MAGELLAN MIDSTREAM PARTNERS LP - 10-Q Quarterly Report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2004

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File No.: 1-16335

Magellan Midstream Partners, L.P.

(Exact name of registrant as specified in its charter)

Delaware

73-1599053

(State or other jurisdiction of

incorporation or organization)

(IRS Employer

Identification No.)

One Williams Center, P.O. Box 22186, Tulsa, Oklahoma 74121-2186

(Address of principal executive offices and zip code)

(918) 574-7000

(Registrant’s telephone number, including area code)

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 whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes x No ¨

As of August 5, 2004, there were outstanding 24,130,541 common units and 4,259,771 subordinated units.

TABLE OF CONTENTS


		Page
	PART I

	FINANCIAL INFORMATION

ITEM 1.	FINANCIAL STATEMENTS

	MAGELLAN MIDSTREAM PARTNERS, L.P.

	Consolidated Statements of Income for the three and six months ended June 30, 2003 and 2004	2

	Consolidated Balance Sheets as of December 31, 2003 and June 30, 2004	3

	Consolidated Statements of Cash Flows for the six months ended June 30, 2003 and 2004	4

	Notes to Consolidated Financial Statements	5

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	21

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	31

ITEM 4.	CONTROLS AND PROCEDURES	32

	FORWARD-LOOKING STATEMENTS	32

	PART II

	OTHER INFORMATION

ITEM 1.	LEGAL PROCEEDINGS	33

ITEM 2.	CHANGES IN SECURITIES AND USE OF PROCEEDS	34

ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	34

ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	34

ITEM 5.	OTHER INFORMATION	34

ITEM 6.	EXHIBITS AND REPORTS ON FORM 8-K	35

PART I

FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except per unit amounts)

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2003			2004			2003			2004
Transportation and terminals revenues:
Third party	$	90,845		$	103,699		$	170,308		$	192,629
Affiliate		4,871			—			13,122			—
Product sales revenues:
Third party		11,472			38,521			43,420			82,735
Affiliate		737			—			790			—

Total revenues		107,925			142,220			227,640			275,364
Costs and expenses:
Operating		42,350			42,911			75,709			79,911
Environmental		154			18,123			1,951			42,328
Environmental reimbursements		(72	)		(17,909	)		(1,258	)		(41,324	)
Product purchases		12,033			32,382			39,851			70,881
Depreciation and amortization		8,883			9,822			18,262			19,344
Affiliate general and administrative		16,485			13,507			26,923			26,394

Total costs and expenses		79,833			98,836			161,438			197,534
Equity earnings		—			148			—			268

Operating profit		28,092			43,532			66,202			78,098
Interest expense		8,499			8,704			17,530			17,219
Interest income		(28	)		(1,000	)		(554	)		(1,446	)
Debt prepayment premium		—			12,666			—			12,666
Write-off of unamortized debt placement fees		—			5,002			—			5,002
Debt placement fee amortization		762			656			1,309			1,338
Gain on derivative		—			(953	)		—			(953	)

Net income	$	18,859		$	18,457		$	47,917		$	44,272

Allocation of net income:
Limited partners’ interest	$	20,498		$	17,465		$	47,506		$	41,339
General partner’s interest		(1,639	)		992			411			2,933

Net income	$	18,859		$	18,457		$	47,917		$	44,272

Basic net income per limited partner unit	$	0.75		$	0.63		$	1.75		$	1.50

Weighted average number of limited partner units outstanding used for basic net income per unit calculation		27,190			27,797			27,190			27,595

Diluted net income per limited partner unit	$	0.75		$	0.63		$	1.74		$	1.50

Weighted average number of limited partner units outstanding used for diluted net income per unit calculation		27,190			27,860			27,254			27,649

See notes to consolidated financial statements.

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(In thousands)


	December 31, 2003			June 30, 2004
	December 31, 2003			June 30, 2004
				(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	111,357		$	51,951
Restricted cash		8,223			5,854
Accounts receivable (less allowance for doubtful accounts of $319 and $288 at December 31, 2003 and June 30, 2004, respectively)		19,615			22,105
Other accounts receivable		14,579			46,372
Affiliate accounts receivable		9,324			8,465
Inventory		17,588			15,007
Acquisition prepayment		—			24,622
Other current assets		3,941			9,215

Total current assets		184,627			183,591
Property, plant and equipment, at cost		1,371,847			1,414,892
Less: accumulated depreciation		431,298			446,977

Net property, plant and equipment		940,549			967,915
Equity investment		—			25,300
Goodwill		22,057			22,006
Other intangibles (less accumulated amortization of $911 and $1,561 at December 31, 2003 and June 30, 2004, respectively)		11,417			10,766
Long-term affiliate receivables		13,472			6,999
Long-term receivables		9,077			19,226
Debt placement costs (less accumulated amortization of $2,761 and $2,419 at December 31, 2003 and June 30, 2004, respectively)		10,618			10,333
Other noncurrent assets		3,113			2,544

Total assets	$	1,194,930		$	1,248,680

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	21,200		$	16,606
Affiliate accounts payable		257			2,237
Outstanding checks		6,961			1,865
Accrued affiliate payroll and benefits		15,077			10,140
Accrued taxes other than income		14,286			14,954
Accrued interest payable		8,196			6,941
Environmental liabilities		12,243			35,567
Deferred revenue		10,868			10,093
Accrued product purchases		11,585			6,575
Current portion of long-term debt		900			—
Other current liabilities		5,616			8,352

Total current liabilities		107,189			113,330
Long-term debt		569,100			551,690
Long-term affiliate payable		1,509			3,215
Other deferred liabilities		4,455			4,257
Environmental liabilities		14,528			28,946
Commitments and contingencies
Partners’ capital:
Partners’ capital		498,920			542,837
Accumulated other comprehensive (loss) income		(771	)		4,405

Total partners’ capital		498,149			547,242

Total liabilities and partners’ capital	$	1,194,930		$	1,248,680

See notes to consolidated financial statements.

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Six Months Ended June 30,
	2003			2004
Operating Activities:
Net income	$	47,917		$	44,272
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		18,262			19,344
Debt placement fee amortization		1,309			1,338
Write-off of unamortized debt placement fees		—			5,002
Loss on sale and retirement of assets		1,971			1,746
Earnings in equity investment		—			(268	)
Debt prepayment premium		—			12,666
Gain on derivative		—			(953	)
Changes in components of operating assets and liabilities:
Accounts receivable and other accounts receivable		(3,836	)		(34,081	)
Affiliate accounts receivable		2,728			859
Inventory		144			2,581
Accounts payable		1,049			(4,594	)
Affiliate accounts payable		(9,688	)		1,980
Accrued affiliate payroll and benefits		4,088			(4,603	)
Accrued taxes other than income		(836	)		668
Accrued interest payable		3,752			(1,255	)
Accrued product purchases		1,823			(5,010	)
Restricted cash		(3,317	)		2,369
Current and noncurrent environmental liabilities		(1,207	)		33,927
Other current and noncurrent assets and liabilities		(9,304	)		(10,157	)

Net cash provided by operating activities		54,855			65,831

Investing Activities:
Additions to property, plant and equipment		(9,835	)		(19,721	)
Proceeds from sale of assets		355			1,171
Acquisition of businesses		—			(25,441	)
Equity investment		—			(25,032	)
Acquisition prepayment		—			(24,622	)

Net cash used by investing activities		(9,480	)		(93,645	)
Financing Activities:
Distributions paid		(42,975	)		(52,695	)
Capital contributions by affiliate		3,912			6,837
Payments on credit facility		—			(90,000	)
Borrowings under long-term notes, net of discount		—			249,485
Payments on long-term notes		—			(178,000	)
Debt placement costs		(313	)		(6,055	)
Issuance of common units, net		—			45,430
Payment of debt prepayment premium		—			(12,666	)
Receipts on interest rate derivatives		—			6,072

Net cash used by financing activities		(39,376	)		(31,592	)

Change in cash and cash equivalents		5,999			(59,406	)
Cash and cash equivalents at beginning of period		75,151			111,357

Cash and cash equivalents at end of period	$	81,150		$	51,951

Supplemental non-cash investing transactions:
Contribution by affiliate of property, plant and equipment	$	23,161		$	—

See notes to consolidated financial statements.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. Organization and Basis of Presentation

Unless indicated otherwise, the terms “our”, “we”, “us” and similar language refer to Magellan Midstream Partners, L.P., together with our subsidiaries. We are a Delaware master limited partnership formed in August 2000 as Williams Energy Partners L.P. and renamed Magellan Midstream Partners, L.P. effective September 1, 2003. Magellan GP, LLC (the “General Partner”), a Delaware limited liability company, serves as our general partner and owns a 2% general partner interest. The General Partner is a wholly-owned subsidiary of Magellan Midstream Holdings, L.P. (“MMH”), a Delaware limited partnership owned by Madison Dearborn Capital Partners IV, L.P. and Carlyle/Riverstone MLP Holdings, L.P. The General Partner has contracted with MMH to perform all of our management and operating functions.

We operate and report in three business segments: the petroleum products pipeline system, the petroleum products terminals and the ammonia pipeline system. Our reportable segments offer different products and services and are managed separately because each requires different business strategies.

In the opinion of management, the accompanying consolidated financial statements of Magellan Midstream Partners, L.P., which are unaudited except for the consolidated balance sheet as of December 31, 2003, which is derived from audited financial statements, include all normal and recurring adjustments necessary to present fairly our financial position as of June 30, 2004, the results of operations for the three month and six month periods ended June 30, 2004 and 2003 and cash flows for the six month periods ended June 30, 2004 and 2003. The results of operations for the three and six months ended June 30, 2004 are not necessarily indicative of the results to be expected for the full year ending December 31, 2004. Certain amounts in the 2003 financial statements have been reclassified to conform to the current period’s presentation.

Pursuant to the rules and regulations of the Securities and Exchange Commission, the financial statements do not include all of the information and notes normally included with financial statements prepared in accordance with accounting principles generally accepted in the United States. These financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2003.

2. Debt and Equity Offerings

During May 2004, we executed a refinancing plan to improve our credit profile and increase our financial flexibility by removing all of the secured debt from our capital structure. This refinancing plan included the issuance of $250.0 million of senior notes, establishment of a new revolving credit facility and the offering of 1.0 million common units representing limited partner interests in us. Both the senior notes and common units were issued on May 25, 2004. Associated with this offering, MMH sold approximately 2.4 million common units that they were holding as an investment in us. MMH’s sale of these common units, combined with our equity offering, reduced MMH’s percentage ownership interest in us from 36% to 27%, including MMH’s 2% ownership interest of the general partner.

Total proceeds from our 1.0 million common unit equity offering at a price of $47.60 per unit were $47.6 million. Associated with this offering, the General Partner contributed $1.0 million to us to maintain its 2% general partner interest. Of the proceeds received, $2.0 million was used to pay underwriting discounts and commissions. Legal, professional and other costs associated with the equity offering were approximately $0.2 million. Total proceeds from the note issuance were $249.5 million. Of these proceeds received, $1.8 million was used to pay underwriting discounts and commissions and $1.0 million of legal, professional and other fees were incurred.

We used the net proceeds from both offerings of $293.1 million as follows:

•

repaid all of the outstanding $178.0 million principal amount of Series A senior notes (see Note 12 - Debt for a description of these notes) issued by Magellan Pipeline Company, LLC (“Magellan Pipeline”);

•

paid $12.7 million of prepayment premiums associated with the early repayment of the Series A senior notes;

•

repaid the $90.0 million outstanding principal balance of our then existing term loan;

•

paid $1.9 million to Magellan Pipeline’s Series B noteholders (see Note 12 - Debt for a description of these notes) to release the collateral held by them and $0.7 million of associated legal costs;

•

incurred $0.6 million of legal and professional fees associated with establishing a new revolving credit facility (see Note 12 for a description of this facility); and

•

partially replenished the cash used to fund our recent acquisitions.

In conjunction with the repayment of the Series A Magellan Pipeline notes and the term loan, we recognized $5.0 million of expense in the current quarter associated with the write-off of the unamortized debt placement costs.

3. Derivative Financial Instruments

We use interest rate derivatives to help us manage interest rate risk. In conjunction with our existing and anticipated debt instruments, we recently executed the following derivative transactions:

Hedges Against Interest Rate Increases on the Anticipated Refinancing of the Magellan Pipeline Notes

In February 2004, we entered into three separate interest rate swap agreements to hedge our exposure against interest rate increases for a portion of the debt we anticipated refinancing related to Magellan Pipeline’s Series A and Series B notes (see Note 12 – Debt). The notional amounts of the swaps totaled $150.0 million. The 10-year period of the swap agreements was the assumed tenure of the replacement debt starting in October 2007. The average fixed rate on the swap agreements was 5.9%.

Hedges Against Interest Rate Increases on a Portion of the Magellan Notes Issued in May 2004

In April 2004, we entered into three agreements for treasury lock transactions to hedge our exposure against interest rate increases for a portion of the $250.0 million of 10-year notes we issued in connection with our May 2004 refinancing plan. The notional amount of the agreements totaled $150.0 million and extended from 2004 to 2014 at a weighted average interest rate of 4.4%.

Impact of Unwinding the Above-Noted Hedges

During May 2004 we unwound the interest rate swap agreements described above and realized a gain of $3.2 million. We also unwound the treasury lock transactions described above in May 2004 and realized a gain of $2.9 million. Because the interest rate swap hedges were considered to be effective, all of the realized gain associated with the interest rate swaps was recorded to other comprehensive income and is being amortized over the 10-year life of the notes issued during May 2004. Because the combined notional amounts of the interest rate swap agreements and the treasury locks exceeded the total amount of debt issued, a portion of the treasury lock hedge was ineffective. As such, the portion of the realized gain associated with the ineffective portion of this hedge, or $1.0 million, was recorded as a gain on derivative during May 2004. The remainder of the realized gain, $1.9 million, was recorded to other comprehensive income and is being amortized over the 10-year life of the notes issued during May 2004.

Interest Rate Swaps and Fair Value Hedges on a Portion of the Magellan Pipeline Notes

During May 2004, we entered into four separate interest rate swap agreements to hedge against changes in the fair value of a portion of the Magellan Pipeline Series B notes. We have accounted for these interest rate hedges as fair value hedges. The notional amounts of the interest rate swap agreements total $250.0 million. Under the terms of the interest rate swap agreements, we will receive 7.7% (the weighted average interest rate of the Magellan Pipeline Series B notes) and will pay LIBOR plus 3.4%. These hedges effectively convert $250.0 million of our fixed-rate debt to floating-rate debt. The interest rate swap agreements began on May 25, 2004 and expire on October 7, 2007, the due date of the Magellan Pipeline Series B notes. Payments settle in April and October each year with the LIBOR interest rate set in arrears. During each settlement period we will record the impact of this

swap based on our best estimate of the LIBOR rate. Any differences between the actual LIBOR rate determined on the settlement date and our estimated LIBOR rates will result in an adjustment to our previously reported interest expense. A change of 1.0% in the LIBOR rates would result in a semi-annual adjustment to our interest expense of $1.3 million.

We generally report gains, losses and any ineffectiveness from interest rate derivatives in our results of operations separately; however, in accordance with Financial Accounting Standards Board Statement No. 133, as amended, as of June 30, 2004 the $0.2 million unrealized gain on the swap agreements discussed above was recorded in other assets and as an increase in long-term debt on the balance sheet.

4. Acquisitions

During the six months ended June 30, 2004, we completed two acquisitions, which are described below. The petroleum products terminals acquisition 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 Osage Pipeline acquisition was accounted for as an equity investment. The results of operations from the petroleum products terminals acquisition have been included with the petroleum products terminals segment results and the equity earnings from the Osage Pipeline acquisition have been included in the petroleum products pipeline system segment results since their respective acquisition dates.

Petroleum Products Terminals

On January 29, 2004, we acquired ownership in 14 petroleum products terminals located in the southeastern United States. We paid $24.8 million for these facilities, incurred $0.6 million of closing costs and assumed $3.8 million of environmental liabilities. We previously owned a 79% interest in eight of these terminals and purchased the remaining ownership interest from Murphy Oil USA, Inc. In addition, the acquisition included sole ownership of six terminals that were previously jointly owned by Murphy Oil USA, Inc. and Colonial Pipeline Company. The allocation of the purchase price to assets acquired and liabilities assumed was as follows (in thousands):


Purchase price:
Cash paid, including transaction costs	$	25,441
Liabilities assumed		3,815

Total purchase price	$	29,256

Allocation of purchase price:
Property, plant and equipment	$	29,256

Osage Pipeline

On March 2, 2004, we acquired a 50% ownership in Osage Pipe Line Company, LLC (“OPL”) for $25.0 million from National Cooperative Refining Association (“NCRA”). The 135-mile Osage pipeline transports crude oil from Cushing, Oklahoma to El Dorado, Kansas and has connections to the NCRA refinery in McPherson, Kansas and the Frontier refinery in El Dorado, Kansas. The remaining 50% interest in OPL is owned by NCRA. Our investment in OPL included an excess net investment amount of $21.7 million. Excess investment is the amount by which our initial investment exceeded the proportionate share of the book value of the net assets of the investment. We determined that there was no equity method goodwill included in the excess investment. Hence, all of the excess investment is being amortized based on a purchase price allocation which reflects the partial step-up in values of OPL’s assets and liabilities.

Pro Forma Information

The following summarized pro forma consolidated income statement information for the three and six months ended June 30, 2003 and for the six months ended June 30, 2004, assumes that all of the acquisitions discussed above had occurred as of January 1, 2003. We have prepared these pro forma financial results for comparative purposes only. These pro forma financial results may not be indicative of the results that would have occurred if we had completed these acquisitions as of the periods shown below or the results that will be attained in the future. The amounts presented below are in thousands, except per unit amounts:


	Three Months Ended June 30, 2003
	As Reported		Pro Forma Adjustments		Pro Forma
Revenues	$	107,925	$	1,830	$	109,755
Net income	$	18,859	$	912	$	19,771
Basic net income per limited partner unit	$	0.75	$	0.03	$	0.78
Diluted net income per limited partner unit	$	0.75	$	0.03	$	0.78

Weighted average number of limited partner units used for basic net income per unit calculation		27,190		27,190		27,190
Weighted average number of limited partner units used for diluted net income per unit calculation		27,190		27,190		27,190


	Six Months Ended June 30, 2003						Six Months Ended June 30, 2004
	As Reported		Pro Forma Adjustments		Pro Forma		As Reported		Pro Forma Adjustments		Pro Forma
Revenues	$	227,640	$	3,669	$	231,309	$	275,364	$	633	$	275,997
Net income	$	47,917	$	1,843	$	49,760	$	44,272	$	322	$	44,594
Basic net income per limited partner unit	$	1.75	$	0.06	$	1.81	$	1.50	$	0.01	$	1.51
Diluted net income per limited partner unit	$	1.74	$	0.06	$	1.80	$	1.50	$	0.01	$	1.51

Weighted average number of limited partner units used for basic net income per unit calculation		27,190		27,190		27,190		27,595		27,595		27,595
Weighted average number of limited partner units used for diluted net income per unit calculation		27,254		27,254		27,254		27,649		27,649		27,649

Significant pro forma adjustments include: revenues and expenses for the period prior to our acquisitions, incremental general and administrative expenses, excess equity investment amortization and the elimination of income taxes.

Announced Acquisition

On June 24, 2004, we announced our agreement to acquire more than 2,000 miles of refined petroleum products pipeline systems from Shell Pipeline Company LP and Equilon Enterprises LLC whose operations are conducted under the name Shell Oil Products US (collectively “Shell”) for $492.4 million. We expect to close the acquisition in September 2004, subject to customary due diligence and regulatory approval. In addition to the purchase price, we will pay approximately $12.0 million for net working capital, which includes approximately $26.0 million of inventory offset by $14.0 million of escrow cash, assume approximately $12.5 million in existing liabilities and incur approximately $9.5 million of transaction costs. Management expects to finance the acquisition initially with cash on hand and short-term bank borrowings and to finance the acquisition permanently with issuances of common units and long-term debt securities. Management is evaluating the appropriate timing of the equity and debt issuances associated with this acquisition. During June 2004, we paid Shell $24.6 million as earnest money associated with the acquisition, which will be applied against the purchase price at closing.

5. Allocation of Net Income

The allocation of net income between the General Partner and limited partners is as follows (in thousands):


	Three Months Ended June 30,						Six Months Ended June 30,
	2003			2004			2003			2004
Allocation of net income to General Partner:
Net income	$	18,859		$	18,457		$	47,917		$	44,272
Charges/(income) direct to General Partner:
General and administrative portion of paid-time-off accrual		1,363			—			1,363			—
Write-off of property, plant and equipment		1,788			—			1,788			—
Charges in excess of the general and administrative expense cap charged against income		247			2,425			247			3,562
Other		—			(367	)		—			261

Total direct charges to General Partner		3,398			2,058			3,398			3,823

Income before direct charges to General Partner		22,257			20,515			51,315			48,095
General Partner’s share of distributions		7.90	%		14.87	%		7.42	%		14.05	%

General Partner’s allocated share of net income before direct charges		1,759			3,050			3,809			6,756
Direct charges to General Partner		3,398			2,058			3,398			3,823

Net income (loss) allocated to General Partner	$	(1,639	)	$	992		$	411		$	2,933

Net income	$	18,859		$	18,457		$	47,917		$	44,272
Less: net income (loss) allocated to General Partner		(1,639	)		992			411			2,933

Net income allocated to limited partners	$	20,498		$	17,465		$	47,506		$	41,339

On June 17, 2003, The Williams Companies, Inc. (“Williams”) sold all of the limited partner units it owned in us and its membership interests in our general partner to MMH. The transition charges shown above represent costs for transitioning our partnership from Williams in excess of the amount we are contractually required to pay. We have recorded these excess transition costs as a capital contribution by our general partner. The write-off of property, plant and equipment relates to Magellan Pipeline’s asset balances prior to our acquisition of it; hence, these write-offs were charged directly against the General Partner’s allocation of net income. The general and administrative portion of paid-time-off expense accrual and the charges in excess of the general and administrative expense cap represent general and administrative expenses charged against our income during the periods presented that were required to be reimbursed to us by our general partner under the terms of the new omnibus agreement. Consequently, these amounts have been charged directly against the General Partner’s allocation of net income. We record these reimbursements by our general partner as a capital contribution

6. Comprehensive Income

For the three and six months ended June 30, 2003 and 2004, the difference between our net income and comprehensive income was the gain on interest rate swaps and treasury locks and the amortization of the gains/losses on derivative transactions accounted for as cash flow hedges. For information relative to the interest rate swaps and treasury locks, see Note 3 – Derivative Financial Instruments. During September 2002, in anticipation of a new debt placement to replace the short-term debt assumed to acquire Magellan Pipeline, we entered into an interest rate hedge. The effect of this interest rate hedge was to set the coupon rate on a portion of the fixed-rate debt prior to actual execution of the debt agreement. The loss on the hedge, approximately $1.0 million, was recorded in accumulated other comprehensive loss and is being amortized over the five-year life of the fixed-rate debt borrowed during October 2002. Our comprehensive income is as follows (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,
	2003		2004		2003		2004
Net income	$	18,859	$	18,457	$	47,917	$	44,272
Gain on interest rate swaps		—		6,606		—		3,212
Gain on effective portion of treasury locks		—		1,907		—		1,907
Amortization of cash flow hedges		50		7		100		57

Other comprehensive income		50		8,520		100		5,176

Comprehensive income	$	18,909	$	26,977	$	48,017	$	49,448

7. Segment Disclosures

Our reportable segments are strategic business units that offer different products and services. The segments are managed separately because each segment requires different marketing strategies and business knowledge.

Management evaluates performance based upon segment operating margin, which includes revenues from affiliate and external customers, operating expenses, environmental expenses, environmental reimbursements and product purchases.

On June 17, 2003, Williams sold its interest in us to MMH. Prior to June 17, 2003, affiliate revenues from Williams were accounted for as if the sales were to unaffiliated third parties. We have not had affiliate revenues since Williams’ sale of its interest in us to MMH on June 17, 2003. Also, prior to June 17, 2003, affiliate general and administrative costs, other than equity-based incentive compensation, were based on the expense limitations provided for in the omnibus agreement and were allocated to the business segments based on their proportional percentage of revenues. After June 17, 2003, affiliate general and administrative costs have generally been allocated to the business segments based on a three-factor formula which considers total salaries, property, plant and equipment and operating revenues less product purchases.

The non-generally accepted accounting principle measure of operating margin (in the aggregate and by segment) is presented in the following tables. The components of operating margin are computed by using amounts that are determined in accordance with generally accepted accounting principles (“GAAP”). A reconciliation of operating margin to operating profit, which is its nearest comparable GAAP financial measure, is included in the tables below. Management believes that investors benefit from having access to the same financial measures they use to evaluate performance. Operating margin is an important performance measure of the economic performance of our core operations. This measure forms the basis of our internal financial reporting and is used by management in deciding how to allocate capital resources between segments. Operating profit, alternatively, includes expense items that management does not consider when evaluating the core profitability of an operation such as depreciation and general and administrative costs.


	Three Months Ended June 30, 2003
	(in thousands)
	Petroleum Products Pipeline System		Petroleum Products Terminals			Ammonia Pipeline System			Inter- segment Elimin- ations		Total
Revenues:
Third party	$	79,445	$	19,398		$	3,474		$	—	$	102,317
Affiliate		4,657		951			—			—		5,608

Total revenues		84,102		20,349			3,474			—		107,925
Operating expenses		32,120		9,151			1,079			—		42,350
Environmental		13		(102	)		243			—		154
Environmental reimbursements		—		132			(204	)		—		(72	)
Product purchases		11,588		445			—			—		12,033

Operating margin		40,381		10,723			2,356			—		53,460
Depreciation and amortization		5,693		2,949			241			—		8,883
Affiliate general and administrative expenses		11,487		4,585			413			—		16,485

Segment profit	$	23,201	$	3,189		$	1,702		$	—	$	28,092


	Three Months Ended June 30, 2004
	(in thousands)
	Petroleum Products Pipeline System			Petroleum Products Terminals			Ammonia Pipeline System			Inter- segment Elimin- ations			Total
Revenues	$	113,957		$	25,431		$	2,985		$	(153	)	$	142,220
Operating expenses		33,557			8,996			1,304			(946	)		42,911
Environmental		14,549			2,689			885			—			18,123
Environmental reimbursements		(14,469	)		(2,689	)		(751	)		—			(17,909	)
Product purchases		31,083			1,299			—			—			32,382
Equity earnings		(148	)		—			—			—			(148	)

Operating margin		49,385			15,136			1,547			793			66,861
Depreciation and amortization		5,536			3,291			202			793			9,822
Affiliate general and administrative expenses		9,358			3,551			598			—			13,507

Segment profit	$	34,491		$	8,294		$	747		$	—		$	43,532


	Six Months Ended June 30, 2003
	(in thousands)
	Petroleum Products Pipeline System			Petroleum Products Terminals			Ammonia Pipeline System			Inter- segment Elimin- ations		Total
Revenues:
Third party	$	170,064		$	38,579		$	5,085		$	—	$	213,728
Affiliate		7,906			6,006			—			—		13,912

Total revenues		177,970			44,585			5,085			—		227,640
Operating expenses		56,662			16,828			2,219			—		75,709
Environmental		1,810			(102	)		243			—		1,951
Environmental reimbursements		(1,099	)		132			(291	)		—		(1,258	)
Product purchases		39,014			837			—			—		39,851

Operating margin		81,583			26,890			2,914			—		111,387
Depreciation and amortization		11,337			5,877			1,048			—		18,262
Affiliate general and administrative expenses		19,828			6,471			624			—		26,923

Segment profit	$	50,418		$	14,542		$	1,242		$	—	$	66,202


	Six Months Ended June 30, 2004
	(in thousands)
	Petroleum Products Pipeline System			Petroleum Products Terminals			Ammonia Pipeline System			Inter- segment Elimin- ations			Total
Revenues	$	220,778		$	48,295		$	6,585		$	(294	)	$	275,364
Operating expenses		62,013			17,355			2,285			(1,742	)		79,911
Environmental		38,437			2,839			1,052			—			42,328
Environmental reimbursements		(37,573	)		(2,839	)		(912	)		—			(41,324	)
Product purchases		68,458			2,423			—			—			70,881
Equity earnings		(268	)		—			—			—			(268	)

Operating margin		89,711			28,517			4,160			1,448			123,836
Depreciation and amortization		11,042			6,449			405			1,448			19,344
Affiliate general and administrative expenses		18,371			6,843			1,180			—			26,394

Segment profit	$	60,298		$	15,225		$	2,575		$	—		$	78,098

Segment assets	$	687,079		$	391,065		$	27,018			—		$	1,105,162
Corporate assets														143,518

Total assets													$	1,248,680

8. Inventories

Inventories at December 31, 2003 and June 30, 2004 were as follows (in thousands):


	December 31, 2003		June 30, 2004
	December 31, 2003		June 30, 2004
Refined petroleum products	$	3,741	$	164
Natural gas liquids		12,362		13,338
Additives		977		997
Other		508		508

Total inventories	$	17,588	$	15,007

9. Equity Investment

Effective March 2, 2004, we acquired a 50% ownership in OPL, which owns the Osage pipeline. The remaining 50% interest is owned by NCRA. The 135-mile Osage pipeline transports crude oil from Cushing, Oklahoma to El Dorado, Kansas and has connections to the NCRA refinery in McPherson, Kansas and the Frontier refinery in El Dorado, Kansas. Our agreement with NCRA calls for equal sharing of OPL’s net income.

We use the equity method of accounting for this investment. Summarized financial information for OPL from the acquisition date (March 2, 2004) through June 30, 2004 is presented below (in thousands):


Revenues	$	3,320
Net income	$	978

The condensed balance sheet for OPL as of June 30, 2004 is presented below (in thousands):


Current assets	$	3,147
Noncurrent assets	$	5,274
Current liabilities	$	720
Members’ equity	$	7,701

A summary of our equity investment in OPL is as follows (in thousands):


Initial investment	$	25,032
Earnings in equity investment:
Proportionate share of Osage earnings		489
Amortization of excess investment		(221	)

Net earnings in equity investment		268

Equity investment, June 30, 2004	$	25,300

Our investment in OPL included an excess net investment amount of $21.7 million. Excess investment is the amount by which our initial investment exceeded our proportionate share of the book value of the net assets of the investment. Amortization expense associated with the excess investment during the second quarter of 2004 was $0.2 million.

10. Related Party Transactions

Affiliate revenues historically represented revenues from Williams and its affiliates. We have not had affiliate revenues since Williams’ sale of its interest in us to MMH on June 17, 2003. The following paragraphs describe the affiliate relationships we had with Williams and its affiliates prior to June 17, 2003.

We had agreements with Williams Energy Marketing & Trading, LLC (“WEM&T”) which provided for: (i) the lease of a Carthage, Missouri propane storage cavern and (ii) access and utilization of storage on the Magellan Pipeline system. Magellan Pipeline had also entered into tank storage agreements with Williams Bio-Energy, LLC (“Williams Bio-Energy”) which was an affiliate entity until its sale by Williams in May 2003. We also had a lease storage contract with Williams Bio-Energy at our Galena Park, Texas marine terminal facility.

In addition, we had an agreement with WEM&T that provided for storage and other ancillary services at our marine terminal facilities. This agreement was cancelled during the first quarter of 2003 in exchange for a $3.0 million payment from WEM&T. Both WEM&T and Williams Refining & Marketing had agreements for the access and utilization of the inland terminals.

We also had an agreement with Williams Petroleum Services, LLC whereby we performed services related to petroleum products asset management activities for an annual fee in 2003 of approximately $4.0 million. In July 2003, we acquired the rights to these activities from Williams and its affiliates.

We also had affiliate agreements with WEM&T and Williams Refining & Marketing for the non-exclusive and non-transferable sub-license to use the ATLAS 2000 software system. The rights to this system were contributed to us on June 17, 2003.

The following table reflects affiliate revenues for the three and six months ended June 30, 2003 (in thousands):


	Three Months Ended June 30, 2003		Six Months Ended June 30, 2003
	Three Months Ended June 30, 2003		Six Months Ended June 30, 2003
Williams Energy Marketing & Trading	$	2,101	$	7,425
Midstream Marketing & Risk Management		394		598
Williams Refining & Marketing		—		306
Williams Bio-Energy		1,007		2,366
Williams Petroleum Services, LLC		1,881		2,992
Rio Grande Pipeline		225		225

Total	$	5,608	$	13,912

Costs and expenses related to activities between us and Williams and its affiliates after June 17, 2003 have been accounted for as unaffiliated third-party transactions. Transactions between us and MMH and its affiliates have been accounted for as affiliate transactions after June 17, 2003. The following table summarizes costs and expenses from our various affiliate companies and are reflected in the cost and expenses in the accompanying consolidated statements of income (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,
	2003		2004		2003		2004
Williams—allocated general and administrative expenses	$	13,442	$	—	$	23,880	$	—
Williams—allocated operating expenses		34,109		—		68,079		—
Williams Energy Marketing & Trading—product purchases		—		—		472		—
MMH—allocated operating expenses		8,323		14,819		8,323		28,193
MMH—allocated general and administrative expenses		3,043		13,507		3,043		26,394

For the period January 1, 2003 through June 30, 2003, Williams allocated both direct and indirect general and administrative expenses to our general partner. Direct expenses allocated by Williams were primarily salaries and benefits of employees and officers associated with our business activities. Indirect expenses included legal, accounting, treasury, engineering, information technology and other corporate services. Williams allocated these expenses to our general partner based on the expense limitation provided for in an agreement between Williams, our general partner and us. We reimbursed our general partner and its affiliates for expenses charged to us by the General Partner on a monthly basis.

As a result of the sale of Williams’ ownership interests in us, we entered into a new services agreement with MMH pursuant to which MMH agreed to perform specified services required for our operations. Consequently, our operations and general and administrative functions are now provided by MMH. Our reimbursement of general and administrative costs is subject to the limitations as defined in the new omnibus agreement.

In addition, MMH has indemnified us against certain environmental costs (see Note 13 – Commitments and Contingencies for further discussion of this matter). Receivables from MMH associated with this indemnification were $19.0 million and $15.5 million at December 31, 2003 and June 30, 2004, respectively, and are included with the affiliate accounts receivable in the consolidated balance sheets.

11. Employee Benefit Plans

On January 1, 2004, MMH assumed sponsorship of the Magellan Pension Plan for PACE Employees (“Union Pension Plan”) for hourly employees. In addition, MMH began sponsorship of a pension plan for non-union employees and a post-retirement benefit plan for selected employees effective January 1, 2004. The following table presents our recognition of net periodic benefit costs related to these plans during the three and six months ended June 30, 2004 (in thousands):


	Three Months Ended June 30, 2004					Six Months Ended June 30, 2004
	Pension Benefits			Other Post- Retirement Benefits		Pension Benefits			Other Post- Retirement Benefits
Components of Net Periodic Benefit Costs:
Service cost	$	925		$	103	$	1,850		$	206
Interest cost		427			221		854			442
Expected return on plan assets		(409	)		—		(818	)		—
Amortization of prior service cost		112			582		224			1,164

Net periodic benefit cost	$	1,055		$	906	$	2,110		$	1,812

We anticipate contributing a total of $2.6 million to satisfy minimum funding requirements for pension benefits for the 2004 plan year. Through June 30, 2004, a total of $0.6 million had been contributed.

The Medicare Prescription Drug Improvement and Modernization Act of 2003 (the “Act”) was enacted on December 8, 2003. The effect of the Act has not been reflected in the net post-retirement benefit cost disclosed above because MMH has been unable to conclude whether the benefits provided by its plan are actuarially equivalent to Medicare Part D under the Act. At present, detailed regulations necessary to implement the Act have not been issued by the Secretary of Health and Human Services, including those that would specify the manner in which actuarial equivalency must be determined, the evidence required to demonstrate actuarial equivalency and the documentation necessary to be entitled to the subsidy.

12. Debt

A summary of our debt at December 31, 2003 and June 30, 2004 follows (in thousands):


	December 31, 2003		June 30, 2004
Magellan term loan and revolving credit facility:
Long-term portion	$	89,100	$	—
Current portion		900		—

Total		90,000		—
Magellan Pipeline Senior Notes		480,000		302,202
Magellan 6.45% Senior Notes		—		249,488

Total debt	$	570,000	$	551,690

Magellan Pipeline Senior Notes

During October 2002, Magellan Pipeline entered into a private placement debt agreement with a group of financial institutions for $178.0 million of floating rate Series A Senior Secured Notes and $302.0 million of fixed rate Series B Senior Secured Notes. Both notes were secured with our membership interest in and assets of Magellan Pipeline until our refinancing plan was executed in May 2004 (see Note 2 – Debt and Equity Offerings). As part of that refinancing, the $178.0 million outstanding balance of the floating rate Series A Senior Secured Notes was repaid and we incurred $12.7 million of associated prepayment premiums. In addition, in exchange for a $1.9 million payment, the fixed rate Series B noteholders released the collateral which secured those notes except for cash deposited in an escrow account in anticipation of semi-annual interest payments on the Magellan Pipeline notes. The maturity date of the Series B notes is October 7, 2007; however, we will be required on each of October 7, 2005 and October 7, 2006, to repay 5.0% of the principal amount outstanding on those dates. The outstanding principal amount of the Series B notes at June 30, 2004 was $302.0 million; however, this amount was increased by $0.2 million for the change in the fair value of the debt from May 25, 2004 through June 30, 2004 in connection with the associated fair value hedge (see Note 3 – Derivative Financial Instruments). The interest rate of the Series B notes is fixed at 7.8%. Including the impact of the derivative agreement which effectively swaps $250.0 million of fixed-rate debt to floating-rate debt (see Note 3 – Derivative Financial Instruments), the weighted average interest rate for both the Series A and Series B notes was 6.6% for both the three and six months ended June 30, 2004.

We incurred debt placement fees associated with these notes of $10.8 million. During May 2004 we recorded $2.8 million of expense, which represented the write-off of the unamortized debt placement fees associated with the Series A notes. The debt placement fees associated with the Series B notes are being amortized over the life of these notes. Deposits for interest due the lenders are made to a cash escrow account and were reflected as restricted cash on our consolidated balance sheets of $8.2 million and $5.9 million at December 31, 2003 and June 30, 2004, respectively.

The note purchase agreement, as amended in connection with our May 2004 refinancing, requires Magellan Pipeline to maintain specified ratios of: (i) consolidated debt to EBITDA of no greater than 3.50 to 1.00, and (ii) consolidated EBITDA to interest expense of at least 3.25 to 1.00. It also requires us to maintain specified ratios of: (i) consolidated debt to EBITDA of no greater than 4.50 to 1.00, and (ii) consolidated EBITDA to interest expense of at least 2.50 to 1.00. In addition, the note purchase agreement contains additional covenants that limit Magellan Pipeline’s ability to, among other things:

•

incur additional indebtedness;

•

encumber its assets;

•

make debt or equity investments;

•

make loans or advances;

•

engage in certain transactions with affiliates;

•

merge, consolidate, liquidate or dissolve;

•

sell or lease a material portion of its assets;

•

engage in sale and leaseback transactions; and

•

change the nature of its business.

We are in compliance with these covenants.

Magellan Midstream Partners 6.45% Senior Notes

On May 25, 2004, we sold $250.0 million aggregate principal of 6.45% notes due June 1, 2014 in an underwritten public offering. The aggregate principal amount of the notes was $250.0 million; however, the notes were issued for the discounted price of 99.8%, or $249.5 million. Including the impact of the amortization of the realized gains on the interest hedges associated with these notes, the effective interest rate on the notes is 6.3%. Interest is payable on June 1 and December 1 of each year, beginning December 1, 2004. The discount on the notes will be accreted over the life of the notes. We are in compliance with all covenants included in the indenture under which we issued these notes.

The indenture under which the notes were issued does not limit our ability to incur additional unsecured debt. The indenture contains covenants limiting, among other things, our ability to incur indebtedness secured by certain liens, engage in certain sale-leaseback transactions, and consolidate, merge or dispose of all or substantially all of our assets. We are in compliance with all of these covenants.

May 2004 Revolving Credit Facility

In connection with our May 2004 refinancing, we entered into a five-year $125.0 million revolving credit facility with a syndicate of banks. Up to $50.0 million of the revolving credit facility will be available for letters of credit. As of June 30, 2004, $0.7 million of the facility was being used for letters of credit. Borrowings under this revolving credit facility will be unsecured and bear interest at LIBOR plus a spread ranging from 0.6% to 1.5%.

The revolving credit facility requires us to maintain specified ratios of: (i) consolidated debt to EBITDA of no greater than 4.50 to 1.00; and (ii) consolidated EBITDA to interest expense of at least 2.50 to 1.00. In addition, the revolving credit facility contains covenants that limit our ability to, among other things:

•

incur additional indebtedness or modify our other debt instruments;

•

encumber our assets;

•

make debt or equity investments;

•

make loans or advances;

•

engage in certain transactions with affiliates;

•

engage in sale and leaseback transactions;

•

merge, consolidate, liquidate or dissolve;

•

sell or lease all or substantially all of our assets; and

•

change the nature of our business.

We are in compliance with these covenants.

Magellan term loan and revolving credit facility

In August 2003, we entered into a credit agreement with a syndicate of banks. This facility was comprised of a $90.0 million term loan and an $85.0 million revolving credit facility. Indebtedness under the term loan incurred interest at the Eurodollar rate plus a margin of 2.0%, while indebtedness under the revolving credit facility incurred interest at the Eurodollar rate plus a margin of 1.8%. We also incurred a commitment fee on the un-drawn portion of the revolving credit facility. In May 2004 we repaid the $90.0 million outstanding term loan and this facility was replaced with the new revolving credit agreement described above. During May 2004 we recorded $2.2 million of expense, which represented the write-off of the unamortized debt placement fees associated with this facility.

13. Commitments and Contingencies

Prior to May 27, 2004, we had three separate indemnification agreements with Williams. These three agreements are described below:

IPO Indemnity Agreement - Williams and certain of its affiliates indemnified us for covered environmental losses up to $15.0 million related to assets operated by us at the time of our initial public offering date (February 9, 2001) that become known by August 9, 2004 and that exceed amounts recovered or recoverable under our contractual indemnities from third persons or under any applicable insurance policies. We refer to this indemnity as the “IPO Indemnity”. Covered environmental losses included those non-contingent terminal and ammonia system environmental losses, costs, damages and expenses suffered or incurred by us arising from correction of violations or performance of remediation required by environmental laws in effect at February 9, 2001, due to events and conditions associated with the operation of the assets and occurring before February 9, 2001. In addition, Williams and certain of its affiliates indemnified us for right-of-way defects or failures in the ammonia pipeline easements for 15 years after February 9, 2001. Williams and certain of its affiliates also indemnified us for right-of-way defects or failures associated with the marine facilities at Galena Park and Corpus Christi, Texas and Marrero, Louisiana for 15 years after February 9, 2001.

Magellan Pipeline Indemnity Agreement - In conjunction with the acquisition of Magellan Pipeline in April 2002, Williams agreed to indemnify us for any breaches of representations or warranties, environmental liabilities and failures to comply with environmental laws as described below. Williams’ liability under this indemnity was capped at $125.0 million. We refer to this indemnity as the “Magellan Pipeline Indemnity”. In addition to environmental liabilities, this indemnity included matters relating to employees and employee benefits and real property, including asset titles. Also, this indemnity provided that we were indemnified for an unlimited amount of losses and damages related to tax liabilities. The environmental liability indemnity included any losses and damages related to environmental liabilities caused by events that occurred prior to the acquisition. Covered environmental losses include those losses arising from the correction of violations of, or performance of remediation required by, environmental laws in effect at April 11, 2002.

Acquisition Indemnity Agreement - In addition to these two agreements, the purchase and sale agreement (“June 2003 Agreement”) entered into in connection with MMH’s acquisition of Williams’ partnership interest provided us with two additional indemnities related to environmental liabilities, which we collectively refer to as the “Acquisition Indemnity”.

First, MMH (the buyer under the June 2003 Agreement) assumed Williams’ obligations to indemnify us for $21.9 million of known environmental liabilities.

Second, in the June 2003 Agreement, Williams agreed to indemnify us for certain environmental liabilities arising prior to June 17, 2003 related to all of our facilities to the extent not already indemnified under the IPO Indemnity and Magellan Pipeline Indemnity agreements described above. This additional indemnification included those liabilities related to the petroleum products terminals and the ammonia pipeline system arising after the initial public offering (February 9, 2001) through June 17, 2003 and those liabilities related to Magellan Pipeline arising after our acquisition of it on April 11, 2002 through June 17, 2003. This indemnification covers environmental as well as other liabilities.

Indemnification Settlement - In May 2004, our general partner entered into an agreement with Williams under which Williams agreed to pay us $117.5 million to release Williams from the environmental indemnifications and certain other indemnifications described under the IPO Indemnity, Magellan Pipeline Indemnity and Acquisition Indemnity agreements described above.

We received $35.0 million from Williams on July 1, 2004 and expect to receive installment payments from Williams of $27.5 million, $20.0 million and $35.0 million on July 1, 2005, 2006 and 2007, respectively. In conjunction with this transaction:

•

We received $2.1 million from Williams during June 2004 in settlement of certain amounts we previously billed to Williams for environmental matters. Following this payment, our receivable balance with Williams for environmental matters was $45.1 million;

•

The $35.0 million amount received in July 2004 will be recorded as a reduction in our receivable with Williams in the third quarter of 2004. Following this payment, our receivable balance with Williams was $10.1 million;

•

When the $27.5 million payment from Williams is received in July 2005, we will record $10.1 million as a reduction in our receivable balance with Williams with the remaining $17.4 million recorded as a capital contribution from our general partner; and

•

The final two installment payments from Williams will be recorded as a capital contribution from our general partner when the cash amounts have been received from Williams.

While the settlement agreement releases Williams from its environmental and certain other indemnifications, certain indemnifications remain in effect. These remaining indemnifications cover:

•

Right-of-way defects or failures in the ammonia pipeline easements for 15 years after February 9, 2001, and right-of-way defects or failures associated with the marine facilities at Galena Park and Corpus Christi, Texas and Marrero, Louisiana for 15 years after February 9, 2001;

•

Issues involving employee and employee benefits matters;

•

Issues involving real property, including asset titles; and

•

Unlimited losses and damages related to tax liabilities.

Environmental Liabilities - Estimated liabilities for environmental costs were$26.8 million and $64.5 million at December 31, 2003 and June 30, 2004, respectively. These estimates are provided on an undiscounted basis and have been classified as current or non-current based on management’s estimates regarding the timing of actual payments. Management estimates that expenditures associated with these environmental remediation liabilities will be paid over the next ten years.

Environmental Receivables - As part of its negotiations with Williams for the June 2003 acquisition of Williams’ interest in us, MMH assumed Williams’ obligations for $21.9 million of environmental liabilities and we recorded a receivable from MMH for this amount. To the extent the environmental and other Williams indemnity claims against MMH are less than $21.9 million, MMH will pay to Williams the remaining difference between $21.9 million and the indemnity claims paid by MMH. Environmental receivables from MMH at December 31, 2003 and June 30, 2004 were $19.0 million and $15.5 million, respectively. Environmental receivables from insurance carriers were $3.1 million and $7.5 million at December 31, 2003 and June 30, 2004, respectively. We invoice MMH and third-party insurance companies for reimbursement as environmental remediation work is performed. Receivables from Williams or its affiliates associated with indemnified environmental costs were $7.8 million at December 31, 2003.

Other Indemnifications - In conjunction with the 1999 acquisition of the Gulf Coast marine terminals from Amerada Hess Corporation (“Hess”), Hess represented that it had disclosed to us all suits, actions, claims, arbitrations, administrative, governmental investigation or other legal proceedings pending or threatened, against or related to the assets we acquired, which arise under environmental law. In the event that any pre-acquisition releases of hazardous substances at the Corpus Christi and Galena Park, Texas and Marrero, Louisiana marine terminal facilities were unknown at closing but subsequently identified by us prior to July 30, 2004, we will be liable for the first $2.5 million of environmental liabilities, Hess will be liable for the next $12.5 million of losses and we will assume responsibility for any losses in excess of $15.0 million. Also, Hess agreed to indemnify us through July 30, 2014 against all known and required environmental remediation costs at the Corpus Christi and Galena Park, Texas marine terminal facilities from any matters related to pre-acquisition actions. Hess has indemnified us for certain pre-acquisition fines and claims that may be imposed or asserted against us under certain environmental laws.

EPA Issue - In July 2001, the Environmental Protection Agency (“EPA”), pursuant to Section 308 of the Clean Water Act (the “Act”) served an information request to Williams based on a preliminary determination that Williams may have systemic problems with petroleum discharges from pipeline operations. That inquiry primarily focused on Magellan Pipeline. The response to the EPA’s information request was submitted during November 2001. In March 2004, we received an additional information request from the EPA and notice from the U.S. Department of Justice (“DOJ”) that the EPA had requested the DOJ to initiate a lawsuit alleging violations of Section 311(b) of the Act in regards to 32 releases. The DOJ stated that the maximum statutory penalty for the releases was in excess of $22.0 million. This assumes that all releases are violations of the Act and that the EPA would impose the maximum penalty. The EPA further indicated that some of those spills may have also violated the Spill Prevention Control and Countermeasure requirements of Section 311(j) of the Act and that additional penalties may be assessed. In addition, we may incur additional costs associated with these spills if the EPA were to successfully seek and obtain injunctive relief. We have verbally agreed to a response schedule for the 32 releases and are submitting responses in accordance to that schedule. We have met with the EPA and the DOJ and anticipate negotiating a final settlement with both agencies during the next twelve months. We have evaluated this issue and have accrued an amount based on our best estimates that is less than $22.0 million. This liability was covered under the environmental indemnification settlement with Williams in May 2004.

Shawnee, Kansas Spill - During the fourth quarter of 2003, we experienced a line break and product spill on our petroleum products pipeline near Shawnee, Kansas. As of June 30, 2004, we estimated the total costs associated with this spill to be $9.2 million. We have spent $7.4 million on remediation at this site, leaving a remaining liability on our balance sheet at June 30, 2004 of $1.8 million. At June 30, 2004, we had recorded a receivable from our insurance carrier of $7.5 million related to this spill.

Other – We are a party to various other claims, legal actions and complaints arising in the ordinary course of business. In the opinion of management, the ultimate resolution of all claims, legal actions and complaints after consideration of amounts accrued, insurance coverage or other indemnification arrangements will not have a material adverse effect upon our future financial position, results of operations or cash flows.

14. Long-Term Incentive Plan

In February 2001, our general partner adopted the Williams Energy Partners’ Long-Term Incentive Plan, which was amended and restated on February 3, 2003, on July 22, 2003, and on February 3, 2004, for employees who perform services for us and for directors and executive officers of our general partner. The Long-Term Incentive Plan consists of two components: phantom units and unit options. The Long-Term Incentive Plan permits the grant of awards covering an aggregate of 700,000 common units. The Compensation Committee of our general partner’s Board of Directors administers the Long-Term Incentive Plan.

In April 2001, our general partner granted 64,200 phantom units pursuant to the Long-Term Incentive Plan. With the change in control of our general partner, which occurred on June 17, 2003, these awards vested at their maximum award level, resulting in 128,400 unit awards. We recognized compensation expense associated with these awards of $2.6 million and $3.4 million during the three and six months ended June 30, 2003, respectively.

During 2002, our general partner granted 22,650 phantom units pursuant to the Long-Term Incentive Plan. With the change in control of our general partner, which occurred on June 17, 2003, these awards vested at their maximum award level, resulting in 45,300 unit awards. We recognized compensation expense associated with these awards of $1.8 million and $2.0 million during the three and six months ended June 30, 2003, respectively.

In February 2003, our general partner granted 52,825 phantom units pursuant to the Long-Term Incentive Plan. The actual number of units that will be awarded under this grant are based on certain performance metrics, which we determined at the end of 2003, and a personal performance component that will be determined at the end of 2005, with vesting to occur at that time. These units are subject to forfeiture if employment is terminated prior to the vesting date. These awards do not have an early vesting feature except under certain circumstances. During 2003, we increased the associated accrual to an expected payout of 95,271 units with further adjustments to the expected unit payouts during 2004 for employee terminations and retirements. Accordingly, we recorded incentive compensation expense of $0.5 million and $0.6 million associated with these phantom awards during the three and six months ended June 30, 2003 and $0.3 million and $0.9 million for the three and six months ended June 30, 2004, respectively. The value of the 94,205 phantom unit awards being accrued was $4.8 million on June 30, 2004.

Following the change in control of our general partner in June 2003 from Williams to MMH, the board of directors of our general partner made the following grants to certain employees who became dedicated to providing services to us:

•

In October 2003, our general partner granted 10,640 phantom units pursuant to the Long-Term Incentive Plan. Of these awards, 4,850 units vested on December 31, 2003 and 470 units vested on July 31, 2004. The remaining units will vest as follows: 4,850 units on December 31, 2004 and 470 units on July 31, 2005. There are no performance metrics associated with these awards and the payouts cannot exceed the face amount of the units awarded. These units are subject to forfeiture if employment is terminated prior to the vesting date. These awards do not have an early vesting feature except under certain circumstances. We recorded less than $0.1 million and $0.1 million of compensation expense associated with these awards during the three and six months ended June 30, 2004, respectively. The value of the 5,790 unvested awards at June 30, 2004 was $0.3 million.

•

On January 2, 2004, our general partner granted 10,856 phantom units pursuant to the Long-Term Incentive Plan. Of these awards, 5,433 units vested on July 31, 2004 and 5,423 units will vest on July 31, 2005. There are no performance metrics associated with these awards and the payouts cannot exceed the face amount of the units awarded. These units are subject to forfeiture if employment is terminated prior to the vesting date. These awards do not have an early vesting feature except under certain circumstances. We recorded $0.2 million and $0.4 million of compensation expense associated with these awards during the three and six months ended June 30, 2004. The value of the awards at June 30, 2004 was $0.6 million.

In February 2004, our general partner granted 79,512 phantom units pursuant to the Long-Term Incentive Plan. The actual number of units that will be awarded under this grant are based on the attainment of short-term and long-term performance metrics. The number of phantom units that could ultimately be issued under this award range from zero units up to a total of 159,024 units; however, the awards are also subject to personal and other performance components which could increase or decrease the number of units to be paid out by as much as 40%. The units will vest at the end of 2006. These units are subject to forfeiture if employment is terminated prior to the vesting date. These awards do not have an early vesting feature except under certain circumstances. We began recognizing compensation expense as though 79,512 units will vest and accordingly recognized $0.3 million and $0.7 million of compensation expense during the three and six months ended June 30, 2004. The value of the 79,512 unit awards on June 30, 2004 was $4.0 million.

A summary of our equity-based incentive compensation costs associated with phantom unit awards for the three and six months ended June 30, 2003 and 2004 is listed below (in thousands). To date, our general partner has not awarded any unit options.


	Three Months Ended June 30,				Six Months Ended June 30,
	2003		2004		2003		2004
Annual 2001 awards	$	2,586	$	—	$	3,373	$	—
Annual 2002 awards		1,837		—		1,955		—
Annual 2003 awards		459		300		556		887
October 2003 awards		—		34		—		113
January 2004 awards		—		213		—		373
Annual 2004 awards		—		310		—		674

Total	$	4,882	$	857	$	5,884	$	2,047

15. Distributions

We paid the following distributions during 2003 and 2004 (in thousands, except per unit amounts):


Cash Distribution Payment Date	Per Unit Cash Distribution Amount		Common Units		Subordinated Units		Class B Common Units		General Partner Equivalent Units		Total Cash Distribution
02/14/03	$	0.7250	$	9,918	$	4,118	$	5,677	$	1,321	$	21,034
05/15/03		0.7500		10,260		4,260		5,873		1,548		21,941
08/14/03		0.7800		10,670		4,430		6,108		1,820		23,028
11/14/03		0.8100		11,081		4,601		6,343		2,499		24,524

Total	$	3.0650	$	41,929	$	17,409	$	24,001	$	7,188	$	90,527


Cash Distribution Payment Date	Per Unit Cash Distribution Amount		Common Units		Subordinated Units		Class B Common Units		General Partner Equivalent Units		Total Cash Distribution
02/13/04	$	0.8300	$	18,020	$	4,714	$	—	$	3,066	$	25,800
05/14/04		0.8500		19,661		3,621		—		3,613		26,895
08/13/04 (a)		0.8700		20,994		3,706		—		4,313		29,013

Total	$	2.5500	$	58,675	$	12,041	$	—	$	10,992	$	81,708

(a)	Our general partner declared this cash distribution on July 22, 2004 to be paid on August 13, 2004 to unitholders of record at the close of business on August 3, 2004.

16. Net Income Per Unit

The following table provides details of the basic and diluted net income per unit computations (in thousands, except per unit amounts):


	Three Months Ended June 30, 2003					Six Months Ended June 30, 2003
	Income (Numerator)		Units (Denominator)	Per Unit Amount		Income (Numerator)		Units (Denominator)	Per Unit Amount
Basic net income per limited partner unit	$	20,498	27,190	$	0.75	$	47,506	27,190	$	1.75
Effect of dilutive restricted unit grants		—	—		—		—	64		0.01

Diluted net income per limited partner unit	$	20,498	27,190	$	0.75	$	47,506	27,254	$	1.74


	Three Months Ended June 30, 2004					Six Months Ended June 30, 2004
	Income (Numerator)		Units (Denominator)	Per Unit Amount		Income (Numerator)		Units (Denominator)	Per Unit Amount
Basic net income per limited partner unit	$	17,465	27,797	$	0.63	$	41,339	27,595	$	1.50
Effect of dilutive restricted unit grants		—	63		—		—	54		—

Diluted net income per limited partner unit	$	17,465	27,860	$	0.63	$	41,339	27,649	$	1.50

Units reported as dilutive securities are related to phantom unit grants (see Note 14 – Long-Term Incentive Plan).

17. Subsequent Events

During June 2004, we announced our agreement to acquire more than 2,000 miles of refined petroleum products pipeline systems from Shell for $492.4 million. We also expect to pay approximately $12.0 million for net working capital, which includes approximately $26.0 million of inventory offset by $14.0 million of escrow cash, assume approximately $12.5 million in existing environmental and pipeline integrity liabilities and incur approximately $9.5 million for transaction costs. We expect to close the acquisition in September 2004, subject to customary due diligence and regulatory approval. Management expects to finance the acquisition initially with cash on hand and short-term bank borrowings and to finance the acquisition permanently with issuances of common units and long-term debt securities. Management is evaluating the appropriate timing of the equity and debt issuances associated with this acquisition. During June 2004, we paid Shell $24.6 million as earnest money associated with the acquisition, which will be applied against the purchase price at closing.

In July 2004, we entered into two agreements for forward starting swaps to hedge our exposure against changes in treasury rates for a portion of the debt we intend to issue during fourth-quarter 2004 to finance the pending pipeline acquisition discussed above. The notional amounts of the agreements total $150.0 million at a weighted average rate of 5.3%. The forward date of the swaps is October 15, 2004 and extends to October 15, 2016.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Introduction

Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the consolidated financial statements and notes thereto. Magellan Midstream Partners, L.P. is a publicly traded limited partnership formed to own, operate and acquire a diversified portfolio of complementary energy assets. We are principally engaged in the transportation, storage and distribution of refined petroleum products. Our three reportable operating segments include:

•

petroleum products pipeline system, which is primarily comprised of a 6,700-mile refined petroleum products pipeline system with 39 terminals and also includes our equity investment in the Osage pipeline;

•

petroleum products terminals, which principally includes our five marine terminal facilities and 29 inland terminals; and

•

ammonia pipeline system, representing our 1,100-mile ammonia pipeline and six associated terminals.

Significant Events

During May 2004, we entered into an agreement with The Williams Companies, Inc. (“Williams”) under which Williams agreed to pay us $117.5 million to release it from certain indemnifications. The indemnifications primarily related to environmental items for periods during which Williams was the owner of assets we previously purchased from them. We received $35.0 million from Williams on July 1, 2004 and expect to receive the remaining balance in annual installments of $27.5 million, $20.0 million and $35.0 million in July of 2005, 2006 and 2007, respectively. See the Environmental section below for further discussion of this matter.

Also in May 2004, we took steps to increase our financial flexibility, which included the issuance of one million common units and $250.0 million of 10-year senior unsecured notes. We used the proceeds from these offerings primarily to refinance $268.0 million of existing secured debt. Further, we amended our remaining secured debt instruments to release the collateral, resulting in our current unsecured capital structure. Please see Liquidity section below for further discussion of our new debt structure.

During June 2004, we announced our agreement to acquire more than 2,000 miles of refined petroleum products pipeline systems from Shell Pipeline Company LP and Equilon Enterprises, LLC whose operations are conducted under the name Shell Oil Products US for $492.4 million. We also expect to pay approximately $12.0 million for net working capital, which includes approximately $26.0 million of inventory offset by $14.0 million of escrow cash, assume approximately $12.5 million in existing environmental and pipeline integrity liabilities and incur approximately $9.5 million for transaction costs. We expect to close the acquisition in September 2004, subject to customary due diligence and regulatory approvals. Management expects to finance the acquisition initially with cash on hand and short-term bank borrowings and to finance the acquisition permanently with issuances of common units and long-term debt securities. Management is evaluating the appropriate timing of the equity and debt issuances associated with this acquisition. During June 2004, we paid Shell $24.6 million as earnest money associated with the acquisition, which will be applied against the purchase price at closing.

Recent Developments

In July 2004, we entered into two agreements for forward starting interest rate swaps to hedge our exposure against changes in treasury rates for a portion of the debt we intend to issue during fourth-quarter 2004 to finance the pending pipeline acquisition discussed above. The notional amounts of the agreements total $150.0 million at a weighted average rate of 5.3%. The forward date of the swaps is October 15, 2004 and extends to October 15, 2016.

On July 22, 2004, the board of directors of our general partner declared a quarterly cash distribution of $0.87 per unit for the period of April 1 through June 30, 2004. The second-quarter distribution represents a 12% increase over the second-quarter 2003 distribution of $0.78 per unit and a 66% increase since our initial public offering in February 2001. The distribution will be paid on August 13, 2004 to unitholders of record on August 3, 2004.

Results of Operations

We believe that investors benefit from having access to the same financial measures being utilized by management. Operating margin is an important performance measure used by management to evaluate the economic success of our core operations. This measure forms the basis of our internal financial reporting and is used by management in deciding how to allocate capital resources between segments. Operating profit, alternatively, includes expense items, such as depreciation and general and administrative costs, that management does not consider when evaluating the core profitability of an operation.

Operating margin is not a generally accepted accounting principle (“GAAP”) measure, but the components of operating margin are computed by using amounts that are determined in accordance with GAAP. A reconciliation of operating margin to operating profit, which is its nearest comparable GAAP financial measure, is included in the table below.

Three Months Ended June 30, 2003 Compared to Three Months Ended June 30, 2004


	Three Months Ended June 30,
	2003		2004
Financial Highlights (in millions)
Revenues:
Transportation and terminals revenue:
Petroleum products pipeline system	$	72.3	$	77.9
Petroleum products terminals		19.9		23.0
Ammonia pipeline system		3.5		3.0
Intersegment eliminations		—		(0.2	)

Total transportation and terminals revenue		95.7		103.7
Product sales		12.2		38.5

Total revenues		107.9		142.2
Operating expenses, environmental expenses and environmental reimbursements:
Petroleum products pipeline system		32.1		33.6
Petroleum products terminals		9.2		9.0
Ammonia pipeline system		1.1		1.4
Intersegment eliminations		—		(0.9	)

Total operating expenses, environmental expenses and environmental reimbursements		42.4		43.1
Product purchases		12.0		32.4
Equity earnings		—		(0.1	)

Operating margin		53.5		66.8
Depreciation and amortization expense		8.9		9.8
Affiliate general and administrative expenses		16.5		13.5

Operating profit	$	28.1	$	43.5


	Three Months Ended June 30,
	2003	2004
Operating Statistics
Petroleum products pipeline system:
Transportation revenue per barrel shipped (cents per barrel)	99.7	100.2
Transportation barrels shipped (million barrels)	59.0	63.2
Barrel miles (billions)	17.5	17.2
Petroleum products terminals:
Marine terminal facilities:
Average storage capacity utilized per month (barrels in millions)	15.6	15.6
Throughput (barrels in millions)	5.4	5.7
Inland terminals:
Throughput (barrels in millions)	15.6	26.1
Ammonia pipeline system:
Volume shipped (tons in thousands)	189	162

Transportation and terminals revenues for the three months ended June 30, 2004 were $103.7 million compared to $95.7 million for the three months ended June 30, 2003, an increase of $8.0 million, or 8%. This increase was the result of:

•

an increase in petroleum products pipeline system revenues of $5.6 million, or 8%, primarily due to significantly higher diesel volume shipments during the current period resulting from increased market demand due to the improving U.S. economy. Further, management fee income associated with our operation of the Longhorn Pipeline beginning in 2004 and higher capacity lease and additive revenues also contributed to the revenue increase;

•

an increase in petroleum products terminals revenues of $3.1 million, or 16%, primarily as a result of our acquisition of ownership interests in 14 inland terminals during January 2004. In addition, revenues at our other inland terminals improved due to increased throughput and marine terminal revenues grew due to higher contract rates; and

•

a decrease in ammonia pipeline system revenues of $0.5 million, or 14%, primarily due to reduced transportation volumes during the current year primarily resulting from maintenance work at one of our shipper’s ammonia facilities that reduced production and thus shipments on our pipeline.

Operating expenses, environmental expenses and environmental reimbursements combined were $43.1 million for the three months ended June 30, 2004 compared to $42.4 million for the three months ended June 30, 2003, an increase of $0.7 million, or 2%. By business segment, this increase was principally the result of:

•

an increase in petroleum products pipeline system expenses of $1.5 million, or 5%, primarily attributable to less favorable product loss allowances and higher asset integrity costs. These increases were partially offset by lower asset retirement and employee costs, the latter reflecting a benefits accrual recorded during 2003 associated with Williams’ sale of its interest in us;

•

a decrease in petroleum products terminals expenses of $0.2 million, or 2%, primarily due to expenses during the 2003 period related to litigation costs and a benefits accrual recorded at the time Williams sold its interest in us. These positive variances were principally offset by higher operating costs associated with the newly acquired ownership interest in 14 inland terminals;

•

an increase in ammonia pipeline system expenses of $0.3 million, or 27%, primarily due to timing of environmental and increased power costs; and

•

intersegment eliminations of $0.9 million, which included $0.7 million of corporate depreciation costs charged to the operating segments as an operating expense and $0.2 million of service fees charged to our petroleum products terminals segment by the petroleum products pipeline segment. During 2003 we did not have depreciable assets recorded at the corporate level and the service fee between the petroleum products terminals and petroleum products pipeline segments did not exist in the second quarter of 2003.

Revenues from product sales were $38.5 million for the three months ended June 30, 2004, while product purchases were $32.4 million, resulting in a net margin of $6.1 million in 2004. The 2004 net margin represents an increase of $5.9 million compared to a net margin in 2003 of $0.2 million resulting from product sales for the three months ended June 30, 2003 of $12.2 million and product purchases of $12.0 million. The increase reflects margin results from our acquisition of the petroleum products management operation during July 2003. Product sales and margins from our petroleum products management business have historically been realized primarily during the first and fourth quarters of each year. Product sales and margins from this business typically are lower during the second and third quarters of each year. Product margin during second-quarter 2004 was higher than normal due to the high gasoline prices.

Depreciation and amortization expense was $9.8 million for the three months ended June 30, 2004 compared to $8.9 million for the three months ended June 30, 2003, an increase of $0.9 million, or 10%, primarily related to the additional depreciation expense associated with assets acquired during the past year.

Affiliate general and administrative (“G&A”) expenses for the three months ended June 30, 2004 were $13.5 million compared to $16.5 million for the three months ended June 30, 2003, a decrease of $3.0 million, or 18%. This fluctuation was primarily attributable to the following items:

•

$2.9 million of incentive compensation expense and $2.0 million of transition costs during the 2003 period, both associated with Williams’ sale of its interest in us. The incentive compensation expense related to an early vesting feature of our equity incentive plan that was triggered due to the change in ownership at the time of the transaction. The 2003 transition costs relate to separation of our G&A functions from Williams, which principally included a benefits accrual at the time of the second-quarter 2003 sale. Comparatively, the 2004 period included $0.2 million of transition costs. We do not anticipate incurring any further transition costs related to our separation from Williams; and

•

$2.3 million more of G&A costs during the 2004 period that will be reimbursed by our general partner. Our general partner provides G&A services to us for an established G&A amount, which was $10.1 million for second-quarter 2004. The owner of our general partner is responsible for G&A expenses in excess of this cap up to a certain amount. We record total G&A costs, including those costs above the cap amount that are reimbursed by the owner of our general partner, as an expense, and we record the amount in excess of the cap for which we are reimbursed as a capital contribution by our general partner. When our general partner was owned by Williams, we were unable to identify specific costs required to support our operations. As a result, we recorded as expense only the G&A costs under the cap, which reflected our actual cash costs. Due to the change in our organizational structure following Williams’ sale of its interest in us in June 2003, we are now able to clearly identify all G&A costs required to support ourselves. The actual cash G&A costs we incur continue to be limited to the G&A cap.

Interest expense, net of interest income, for the three months ended June 30, 2004 was $7.7 million compared to $8.5 million for the three months ended June 30, 2003. The weighted-average interest rate on our borrowings was 6.2% for both periods, with the average debt outstanding decreasing slightly from $570.0 million during 2003 to $561.6 million during 2004.

Refinancing costs associated with our May 2004 debt placement were $16.7 million during second quarter 2004. These costs included a $12.7 million debt prepayment premium associated with the early extinguishment of a portion of our previously outstanding Magellan Pipeline Series B notes and a $5.0 million non-cash write-off of the unamortized debt placement costs associated with the retired debt. Partially offsetting these charges was a $1.0 million gain on an interest rate hedge related to the refinancing.

Net income for the three months ended June 30, 2004 was $18.5 million compared to $18.9 million for the three months ended June 30, 2003, a decline of $0.4 million, or 2%, as a result of $16.7 million of debt refinancing costs during the current period. Operating margin increased by $13.3 million, or 25%, primarily due to higher transportation volumes on our petroleum products pipeline system and incremental operating results associated with our petroleum products management business acquired in July 2003 and our ownership interest in 14 terminals acquired during January 2004. Operating margin also improved during the current period due to operating expense transition costs during 2003 associated with Williams’ sale of its interest in us. G&A costs decreased by $3.0 million between periods, also primarily related to transition expenses during 2003. Depreciation and amortization increased by $0.9 million, whereas net interest expense declined by $0.8 million.

Six Months Ended June 30, 2003 Compared to Six Months Ended June 30, 2004


	Six Months Ended June 30,
	2003		2004
Financial Highlights (in millions)
Revenues:
Transportation and terminals revenue:
Petroleum products pipeline system	$	137.0	$	142.5
Petroleum products terminals		41.3		43.8
Ammonia pipeline system		5.1		6.6
Intersegment eliminations		—		(0.3	)

Total transportation and terminals revenue		183.4		192.6
Product sales		44.2		82.8

Total revenues		227.6		275.4
Operating expenses, environmental expenses and environmental reimbursements:
Petroleum products pipeline system		57.4		62.9
Petroleum products terminals		16.8		17.4
Ammonia pipeline system		2.2		2.4
Intersegment eliminations		—		(1.7	)

Total operating expenses, environmental expenses and environmental reimbursements		76.4		81.0
Product purchases		39.8		70.9
Equity earnings		—		(0.3	)

Operating margin		111.4		123.8
Depreciation and amortization expense		18.3		19.3
Affiliate general and administrative expenses		26.9		26.4

Operating profit	$	66.2	$	78.1

Operating Statistics
Petroleum products pipeline system:
Transportation revenue per barrel shipped (cents per barrel)		98.9		99.1
Transportation barrels shipped (million barrels)		111.7		115.4
Barrel miles (billions)		33.3		32.1
Petroleum products terminals:
Marine terminal facilities:
Average storage capacity utilized per month (barrels in millions)		15.7		15.6
Throughput (barrels in millions)		10.4		11.2
Inland terminals:
Throughput (barrels in millions)		28.3		46.6
Ammonia pipeline system:
Volume shipped (tons in thousands)		236		381

Transportation and terminals revenues for the six months ended June 30, 2004 were $192.6 million compared to $183.4 million for the six months ended June 30, 2003, an increase of $9.2 million, or 5%. This increase was the result of:

•

an increase in petroleum products pipeline system revenues of $5.5 million, or 4%, primarily due to significantly higher diesel volume shipments during the current period resulting from increased market demand due to the improving U.S. economy. Further, additional revenue associated with our operation of the Longhorn Pipeline beginning in 2004 and higher capacity lease and additive revenues in the current period also contributed to the revenue increase;

•

an increase in petroleum products terminals revenues of $2.5 million, or 6%, primarily due to additional revenues from our recently acquired ownership interest in 14 inland terminals. Further, higher rates at our marine terminals and increased throughput at our other inland terminals benefited the 2004 period. These positives more than offset the $3.0 million of revenue recognized during first-quarter 2003 associated with a settlement received from a former customer related to the early termination of its storage contract at our Galena Park facility; and

•

an increase in ammonia pipeline system revenues of $1.5 million, or 29%, primarily due to significantly increased transportation volumes during the current year. Volumes increased in the current year primarily due to higher farm commodity prices and the implementation of a proportional credit program during late 2003.

Operating expenses, environmental expenses and environmental reimbursements combined were $81.0 million for the six months ended June 30, 2004 compared to $76.4 million for the six months ended June 30, 2003, an increase of $4.6 million, or 6%. By business segment, this increase was principally the result of:

•

an increase in petroleum products pipeline system expenses of $5.5 million, or 10%, primarily attributable to less favorable product loss allowances, increased asset integrity costs and higher insurance expenses. These increases were partially offset by lower employee costs due to a benefits accrual recorded during second-quarter 2003 associated with Williams’ sale of its interest in us;

•

an increase in petroleum products terminals expenses of $0.6 million, or 4%, primarily due to operating costs associated with the newly acquired ownership interest in 14 inland terminals. Partially offsetting this increase was a reduction in costs at our Marrero marine facility resulting from the 2003 demolition of smaller, inefficient storage tanks at this location and lower employee costs due to a benefits accrual recorded during second-quarter 2003 associated with Williams’ sale of its interest in us; and

•

intersegment eliminations of $1.7 million, which included $1.4 million of corporate depreciation costs charged to the operating segments as an operating expense and $0.3 million of service fees charged to our petroleum products terminals segment by the petroleum products pipeline segment. During 2003 we did not have depreciable assets recorded at the corporate level and the service fee between the petroleum products terminals and petroleum products pipeline segments did not exist during the first six months of 2003.

Revenues from product sales were $82.8 million for the six months ended June 30, 2004, while product purchases were $70.9 million, resulting in a net margin of $11.9 million in 2004. The 2004 net margin represents an increase of $7.5 million compared to a net margin in 2003 of $4.4 million resulting from product sales for the six months ended June 30, 2003 of $44.2 million and product purchases of $39.8 million. The increase in 2004 primarily reflects the margin results from our acquisition of the petroleum products management operation during July 2003.

Depreciation and amortization expense was $19.3 million for the six months ended June 30, 2004 compared to $18.3 million for the six months ended June 30, 2003, an increase of $1.0 million, or 5%, primarily related to the additional depreciation expense associated with assets acquired during the past year.

Affiliate G&A expenses for the six months ended June 30, 2004 were $26.4 million compared to $26.9 million for the six months ended June 30, 2003, a decline of $0.5 million, or 2%. This decrease was primarily attributable to the following items:

•

$2.9 million of incentive compensation expense and $2.0 million of transition costs during the 2003 period, both associated with Williams’ sale of its interest in us. The incentive compensation expense related to an early vesting feature of our equity incentive plan that was triggered due to the change in ownership at the time of the transaction. The 2003 transition costs relate to separation of our G&A functions from Williams, which principally included a benefits accrual at the time of the second-quarter 2003 sale. Comparatively, the 2004 period included $0.8 million of transition costs. We do not anticipate incurring any further transition costs related to our separation from Williams; and

•

$3.4 million more of G&A costs during the 2004 period that will be reimbursed by our general partner. Our general partner provides G&A services to us for an established G&A amount, which was $20.2 million for the six months ended June 30, 2004. The owner of our general partner is responsible for G&A expenses in excess of this cap up to a certain amount. We record total G&A costs, including those costs above the cap amount that are reimbursed by the owner of our general partner, as an expense, and we record the amount in excess of the cap for which we are reimbursed as a capital contribution by our general partner. When our general partner was owned by Williams, we were unable to identify specific costs required to support our operations. As a result, we recorded as expense only the G&A costs under the cap, which reflected our actual cash costs. Due to the change in our organizational structure

following Williams’ sale of its interest in us in June 2003, we are now able to clearly identify all G&A costs required to support ourselves. The actual cash G&A costs we incur continue to be limited to the G&A cap.

Interest expense, net of interest income, for the six months ended June 30, 2004 was $15.8 million compared to $17.0 million for the six months ended June 30, 2003. The weighted-average interest rate on our borrowings decreased slightly from 6.3% in the first half of 2003 to 6.1% in the first half of 2004. Our average debt outstanding decreased from $570.0 million during 2003 to $565.6 million during 2004.

Refinancing costs associated with our May 2004 debt placement were $16.7 million during the second quarter of 2004. These costs included a $12.7 million debt prepayment premium associated with the early extinguishment of a portion of our previously outstanding Magellan Pipeline Series B notes and a $5.0 million non-cash write-off of the unamortized debt placement costs associated with the retired debt. Partially offsetting these charges was a $1.0 million gain on an interest rate hedge related to the refinancing.

Net income for the six months ended June 30, 2004 was $44.3 million compared to $47.9 million for the six months ended June 30, 2003, a decline of $3.6 million, or 8%, as a result of $16.7 million of debt refinancing costs during the current year. Operating margin increased by $12.4 million, or 11%, primarily due to higher transportation volumes on our petroleum products pipeline system and incremental operating results associated with our petroleum products management business acquired in July 2003 and our ownership interest in 14 terminals acquired during January 2004. Operating margin also improved during the current period due to operating expense transition costs during 2003 associated with Williams’ sale of its interest in us. G&A costs decreased by $0.5 million between periods, also primarily related to transition expenses during 2003 partially offset by reimbursable G&A. Depreciation and amortization increased by $1.0 million, whereas net interest expense declined by $1.2 million.

Liquidity and Capital Resources

Cash Flows and Capital Expenditures

During the six months ended June 30, 2004, net cash provided by operating activities exceeded distributions paid and maintenance capital requirements by $8.0 million. Our current cash distributions exceeded the minimum quarterly distribution of $0.525 per unit by $13.8 million.

Net cash provided by operating activities was $65.8 million and $54.9 million for the six months ended June 30, 2004 and 2003 respectively, an increase of $10.9 million. Although net income declined $3.6 million, current period net income included $12.7 million in charges for debt prepayment premiums and a $1.0 million gain on derivatives. Both the debt prepayment premium and the gain on derivative are classified as financing activities and do not impact cash from operating activities. Also, current period net income included a $5.0 million non-cash charge for the write-off of debt placement fees associated with our second-quarter 2004 refinancing plan. Collectively, these items account for $13.1 million of the increase in net cash from operating activities. These increases were partially offset by changes in components of operating assets and liabilities during 2004. Significant changes in working capital included:

•

a decrease in accrued affiliate payroll and benefits of $4.6 million in 2004 compared to an increase of $4.1 million in 2003. The decrease in 2004 was primarily the result of the payment of larger bonuses related to 2003 in the first quarter of 2004, while smaller bonuses related to 2002 were paid partially in March 2003 and partially in August 2003;

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a decrease in accrued product purchases in 2004 of $5.0 million, compared to an increase of $1.8 million in 2003. The decrease in accrued product purchases in 2004 was primarily the result of seasonal fluctuations related to our petroleum products management operation, which we purchased in July 2003. This decrease was partially offset by a decrease in inventories of $2.6 million in 2004 versus a decrease of only $0.1 million in 2003;

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an increase in accounts receivable and other accounts receivable in 2004 of $34.1 million, compared to an increase of $3.8 million in 2003. The majority of the increase in 2004 was related to indemnified environmental liabilities. The remaining increase in 2004 was attributable primarily to receivables from insurers related to environmental remediation performed during 2004, and to higher trade receivables related to our petroleum products management business as a result of favorable market conditions;

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an increase in current and noncurrent environmental liabilities in 2004 of $33.9 million, compared to a decrease of $1.2 million in 2003. In connection with our negotiations with Williams to settle its environmental indemnifications made to us we reviewed our current assumptions related to our environmental liabilities. The increase in 2004 was primarily the result of recording additional environmental liabilities associated with this review. Most of the increase involved environmental liabilities that were indemnified by Williams and we recorded an offsetting receivable; and

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an increase in affiliate accounts payable in 2004 of $2.0 million, compared to a decrease in affiliate accounts payable of $9.7 million in 2003. The decrease in affiliate accounts payable in 2003 was attributable to the change in ownership of our general partner, which caused us to pay all outstanding affiliate accounts payable.

Net cash used by investing activities for the six months ended June 30, 2004 and 2003 was $93.6 million and $9.5 million, respectively. During 2004, we acquired ownership in 14 petroleum products terminals and a 50% interest in Osage Pipeline Company, LLC and made a deposit payment in connection with our anticipated acquisition of the Shell pipeline assets. We also invested capital to maintain our existing assets. Total maintenance capital spending before reimbursements was $6.2 million and $6.0 million in 2004 and 2003, respectively. Please see Capital Requirements below for further discussion of capital expenditures as well as maintenance capital amounts net of reimbursements.

Net cash used by financing activities for the six months ended June 30, 2004 and 2003 was $31.6 million and $39.4 million, respectively. Net cash used in 2004 is due to the payments of cash distributions to unitholders and net cash used to reduce overall debt, partially offset by proceeds from the issuance of additional equity in second-quarter 2004, capital contributions from our general partner and cash receipts that resulted from unwinding derivative contracts. Net cash used in 2003 was principally cash distributions paid partially offset by capital contributions from our general partner.

During the first two quarters of 2004, we paid $52.7 million in cash distributions to our unitholders and general partner. The quarterly distribution amount associated with the second quarter of 2004 that will be paid during the third quarter of 2004 was $0.87 per unit, which equates to a total payment of $29.0 million. If we continue to pay cash distributions at this current level and the number of outstanding units remains the same, total cash distributions of $116.0 million will be paid to our unitholders on an annual basis. Of this amount, $17.3 million, or 15%, would be related to our general partner’s 2% ownership interest and incentive distribution rights.

Capital Requirements

Our businesses require continual investment to upgrade or enhance existing operations and to ensure compliance with safety and environmental regulations. The capital requirements of our businesses consist primarily of:

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maintenance capital expenditures, such as those required to maintain equipment reliability and safety and to address environmental regulations; and

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payout capital expenditures to acquire additional complementary assets to grow our business and to expand or upgrade our existing facilities, referred to as organic growth projects. Organic growth projects include capital expenditures that increase storage or throughput volumes or develop pipeline connections to new supply sources.

During second-quarter 2004, we spent maintenance capital of $2.9 million net of $0.6 million of environmental reimbursements. Through June 30, 2004, we have spent $5.1 million on maintenance capital related to our operations, net of reimbursable projects. Further, we spent $1.1 million on year-to-date maintenance capital projects for which we were reimbursed, including $0.6 million of environmental projects and $0.5 million associated with our transition from Williams. For 2004, we expect to incur maintenance capital expenditures net of reimbursable projects for our existing businesses of approximately $18.0 million.

In addition to maintenance capital expenditures, we also incur payout capital expenditures at our existing facilities. During second-quarter 2004, we spent $6.9 million for organic growth opportunities and $24.6 million as earnest money for our pending pipeline acquisition from Shell. As of June 30, 2004, we have spent $75.0 million on acquisitions and $13.5 million on organic growth projects year to date. Based on projects currently in process, we plan to spend approximately $30.0 million on organic growth payout capital during 2004. We expect to fund our payout capital expenditures, including any acquisitions, from:

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cash provided by operations;

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borrowings under the revolving credit facility discussed below and other borrowings or debt issuances; and

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the issuance of additional common units.

If capital markets do not permit us to issue additional debt and equity, our business may be adversely affected and we may not be able to acquire additional assets and businesses.

Liquidity

During second-quarter 2004, we completed a refinancing plan that improved our financial flexibility by providing for the release of the collateral previously securing our debt. This refinancing plan further served to reduce the weighted-average interest rate we incur and lower our outstanding debt balance. As of June 30, 2004, we had $551.7 million of total debt outstanding. Details of our current and previous debt obligations follow.

Magellan Midstream Partners 6.45% Senior Notes due 2014. On May 25, 2004, we sold $250.0 million aggregate principal of 6.45% Notes due 2014 in an underwritten public offering. The Notes were issued at 99.8% of par for proceeds of $249.5 million before underwriters’ fees and expenses. After underwriters’ fees and expenses, net proceeds were approximately $246.7 million. Including the impact of the amortization of the realized gains on the interest hedges associated with these notes (see discussion below), the effective interest rate on the notes is 6.3%.

Magellan Pipeline Senior Secured Notes. In connection with the long-term financing of our acquisition of the petroleum products pipeline system, we and our subsidiary, Magellan Pipeline, entered into a note purchase agreement on October 1, 2002. The $480.0 million borrowed under this agreement included Series A and Series B notes. The Series A notes included $178.0 million of borrowings that incur interest based on the six-month Eurodollar rate plus 4.3%. The Series B notes included $302.0 million of borrowings that incur interest at a weighted-average fixed rate of 7.8%. The maturity date of these notes is October 7, 2007, with scheduled prepayments equal to 5% of the outstanding balance due on both October 7, 2005 and October 7, 2006. Payment of interest and principal is guaranteed by the Partnership. Our membership interests in and the assets of Magellan Pipeline initially secured the debt.

As a result of our May 2004 refinancing, we repaid the $178.0 million outstanding balance of the Series A notes and we incurred $12.7 million of associated prepayment premiums. In addition, in exchange for a $1.9 million payment, the Series B noteholders released the collateral that secured these notes, except for cash deposited monthly by Magellan Pipeline into a cash escrow account in anticipation of semi-annual interest payments. Including the impact of the swap of $250.0 million of the Series B notes from fixed-rate to floating-rate, the weighted average interest rate for both the Series A and Series B notes was 6.6% for both the three and six months ended June 30, 2004.

The note purchase agreement under which these notes were issued, as amended during our May 2004 refinancing, requires Magellan Pipeline to maintain specified ratios of: (i) consolidated debt to EBITDA of no greater than 3.50 to 1.00, and (ii) consolidated EBITDA to interest expense of at least 3.25 to 1.00. It also requires us to maintain specified ratios of: (i) consolidated debt to EBITDA of no greater than 4.50 to 1.00, and (ii) consolidated EBITDA to interest expense of at least 2.50 to 1.00. In addition, the note purchase agreement contains additional covenants that limit Magellan Pipeline’s ability to, among other things:

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incur additional indebtedness;

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encumber its assets;

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make debt or equity investments;

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make loans or advances;

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engage in certain transactions with affiliates;

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merge, consolidate, liquidate or dissolve;

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sell or lease a material portion of its assets;

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engage in sale and leaseback transactions; and

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change the nature of its business.

May 2004 Revolving Credit Facility. In connection with our May 2004 refinancing, we entered into a five-year $125.0 million revolving credit facility with a syndicate of banks. Borrowings under this facility are unsecured and bear interest at LIBOR plus a spread ranging from 0.6% to 1.5% based upon our credit ratings. As of June 30, 2004, $0.7 million of the facility was being used for letters of credit, with no other amounts outstanding.

The revolving credit facility requires us to maintain specified ratios of consolidated debt to EBITDA of no greater than 4.5 to 1.0, and consolidated EBITDA to interest expense of at least 2.5 to 1.0. In addition, the facility contains various other covenants limiting our ability to incur additional indebtedness, encumber our assets, make certain investments, engage in certain transactions with affiliates, engage in sale and leaseback transactions, merge, consolidate, liquidate, dissolve or dispose of all of our assets or change the nature of our business. We are in compliance with these covenants.

Magellan Midstream Partners term loan and revolving credit facility. In August 2003, we entered into a credit agreement with a syndicate of banks. This facility was comprised of a $90.0 million term loan and an $85.0 million revolving credit facility. Indebtedness under the term loan incurred interest at the Eurodollar rate plus a margin of 2.0%, while indebtedness under the revolving credit facility incurred interest at the Eurodollar rate plus a margin of 1.8%. We also incurred a commitment fee on the un-drawn portion of the revolving credit facility. In May 2004 we repaid the $90.0 million outstanding term loan balance and this facility was replaced with the revolving credit facility described above.

Management uses interest rate derivatives to manage interest rate risk. In conjunction with our existing and anticipated debt instruments, we recently executed the following derivative transactions:

•

In February 2004, we entered into $150.0 million of 10-year forward starting pay-fixed interest rate swap agreements to hedge against changes in the benchmark interest rate for a portion of the anticipated refinancing of the Magellan Pipeline notes. We received a payment of $3.2 million when we unwound these swaps in May 2004;

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In April 2004, we entered into $150.0 million of 10-year treasury lock agreements to hedge against changes in the benchmark interest rate for a portion of the $250.0 million of 10-year notes we issued in May 2004. The average fixed rate on the locks was 4.4%. We received a payment of $2.9 million when we unwound these locks in May 2004. $1.0 million of this gain was considered ineffective and recorded to net income in the second quarter of 2004;

•

In May 2004, we entered into $250.0 million of pay-floating interest rate swap agreements to hedge against changes in the fair value of a portion of the Magellan Pipeline Series B notes. These agreements effectively change the interest rate on $250.0 million of the Series B notes from a fixed rate of 7.7% to a floating rate of six-month LIBOR plus 3.4%, with LIBOR set in arrears; and

•

In July 2004, we entered into $150.0 million of 12-year forward starting pay-fixed swap agreements to hedge against changes in the benchmark interest rate for a portion of the debt we intend to issue during fourth-quarter 2004 to finance the pending pipeline acquisition discussed above. The average rate of the swaps is 5.3%.

Debt-to-Total Capitalization. The ratio of debt-to-total capitalization is a measure frequently used by the financial community to assess the reasonableness of a company’s debt levels compared to its total capitalization, which is calculated by adding total debt and total partners’ capital. Based on the figures shown in our balance sheet, debt-to-total capitalization was 50% at June 30, 2004. Because accounting rules required the acquisition of our petroleum products pipeline system to be recorded at historical book value due to the then affiliate nature of the transaction, the $474.5 million difference between the purchase price and book value at the time of the acquisition was recorded as a decrease to our general partner’s capital account, thus lowering our overall partners’ capital by that amount. If we had acquired this pipeline system from a third party at the identical purchase price, the asset would have been recorded at market value and we would have incurred approximately $34.3 million of depreciation expense, resulting in a debt-to-total capitalization of 36% because our equity would have been $440.2 million higher.

This pro forma debt-to-total capitalization ratio is presented in order to provide our investors with an understanding of what our debt-to-total capitalization position would have been had we made a similar acquisition from a third party. We believe this presentation is important to investors in comparing our debt-to-total capitalization ratio to that of other entities.

Environmental

Various governmental authorities in the jurisdictions in which our operations are conducted subject us to environmental laws and regulations. We have accrued liabilities for estimated site restoration costs to be incurred in the future at our facilities and properties, including liabilities for environmental remediation obligations at various sites where we have been identified as a possible responsible party. Under our accounting policies, liabilities are recorded when site restoration and environmental remediation and cleanup obligations are either known or considered probable and can be reasonably estimated.

Prior to May 2004, Williams provided indemnifications to us for assets we previously acquired from it. The indemnifications primarily related to environmental items for periods during which Williams was the owner of those assets. During May 2004, we entered into an agreement with Williams under which they agreed to pay us $117.5 million to release it from its indemnification obligations. We received $35.0 million from Williams on July 1, 2004 and expect to receive the remaining balance in annual installments of $27.5 million, $20.0 million and $35.0 million in July of 2005, 2006 and 2007, respectively. As of June 30, 2004, known liabilities that would have been covered by these indemnifications were $42.6 million.

In addition, Magellan Midstream Holdings, L.P. (“MMH”), the owner of our general partner, has indemnified us against certain environmental liabilities. At the time of MMH’s purchase of Williams’ ownership in us, MMH assumed Williams’ obligations to indemnify us for $21.9 million of known environmental liabilities. Through June 30, 2004, we have collected $7.5 million from MMH associated with this indemnification obligation.

Other items

We ship ammonia for three customers on our ammonia pipeline system. The transportation agreements we have with these three customers expire at the end of June 2005. Management has no reason to believe that the demand for ammonia transportation will diminish after the expiration of these contracts.

In conjunction with our May 2004 equity offering, MMH sold approximately 2.4 million of our common units to the public that it held as an investment. Following this secondary offering, MMH owns a combined 27% interest in us, including the general partner interest.

During May 2004, our general partner’s board of directors appointed N. John Lancaster, Jr. as a board member, serving as one of the four representatives from MMH. All eight board seats are filled.

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. FERC, which vacated the FERC’s Lakehead policy. In its Lakehead decision, the FERC allowed a regulated entity organized as a master limited partnership to include in its cost-of-service an income tax allowance to the extent that its unit-holders were corporations subject to income tax. Because the court’s ruling on the FERC’s Lakehead policy in BP West Coast Products appears to focus on the facts and record presented to it in that case, it is not clear what impact, if any, the opinion will have on our indexed rates or on the rates of other FERC-jurisdictional pipelines organized as master limited partnerships (or other tax pass-through entities). Moreover, it is not clear what action the FERC will take in response to BP West Coast, whether such action will be challenged and, if so, whether it will withstand further FERC or judicial review. Nevertheless, a shipper might rely on this decision to challenge our indexed rates and claim that, because we now own the Magellan Pipeline system, the Magellan Pipeline system’s income tax allowance should be eliminated. If the FERC were to disallow our income tax allowance, it may be more difficult to justify our indexed rate. If a challenge were brought and the FERC found that some of the indexed rates exceed levels justified by the cost of service, the FERC would order a reduction in the indexed rates and could require reparations for a period of up to two years prior to the filing of a complaint.

NEW ACCOUNTING PRONOUNCEMENTS

There were no new standards issued by the Financial Accounting Standards Board or other rate-making bodies during the second quarter of 2004 which had a material impact on our results of operations, financial condition or cash flows.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We may be exposed to market risk through changes in commodity prices and interest rates. We do not have foreign exchange risks. We have established policies to monitor and control these market risks.

Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risk to which we are exposed is interest rate risk. As of June 30, 2004, we had no variable interest debt outstanding; however, because of certain interest rate swap agreements discussed below we are exposed to $250.0 million of interest rate market risk. If interest rates change by 0.25%, our interest expense would change by $0.6 million.

During May 2004, we entered into four separate interest rate swap agreements to hedge against changes in the fair value of a portion of the Magellan Pipeline Series B notes. We have accounted for these interest rate hedges as fair value hedges. The notional amounts of the interest rate swap agreements total $250.0 million. Under the terms of the interest rate swap agreements, we will receive 7.7% (the weighted average interest rate of the Magellan Pipeline Series B notes) and will pay LIBOR plus 3.4%. These hedges effectively convert $250.0 million of our fixed-rate debt to floating-rate debt. The interest rate swap agreements began on May 25, 2004 and expire on October 7, 2007. Payments settle in April and October of each year with LIBOR rates set in arrears.

$0.2 million unrealized gain on the swap agreements discussed above under “Liquidity and Capital Resources” was recorded in other assets and as an increase to long-term debt on our balance sheet.

ITEM 4. CONTROLS AND PROCEDURES

An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-14(c) of the Securities Exchange Act) was performed as of the end of the period covered by the date of this report. This evaluation was performed under the supervision and with the participation of our management, including our general partner’s Chief Executive Officer (principal executive officer) and Chief Financial Officer (principal financial officer). Based upon that evaluation, our general partner’s Chief Executive Officer and Chief Financial Officer concluded that these disclosure controls and practices are effective in providing reasonable assurance that all required disclosures are included in the current report.

Our management, including our general partner’s Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls or our internal controls over financial reporting (internal controls) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that simple errors or mistakes can occur. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Over time, controls may become inadequate because of changes in conditions, or the degree of compliance with the policies or procedures may deteriorate. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our disclosure controls and internal controls and make modifications as necessary; our intent in this regard is that the disclosure controls and the internal controls will be maintained as systems change and conditions warrant.

There have been substantial changes in our internal controls since December 31, 2003. We have implemented new accounting systems as well as new payroll and benefits systems. In addition, we implemented our own general and administrative functions, including accounting, legal, human resources, treasury, business development and information technology. Additionally, we developed and implemented a code of business conduct, a conflicts of interest policy for members of our general partner’s board of directors and new policies and procedures. We are nearing the completion of our Sarbanes-Oxley 404 internal control review, which includes the documentation and testing of our newly designed internal control structure. To date, we have found no material internal control weaknesses. Management believes that our internal control system has been designed and implemented in such a manner that it contains no material control weaknesses.

FORWARD-LOOKING STATEMENTS

Certain matters discussed in this Quarterly Report on Form 10-Q include forward-looking statements – statements that discuss our expected future results based on current and pending business operations. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.

Forward-looking statements can be identified by words such as anticipates, believes, expects, estimates, forecasts, projects and other similar expressions. Although we believe our forward-looking statements are based on reasonable assumptions, statements made regarding future results are subject to numerous assumptions, uncertainties and risks that may cause future results to be materially different from the results stated or implied in this document.

The following are among the important factors that could cause actual results to differ materially from any results projected, forecasted, estimated or budgeted:

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price trends and overall demand for natural gas liquids, refined petroleum products, natural gas, oil and ammonia in the United States;

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weather patterns materially different than historical trends;

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development of alternative energy sources;

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changes in demand for storage in our petroleum products terminals;

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changes in supply patterns for our marine terminals due to geopolitical events;

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changes in our tariff rates implemented by the Federal Energy Regulatory Commission and the United States Surface Transportation Board;

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shut-downs or cutbacks at major refineries, petrochemical plants, ammonia production facilities or other businesses that use or supply our services;

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changes in the throughput on petroleum products pipelines owned and operated by third parties and connected to our petroleum products terminals or petroleum products pipeline system;

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loss of one or more of our three customers on our ammonia pipeline system;

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changes in the federal government’s policy regarding farm subsidies, which could negatively impact the demand for ammonia and reduce the amount of ammonia transported through our ammonia pipeline system;

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an increase in the competition our operations encounter;

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the occurrence of an operational hazard or unforeseen interruption for which we are not adequately insured;

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our ability to integrate any acquired operations into our existing operations;

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our ability to successfully identify and close strategic acquisitions and expansion projects and make cost saving changes in operations;

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changes in general economic conditions in the United States;

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changes in laws and regulations to which we are subject, including tax withholding issues, safety, environmental and employment laws and regulations;

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the cost and effects of legal and administrative claims and proceedings against us or our subsidiaries;

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the amount of our indebtedness, which could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds, place us at competitive disadvantages compared to our competitors that have less debt or could have other adverse consequences;

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the condition of the capital markets and equity markets in the United States;

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the ability to raise capital in a cost-effective manner;

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the effect of changes in accounting policies;

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the ability to manage rapid growth;

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MMH’s ability to perform on their environmental and right-of-way indemnifications to us;

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Williams’ ability to pay the amounts owed to us under the indemnification settlement;

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the ability of our general partner to enter into certain agreements which could negatively impact our financial position, results of operations and cash flows;

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supply disruption; and

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global and domestic economic repercussions from terrorist activities and the government’s response thereto.

PART II

OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

During 2001, the Environmental Protection Agency (“EPA”), pursuant to Section 308 of the Clean Water Act (the “Act”), preliminarily determined that Williams may have systemic problems with petroleum discharges from pipeline operations. That inquiry primarily focused on Magellan Pipeline. The response to the EPA’s information request was submitted during November 2001. In March 2004, we received the EPA’s reply, which indicated that the EPA intends to fine us for as much as $22.0 million for violations under Section 311(b) of the Act associated with spills identified in the EPA’s reply that occurred from March 1999 through January 2004. The EPA further indicated that some of those spills may have also violated the Spill Prevention Control and Countermeasure requirements of Section 311(j) of the Act and that additional penalties may be assessed. In addition, we may incur additional costs associated with these spills if the EPA were to successfully seek and obtain injunctive relief. We are in the process of evaluating the EPA’s assertions and anticipate negotiating a final settlement with the EPA during the next twelve months. While we are currently unable to estimate the final settlement amount we have accrued a liability associated with this issue based on our best estimates that is less than $22.0 million.

On March 22, 2004, we received a Corrective Action Order (CPF 4-2004-5006) from the Department of Transportation Southwest Region Office of Pipeline Safety (“OPS”) as a result of the OPS’ May 2003 inspection of the Williams Energy Services Integrity Management Program. The Corrective Action Order (“CAO”) focused on timing of repairs and temporary pressure reductions upon discovery of anomalies. The OPS preliminarily assessed us with a civil penalty of $105,000. We have requested a formal hearing with the OPS to present supplemental information that we believe will help resolve this citation.

The Oklahoma Department of Environmental Quality (“ODEQ”) has alleged in a Notice of Violation dated June 14, 2002 that a terminal on our petroleum products pipeline system located in Enid, Oklahoma was subject to the Maximum Achievable Control Technology (“MACT”) standards at 40 C.F.R 63.420-429, National Emission Standard for Gasoline Distribution Facilities. During July 2004, we reached a verbal agreement with ODEQ to comply with the MACT requirements and to pay a penalty of $475,000.

On August 8, 2003, we notified the Texas Commission on Environmental Quality (“TCEQ”) that we were requesting immunity from civil and administrative penalties under the Texas Environmental Health and Safety Audit Privilege Act (“Audit Act”) for potential violations of TCEQ rules, federal rules or permit emission limits arising out of air emissions produced when storage tank floating roofs are landed on their support legs for extended periods of time. To qualify for immunity under the Audit Act, the violation must have been noted and disclosed as a result of a voluntary environmental audit and must meet the reasonable inquiry standard required under the EPA Clean Air Act Title V regulations. If the TCEQ concludes that our environmental audit that led to the disclosure to TCEQ did not exceed the reasonable inquiry standard, the immunity provided by the Audit Act would not apply, which may result in a fine in excess of $100,000.

We are a party to various legal actions that have arisen in the ordinary course of our business. We do not believe that the resolution of these matters will have a material adverse effect on our financial condition or results of operations.

ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

The annual meeting of our general partner, Magellan GP, LLC, was held on April 22, 2004. At this meeting, two individuals were elected as Class II directors of our general partner’s board of directors. A tabulation of the voting on this issue follows:


Name	For	Withheld	Abstain	Broker Non-Votes
Patrick C. Eilers	22,054,383	125,562	0	0
Pierre F. Lapeyre, Jr.	22,055,588	124,357	0	0

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits:



Exhibit 2.1 –		Amendment No. 3 dated May 26, 2004 to Purchase Agreement dated April 18, 2003 among Williams Energy Services, LLC, Williams Natural Gas Liquids, Inc., Williams GP LLC and WEG Acquisitions, L.P.

Exhibit 3.1 –		Second Amendment dated May 21, 2004 to Amended & Restated Limited Liability Company Agreement of Magellan GP, LLC dated December 1, 2003.

Exhibit 3.2 –		Amendment No. 1 dated July 22, 2004 to Third Amended and Restated Agreement of Limited Partnership of Magellan Midstream Partners, L.P. dated April 22, 2004.

Exhibit 3.3 –		Amendment No. 2 dated July 22, 2004 to Third Amended and Restated Agreement of Limited Partnership of Magellan Midstream Partners, L.P. dated April 22, 2004.

Exhibit 4.1* –		Indenture dated as of May 25, 2004 between Magellan Midstream Partners, L.P. and SunTrust Bank, as trustee (filed as Exhibit 4.1 to Form 8-K filed May 25, 2004).

Exhibit 4.2 * –		First Supplemental Indenture dated as of May 25, 2004 between Magellan Midstream Partners, L.P. and SunTrust Bank, as trustee (filed as Exhibit 4.2 to Form 8-K filed May 25, 2004).

Exhibit 10.1 –		$125,000,000 Revolving Loan Credit Agreement dated May 25, 2004 among Magellan Midstream Partners, L.P., the lenders party thereto, JPMorgan Chase Bank, as Administrative Agent, and J.P. Morgan Securities Inc. and Lehman Brothers Inc., as Joint Bookrunners and Lead Arrangers.

Exhibit 10.2 –		Amended and Restated Note Purchase Agreement dated May 25, 2004 among Magellan Pipeline Company, LLC, Magellan Midstream Partners, L.P. and Magellan GP, LLC and each of the Holders thereto.

Exhibit 10.3 –		Agreement for the Release of Certain Indemnification Obligations dated May 26, 2004 among Magellan Midstream Holdings, L.P., Magellan GP, LLC and Magellan Midstream Partners, L.P. and The Williams Companies, Inc., Williams Energy Services, LLC, Williams Natural Gas Liquids, Inc. and Williams GP LLC.

Exhibit 10.4 –		First Amendment dated May 19, 2004 to Services Agreement dated June 17, 2003 among WEG GP LLC, Williams Energy Partners L.P. and WEG Acquisitions, L.P.

Exhibit 10.5 –		Purchase and Sale Agreement dated June 23, 2004 among Shell Pipeline Company LP, Equilon Enterprises LLC dba Shell Oil Products US and Magellan Midstream Partners, L.P.

Exhibit 12.1 –		Ratio of earnings to fixed charges

Exhibit 31.1 –		Rule 13a-14(a)/15d-14(a) Certification of Don R. Wellendorf, principal executive officer.

Exhibit 31.2 –		Rule 13a-14(a)/15d-14(a) Certification of John D. Chandler, principal financial and accounting officer.

Exhibit 32.1 –		Section 1350 Certification of Don R. Wellendorf, Chief Executive Officer.

Exhibit 32.2 –		Section 1350 Certification of John D. Chandler, Chief Financial Officer.

Exhibit 99.1 –		Magellan GP, LLC balance sheets as of June 30, 2004 and December 31, 2003 and notes thereto.

*	Each such exhibit has previously been filed with the Securities and Exchange Commission as part of the filing indicated and is incorporated herein by reference.

(b) Reports on Form 8-K:

On April 27, 2004, we reported under Items 9 and 12 our earnings for the three months ended March 31, 2004 and 2003. We further reported the non-GAAP financial measures included therein.

On May 5, 2004, we reported under Item 5 the resignationof David M. Leuschen from our general partner’s board of directors, effective May 4, 2004. Mr. Leuschen resigned due to other board of director commitments.

On May 18, 2004, we reported under Item 5 our commencement of simultaneous underwritten public offerings of $250.0 million of senior notes due 2014 and 1 million common units. In addition, we reported that Magellan Midstream Holdings, L.P. had commenced an underwritten public offering of 2 million of our common units.

On May 21, 2004, we reported under Item 5 the announcement that on May 20, 2004, the board of directors of our general partner elected N. John Lancaster, Jr. as a member of the board. Mr. Lancaster replaced David M. Leuschen who resigned on May 4, 2004.

On May 25, 2004, we reported under Item 5 that we had entered into an underwriting agreement for the public offering of $250.0 million aggregate principal amount of 6.45% senior notes due 2014 and 1 million common units representing limited partner interests and the sale by Magellan Midstream Holdings, L.P., the owner of our general partner, of 2 million common units.

On May 27, 2004, we reported under Item 5 that we had closed our previously announced debt and equity offerings. We issued one million common units and $250.0 million of unsecured notes for combined net proceeds of approximately $293.0 million, after underwriting discounts and offering expenses. We also reported under Item 5 that we had entered into an agreement with Williams under which Williams will pay us $117.5 million to release Williams from certain indemnifications provided to us for assets previously acquired from Williams. The indemnifications primarily relate to environmental items for periods during which Williams was the owner of those assets.

On June 24, 2004, we reported under Item 5 that we had agreed to acquire more than 2,000 miles of refined petroleum products pipeline infrastructure from Shell Oil Products US for $492.4 million. In addition to the pipeline systems, the acquisition will include five active system terminals and seven transshipment storage facilities with a combined storage capacity of approximately 6.4 million barrels. The transaction is expected to close within 90 days, subject to customary due diligence and regulatory approval. In addition to the purchase price, we will pay approximately $16.0 million for net working capital, assume approximately $12.5 million in existing liabilities and incur approximately $9.5 million for transaction costs. We further reported that we intend to initially fund the acquisition with cash on hand and bank borrowings and permanently finance the acquisition with equal proceeds from equity and debt issuances.

SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized in Tulsa, Oklahoma, on August 6, 2004.


MAGELLAN MIDSTREAM PARTNERS, L.P.

By:		Magellan GP, LLC,
		its General Partner

/s/ John D. Chandler

John D. Chandler

Chief Financial Officer

and Treasurer (Principal Accounting and

Financial Officer)

INDEX TO EXHIBITS


EXHIBIT NUMBER		DESCRIPTION

2.1		Amendment No. 3 dated May 26, 2004 to Purchase Agreement dated April 18, 2003 among Williams Energy Services, LLC, Williams Natural Gas Liquids, Inc., Williams GP LLC and WEG Acquisitions, L.P.

3.1		Second Amendment dated May 21, 2004 to Amended & Restated Limited Liability Company Agreement of Magellan GP, LLC dated December 1, 2003.

3.2		Amendment No. 1 dated July 22, 2004 to Third Amended and Restated Agreement of Limited Partnership of Magellan Midstream Partners, L.P. dated April 22, 2004.

3.3		Amendment No. 2 dated July 22, 2004 to Third Amended and Restated Agreement of Limited Partnership of Magellan Midstream Partners, L.P. dated April 22, 2004.

4.1*		Indenture dated as of May 25, 2004 between Magellan Midstream Partners, L.P. and SunTrust Bank, as trustee (filed as Exhibit 4.1 to Form 8-K filed May 25, 2004).

4.2*		First Supplemental Indenture dated as of May 25, 2004 between Magellan Midstream Partners, L.P. and SunTrust Bank, as trustee (filed as Exhibit 4.2 to Form 8-K filed May 25, 2004).

10.1		$125,000,000 Revolving Loan Credit Agreement dated May 25, 2004 among Magellan Midstream Partners, L.P., the lenders party thereto, JPMorgan Chase Bank, as Administrative Agent, and J.P. Morgan Securities Inc. and Lehman Brothers Inc., as Joint Bookrunners and Lead Arrangers.

10.2		Amended and Restated Note Purchase Agreement dated May 25, 2004 among Magellan Pipeline Company, LLC, Magellan Midstream Partners, L.P. and Magellan GP, LLC and each of the Holders thereto.

10.3		Agreement for the Release of Certain Indemnification Obligations dated May 26, 2004 among Magellan Midstream Holdings, L.P., Magellan GP, LLC and Magellan Midstream Partners, L.P. and The Williams Companies, Inc., Williams Energy Services, LLC, Williams Natural Gas Liquids, Inc. and Williams GP LLC.

10.4		First Amendment dated May 19, 2004 to Services Agreement dated June 17, 2003 among WEG GP LLC, Williams Energy Partners L.P. and WEG Acquisitions, L.P.

10.5		Purchase and Sale Agreement dated June 23, 2004 among Shell Pipeline Company LP, Equilon Enterprises LLC dba Shell Oil Products US and Magellan Midstream Partners, L.P.

12.1		Ratio of earnings to fixed charges

31.1		Rule 13a-14(a)/15d-14(a) Certification of Don R. Wellendorf, principal executive officer.



31.2		Rule 13a-14(a)/15d-14(a) Certification of John D. Chandler, principal financial and accounting officer.

32.1		Section 1350 Certification of Don R. Wellendorf, Chief Executive Officer.

32.2		Section 1350 Certification of John D. Chandler, Chief Financial Officer.

99.1		Magellan GP, LLC balance sheets for June 30, 2004 and December 31, 2003

*	Each such exhibit has previously been filed with the Securities and Exchange Commission as part of the filing indicated and is incorporated herein by reference.

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