191,754 $ 0.52 $ 0.52 Second Quarter.... 1,957,182 231,364 195,218 0.51 0.51 Third Quarter..... 2,014,659 252,836 217,342 0.59 0.59 Fourth Quarter.... 2,138,764 264,654 227,264 0.59 0.59 2003 First Quarter(a).. $1,788,838 $ 195,152 $ 170,478 $ 0.52 $ 0.52 Second Quarter.... 1,664,447 199,562 168,957 0.48 0.48 Third Quarter..... 1,650,842 204,965 174,176 0.49 0.49 Fourth Quarter.... 1,520,195 207,010 183,726 0.51 0.51 - ---------- </TABLE> (a) 2003 first quarter includes a benefit of $3,465 due to a cumulative effect adjustment related to a change in accounting for asset retirement obligations. Net income before cumulative effect of a change in accounting principle was $167,013 and basic and diluted net income before cumulative effect of a change in accounting principle was $0.50. 181 <PAGE> 19. Supplemental Information on Oil and Gas Producing Activities (Unaudited) The Supplementary Information on Oil and Gas Producing Activities is presented as required by SFAS No. 69, "Disclosures about Oil and Gas Producing Activities." The supplemental information includes capitalized costs related to oil and gas producing activities; costs incurred for the acquisition of oil and gas producing activities, exploration and development activities; and the results of operations from oil and gas producing activities. Supplemental information is also provided for per unit production costs; oil and gas production and average sales prices; the estimated quantities of proved oil and gas reserves; the standardized measure of discounted future net cash flows associated with proved oil and gas reserves; and a summary of the changes in the standardized measure of discounted future net cash flows associated with proved oil and gas reserves. Our capitalized costs consisted of the following (in thousands): Capitalized Costs Related to Oil and Gas Producing Activities December 31, -------------------------------------- Consolidated Companies(a) 2004 2003 2002 ----------- ----------- ---------- Wells and equipment, facilities and other.............................. $ 815,311 $ 601,744 $ 198,082 Leasehold............................ 315,100 234,996 47,787 ----------- ----------- ---------- Total proved oil and gas properties.. 1,130,411 836,740 245,869 Accumulated depreciation and depletion.......................... (174,802) (72,572) (27,164) ----------- ----------- ---------- Net capitalized costs................ $ 955,609 $ 764,168 $ 218,705 =========== =========== ========== - ---------- (a) Amounts relate to Kinder Morgan CO2 Company, L.P. and Consolidated Subsidaries. Includes capitalized asset retirement costs and associated accumulated depreciation. There are no capitalized costs associated with unproved oil and gas properties for the periods reported. December 31, ------------ Equity Investee(a) 2002 ------------ Net capitalized costs.............................. $ 60,257 ============ - ---------- (a) Amounts relate to our previous 15% ownership interest in MKM Partners, L.P., which we accounted for under the equity method. MKM Partners, L.P. was dissolved on June 30, 2003. There are no capitalized costs associated with unproved oil and gas properties for the period reported. Our costs incurred for property acquisition, exploration and development were as follows (in thousands): Costs Incurred in Exploration, Property Acquisitions and Development Year Ended December 31, --------------------------------------- Consolidated Companies(a) 2004 2003 2002 ------------ ------------ ----------- Property Acquisition Proved oil and gas properties....... $ - $ 325,022 $ - Development(b)........................ 293,671 265,849 128,014 - ---------- (a) Amounts relate to Kinder Morgan CO2 Company, L.P. and Consolidated Subsidaries. There are no capitalized costs associated with unproved oil and gas properties for the periods reported. All capital expenditures were made to develop our proved oil and gas properties and no exploration costs were incurred for the periods reported. (b) Includes all capitalized and expensed costs. For the years ended December 31, 2003 and 2002, we incurred development costs related to our previous 15% equity interest in MKM Partners, L.P. in the amounts of $1.8 million and $3.8 million, respectively. Our results of operations from oil and gas producing activities for each of the years 2004, 2003 and 2002 are shown in the following table: 182 <PAGE> Results of Operations for Oil and Gas Producing Activities Consolidated Companies(a) -------------- For the Year Ended December 31, 2004 (In thousands) Revenues............................................... $ 361,809 Expenses: Production costs....................................... (131,501) Other operating expenses............................... (44,043) Depreciation, depletion and amortization expenses...... (104,147) ------------- Total expenses....................................... (279,691) ------------- Results of operations for oil and gas producing activities............................................ $ 82,118 ============= For the Year Ended December 31, 2003 Revenues............................................... $ 171,270 Expenses: Production costs....................................... (63,929) Other operating expenses(b)............................ (22,387) Depreciation, depletion and amortization expenses...... (47,404) ------------- Total expenses....................................... (133,720) ------------- Results of operations for oil and gas producing activities............................................ $ 37,550 ============= For the Year Ended December 31, 2002 Revenues............................................... $ 84,744 Expenses: Production costs....................................... (38,449) Other operating expenses(b)............................ (11,123) Depreciation, depletion and amortization expenses...... (17,995) ------------- Total expenses....................................... (67,567) ------------- Results of operations for oil and gas producing activities............................................ $ 17,177 ============= Equity Investee(c) For the Year Ended December 31, 2003................... $ 3,682 ============= For the Year Ended December 31, 2002.................. $ 7,806 ============= - ---------- (a) Amounts relate to Kinder Morgan CO2 Company, L.P. and Consolidated Subsidaries. (b) Consists primarily of carbon dioxide expense. (c) Amounts relate to our previous 15% ownership interest in MKM Partners, L.P., which we accounted for under the equity method. MKM Partners, L.P. was dissolved on June 30, 2003. Operating statistics from our oil and gas producing activities for each of the years 2004, 2003 and 2002 are shown in the following table: <TABLE> <CAPTION> Results of Operations for Oil and Gas Producing Activities - Unit Prices and Costs Year Ended December 31, 2004 2003 2002 ------------ ------------ ----------- <S> <C> <C> <C> Consolidated Companies(a) Production costs per barrel of oil equivalent(b)(c)(d). $ 9.71 $ 8.98 $ 10.19 ============ ============ ============ Production costs per total barrels of oil equivalent(e) $ 8.63 $ 7.87 $ 9.12 ============ ============ ============ Crude oil production (MBbl/d).......................... 32.5 18.0 9.6 ============ ============ ============ Natural gas liquids production (MBbl/d)(d)............. 3.7 1.3 0.6 Natural gas liquids production from gas plants(MBbl/d)(e) 4.0 2.4 1.5 ------------ ------------ ------------ Total natural gas liquids production(MBbl/d)......... 7.7 3.7 2.1 ============ ============ ============ Natural gas production (MMcf/d)(d)..................... 4.4 1.6 0.6 Natural gas production from gas plants(MMcf/d)(e)...... 3.9 2.0 1.5 ------------ ------------ ------------ Total natural gas production(MMcf/d)................. 8.3 3.6 2.1 ============ ============ ============ Average sales prices including hedge gains/losses: Crude oil price per Bbl.............................. $ 25.72 $ 23.73 $ 22.45 ============ ============ ============ Natural gas liquids price per Bbl.................... $ 31.37 $ 22.49 $ 23.20 ============ ============ ============ Natural gas price per Mcf............................ $ 5.27 $ 4.40 $ 1.80 ============ ============ ============ Total natural gas liquids price per Bbl(e)........... $ 31.33 $ 21.77 $ 24.60 ============ ============ ============ Total natural gas price per Mcf(e)................... $ 5.24 $ 4.50 $ 2.60 ============ ============ ============ Average sales prices excluding hedge gains/losses: Crude oil price per Bbl............................. $ 40.91 $ 31.26 $ 25.22 ============ ============ ============ Natural gas liquids price per Bbl................... $ 31.68 $ 24.70 $ 23.13 ============ ============ ============ Natural gas price per Mcf........................... $ 5.27 $ 4.40 $ 1.80 ============ ============ ============ </TABLE> 183 <PAGE> - ---------- (a) Amounts relate to Kinder Morgan CO2 Company, L.P. and Consolidated Subsidaries. (b) Computed using production costs, excluding transportation costs, as defined by the Securities and Exchange Commisson. Natural gas volumes were converted to barrels of oil equivalent (BOE) using a conversion factor of six mcf of natural gas to one barrel of oil. (c) Production costs include labor, repairs and maintenance, materials, supplies, fuel and power, property taxes, severance taxes, and general and administrative expenses directly related to oil and gas producing activities. (d) Includes only production attributable to leasehold ownership. (e) Includes production attributable to our ownership in processing plants and third party processing agreements. * Less than 0.1 MMcf per day. The table below represents our estimate of proved crude oil, natural gas liquids and natural gas reserves based upon our evaluation of pertinent geological and engineering data in accordance with United States Securities and Exchange Commission regulations. Estimates of proved reserves have been prepared by our team of reservoir engineers and geoscience professionals and are reviewed by members of our senior management with professional training in petroleum engineering to ensure that we consistently apply rigorous professional standards and the reserve definitions prescribed by the United States Securities and Exchange Commission. Netherland, Sewell and Associates, Inc., independent oil and gas consultants, have reviewed the estimates of proved reserves of natural gas, natural gas liquids and crude oil that we have attributed to our net interest in oil and gas properties as of December 31, 2004. Based upon their review of more than 99% of our reserve estimates, it is their judgment that the estimates are reasonable in the aggregate. We believe the geologic and engineering data examined provides reasonable assurance that the proved reserves are recoverable in future years from known reservoirs under existing economic and operating conditions. Estimates of proved reserves are subject to change, either positively or negatively, as additional information becomes available and contractual and economic conditions change. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, that is, prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. Proved developed reserves are the quantities of crude oil, natural gas liquids and natural gas expected to be recovered through existing investments in wells and field infrastructure under current operating conditions. Proved undeveloped reserves require additional investments in wells and related infrastructure in order to recover the production. During 2004, we filed estimates of our oil and gas reserves for the year 2003 with the Energy Information Administration of the U. S. Department of Energy on Form EIA-23. The data on Form EIA-23 was presented on a different basis, and included 100% of the oil and gas volumes from our operated properties only, regardless of our net interest. The difference between the oil reserves reported on Form EIA-23 and those reported in this report exceeds 5%. 184 <PAGE> Reserve Quantity Information Consolidated Companies(a) ------------------------- Crude Oil NGLs Nat. Gas (MBbls) (MBbls) (MMcf)(d) --------- --------- ----------- Proved developed and undeveloped reserves: As of December 31, 2001.................... 12,284 1,879 6,746 Revisions of previous estimates.......... 60,927 14,009 10,932 Production............................... (3,505) (230) (228) Purchases of reserves in place........... 1,013 185 746 ---------- --------- --------- As of December 31, 2002.................... 70,719 15,843 18,196 Revisions of previous estimates(b)....... 2,037 (1,404) (14,538) Production............................... (6,579) (444) (582) Purchases of reserves in place........... 50,431 2,268 217 Sales of reserves in place............... - - - ---------- --------- --------- As of December 31, 2003.................... 116,608 16,263 3,293 Revisions of previous estimates.......... 19,030 5,350 (120) Production............................... (11,907) (1,368) (1,583) ---------- --------- --------- As of December 31, 2004.................... 123,731 20,245 1,590 ========== ========= ========= Equity Investee(c) As of December 31, 2001.................... 4,629 44 136 As of December 31, 2002.................... 5,454 362 370 Proved developed reserves: As of December 31, 2001.................... 8,699 1,341 4,951 As of December 31, 2002.................... 15,918 3,211 5,149 As of December 31, 2003(b)................. 64,879 8,160 2,551 As of December 31, 2004(b)................. 71,307 8,873 1,357 - ---------- (a) Amounts relate to Kinder Morgan CO2 Company, L.P. and Consolidated Subsidaries. (b) The downward revision in natural gas reserves was primarily attributable to natural gas reserves used as fuel on lease for the power generation facility. (c) Amounts relate to our previous 15% ownership interest in MKM Partners, L.P., which we accounted for under the equity method. MKM Partners, L.P. was dissolved on June 30, 2003. (d) Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degress fahrenheit. The standardized measure of discounted cash flows and summary of the changes in the standardized measure computation from year-to-year are prepared in accordance with SFAS No. 69. The assumptions that underly the computation of the standardized measure of discounted cash flows may be summarized as follows: o the standardized measure includes our estimate of proved crude oil, natural gas liquids and natural gas reserves and projected future production volumes based upon year-end economic conditions; o pricing is applied based upon year-end market prices adjusted for fixed or determinable contracts that are in existence at year-end; o future development and production costs are determined based upon actual cost at year-end; o the standardized measure includes projections of future abandonment costs based upon actual costs at year-end; and o a discount factor of 10% per year is applied annually to the future net cash flows. 185 <PAGE> Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves Consolidated Companies(a) -------------- (In thousands) As of December 31, 2004 Future cash inflows from production................. $ 5,799,658 Future production costs............................. (1,935,597) Future development costs(b)......................... (502,172) -------------- Undiscounted future net cash flows................ 3,361,889 10% annual discount................................. (1,316,923) -------------- Standardized measure of discounted future net cash flows............................................ $ 2,044,966 ============== As of December 31, 2003 Future cash inflows from production................. $ 4,149,369 Future production costs............................. (1,347,822) Future development costs(b)......................... (540,900) -------------- Undiscounted future net cash flows................ 2,260,647 10% annual discount................................. (852,832) -------------- Standardized measure of discounted future net cash flows....................................... $ 1,407,815 ============== As of December 31, 2002 Future cash inflows from production................. $ 2,630,701 Future production costs............................. (1,355,947) Future development costs(b)......................... (470,256) -------------- Undiscounted future net cash flows................ 804,498 10% annual discount................................. (290,386) -------------- Standardized measure of discounted future net cash flows............................................ $ 514,112 ============== Equity Investee(c) As of December 31, 2002 $ 55,352 ============== - ---------- (a) Amounts relate to Kinder Morgan CO2 Company, L.P. and Consolidated Subsidaries. (b) Includes abandonment costs. (c) Amounts relate to our previous 15% ownership interest in MKM Partners, L.P., which we accounted for under the equity method. MKM Partners, L.P. was dissolved on June 30, 2003. The following table represents our estimate of changes in the standardized measure of discounted future net cash flows from proved reserves: 186 <PAGE> Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Oil and Gas Reserves Consolidated Companies(a) -------------- (In thousands) Present value as of January 1, 2002................... $ 24,025 Changes during the year: Revenues less production and other costs.......... (35,173) Net changes in prices, production and other costs. 91,715 Development costs incurred........................ 128,014 Net changes in future development costs........... (405,689) Purchases of reserves in place.................... 12,019 Revisions of previous quantity estimates.......... 697,930 Accretion of discount............................. 2,302 Timing differences and other...................... (1,031) -------------- Net change for the year ............................ 490,087 -------------- Present value as of December 31, 2002................. $ 514,112 Changes during the year: Revenues less production and other costs.......... (84,954) Net changes in prices, production and other costs. 331,366 Development costs incurred........................ 265,849 Net changes in future development costs........... (309,843) Purchases of reserves in place.................... 689,593 Sales of reserves in place........................ - Revisions of previous quantity estimates.......... (23,412) Accretion of discount............................. 51,183 Timing differences and other...................... (26,079) -------------- Net change for the year ............................ 893,703 -------------- Present value as of December 31, 2003................. $ 1,407,815 Changes during the year: Revenues less production and other costs.......... (186,265) Net changes in prices, production and other costs. 324,260 Development costs incurred........................ 293,671 Net changes in future development costs........... (270,114) Revisions of previous quantity estimates.......... 396,946 Accretion of discount............................. 136,939 Timing differences and other...................... (58,286) -------------- Net change for the year ............................ 637,151 -------------- Present value as of December 31, 2004................. $ 2,044,966 ============== - ---------- (a) Amounts relate to Kinder Morgan CO2 Company, L.P. and Consolidated Subsidaries. 187 <PAGE> SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. KINDER MORGAN ENERGY PARTNERS, L.P. (A Delaware Limited Partnership) By: KINDER MORGAN G.P., INC., its General Partner By: KINDER MORGAN MANAGEMENT, LLC, its Delegate By: /s/ C. Park Shaper --------------------------------- C. Park Shaper, Executive Vice President and Chief Financial Officer Date: March 4, 2005 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. Signature Title Date --------- ----- ---- /s/ RICHARD D. KINDER Chairman of the Board. Chief March 4, 2005 - --------------------- Executive Officer and President Richard D. Kinder of Kinder Morgan Management, LLC, Delegate of Kinder Morgan G.P., Inc. /s/ EDWARD O. GAYLORD Director of Kinder Morgan March 4, 2005 - --------------------- Edward O. Gaylord Management, LLC, Delegate of Kinder Morgan G.P., Inc. /s/ GARY L. HULTQUIST Director of Kinder Morgan March 4, 2005 - --------------------- Gary L. Hultquist Management, LLC, Delegate of Kinder Morgan G.P., Inc. /s/ PERRY M. WAUGHTAL Director of Kinder Morgan March 4, 2005 - --------------------- Perry M. Waughtal Management, LLC, Delegate of Kinder Morgan G.P., Inc. /s/ C. PARK SHAPER Director, Executive Vice President March 4, 2005 - --------------------- and Chief Financial Officer of C. Park Shaper Kinder Morgan Management, LLC, Delegate of Kinder Morgan G.P., Inc. (principal financial officer and principal accounting officer) 188