Magellan Midstream Partners (MMP) 10-Q 2006 Q1 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 March 31, 2006

OR

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

For the transition period from              to             

Commission File 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 a large accelerated filer, an accelerated filer or a non-accelerated filer.

Large accelerated filer  x                                Accelerated filer  ¨                                Non-accelerated filer  ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12-b-2 of the Exchange Act).    Yes  ¨    No  x

As of May 8, 2006, there were outstanding 66,360,624 common units.

TABLE OF CONTENTS

FINANCIAL INFORMATION

		Page
ITEM 1.	FINANCIAL STATEMENTS
	MAGELLAN MIDSTREAM PARTNERS, L.P.
	Consolidated Statements of Income for the three months ended March 31, 2005 and 2006	2
	Consolidated Balance Sheets as of December 31, 2005 and March 31, 2006	3
	Consolidated Statements of Cash Flows for the three months ended March 31, 2005 and 2006	4
	Notes to Consolidated Financial Statements	5
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	17
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	24
ITEM 4.	CONTROLS AND PROCEDURES	25
	FORWARD-LOOKING STATEMENTS	25
	PART II
	OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS	27
ITEM 1A.	RISK FACTORS	27
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	27
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	27
ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	27
ITEM 5.	OTHER INFORMATION	27
ITEM 6.	EXHIBITS	28

1

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 March 31,
	2005			2006
Transportation and terminals revenues	$	112,692		$	130,191
Product sales revenues		145,474			148,896
Affiliate management fee revenue		167			173
Total revenues		258,333			279,260
Costs and expenses:
Operating		44,255			51,113
Environmental		1,200			2,272
Product purchases		131,311			133,595
Depreciation and amortization		12,970			15,201
Affiliate general and administrative		15,126			15,027
Total costs and expenses		204,862			217,208
Equity earnings		518			719
Operating profit		53,989			62,771
Interest expense		12,418			14,088
Interest income		(985	)		(646	)
Debt placement fee amortization		732			677
Other (income)/expense		(299	)		339
Net income	$	42,123		$	48,313
Allocation of net income:
Limited partners’ interest	$	35,977		$	36,685
General partner’s interest		6,146			11,628
Net income	$	42,123		$	48,313
Basic net income per limited partner unit	$	0.54		$	0.55
Weighted average number of limited partner units outstanding used for basic net income per unit calculation		66,361			66,361
Diluted net income per limited partner unit	$	0.54		$	0.55
Weighted average number of limited partner units outstanding used for diluted net income per unit calculation		66,467			66,482

See notes to consolidated financial statements.

2

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(In thousands)

	December 31, 2005			March 31, 2006
				(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	36,489		$	35,771
Restricted cash		5,537			11,117
Accounts receivable (less allowance for doubtful accounts of $133 and $42 at December 31, 2005 and March 31, 2006, respectively)		49,373			60,593
Other accounts receivable		5,566			7,697
Affiliate accounts receivable		5,535			5,785
Inventory		78,155			62,768
Other current assets		5,034			7,838
Total current assets		185,689			191,569
Property, plant and equipment, at cost		2,116,143			2,138,467
Less: accumulated depreciation		506,626			520,567
Net property, plant and equipment		1,609,517			1,617,900
Equity investments		24,888			24,532
Long-term receivables		7,327			7,231
Long-term affiliate receivables		1,245			916
Goodwill		24,430			24,430
Other intangibles (less accumulated amortization of $3,607 and $4,006 at December 31, 2005 and March 31, 2006, respectively)		11,652			11,253
Debt placement costs (less accumulated amortization of $6,911 and $7,588 at December 31, 2005 and March 31, 2006, respectively)		8,084			7,407
Other noncurrent assets		3,686			3,521
Total assets	$	1,876,518		$	1,888,759
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	25,508		$	25,283
Affiliate accounts payable		5,821			7,386
Affiliate payroll and benefits		17,028			9,645
Accrued interest payable		9,628			22,627
Accrued taxes other than income		17,307			17,268
Environmental liabilities		30,840			32,606
Deferred revenue		17,522			18,861
Accrued product purchases		34,772			23,727
Current portion of long-term debt		14,345			14,345
Other current liabilities		13,124			15,254
Total current liabilities		185,895			187,002
Long-term debt		782,639			792,561
Long-term affiliate payable		10,091			4,235
Long-term affiliate pension and benefits		9,766			12,593
Other deferred liabilities		52,773			56,483
Environmental liabilities		27,364			24,185
Commitments and contingencies
Partners’ capital:
Partners’ capital		810,045			813,647
Accumulated other comprehensive loss		(2,055	)		(1,947	)
Total partners’ capital		807,990			811,700
Total liabilities and partners’ capital	$	1,876,518		$	1,888,759

See notes to consolidated financial statements.

3

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Three Months Ended March 31,
	2005			2006
Operating Activities:
Net income	$	42,123		$	48,313
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		12,970			15,201
Debt placement fee amortization		732			677
Loss on sale and retirement of assets		451			394
Equity earnings		(518	)		(719	)
Distributions from equity investment		350			1,075
Changes in components of operating assets and liabilities:
Accounts receivable and other accounts receivable		(5,442	)		(13,351	)
Affiliate accounts receivable		965			(250	)
Inventory		6,310			15,387
Accounts payable		5,366			(225	)
Affiliate accounts payable		3,833			1,565
Affiliate payroll and benefits		(10,431	)		(7,383	)
Accrued taxes other than income		(1,098	)		(39	)
Accrued interest payable		13,197			12,999
Accrued product purchases		10,315			(11,045	)
Restricted cash		(5,816	)		(5,580	)
Current and noncurrent environmental liabilities		(1,824	)		(1,413	)
Other current and noncurrent assets and liabilities		(4,768	)		(5,101	)
Net cash provided by operating activities		66,715			50,505
Investing Activities:
Purchases of marketable securities		(50,500	)		—
Sales of marketable securities		126,214			—
Additions to property, plant and equipment		(13,237	)		(24,479	)
Prepaid construction costs		—			2,500
Proceeds from sale of assets		19			466
Net cash provided (used) in investing activities		62,496			(21,513	)
Financing Activities:
Distributions paid		(35,478	)		(49,503	)
Borrowings under revolver		—			57,000
Payments on revolver		—			(42,000	)
Capital contributions by affiliate		—			4,777
Other		59			16
Net cash used in financing activities		(35,419	)		(29,710	)
Change in cash and cash equivalents		93,792			(718	)
Cash and cash equivalents at beginning of period		29,833			36,489
Cash and cash equivalents at end of period	$	123,625		$	35,771

See notes to consolidated financial statements.

4

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 limited partnership. Magellan GP, LLC, a Delaware limited liability company, serves as our general partner and owns a 2% general partner interest in us. Magellan GP, LLC is a wholly-owned subsidiary of Magellan Midstream Holdings, L.P. (“MGG”), a publicly traded Delaware limited partnership. We and Magellan GP, LLC have contracted with Magellan Midstream Holdings GP, LLC (“MGG GP”), MGG’s general partner, to provide all general and administrative services (“G&A”) and operating functions required for our operations.

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, our accompanying consolidated financial statements, which are unaudited except for the consolidated balance sheet as of December 31, 2005, which is derived from audited financial statements, include all normal and recurring adjustments necessary to present fairly our financial position as of March 31, 2006, and the results of operations and cash flows for the three months ended March 31, 2006 and 2005. The results of operations for the three months ended March 31, 2006 are not necessarily indicative of the results to be expected for the full year ending December 31, 2006. Certain amounts in the financial statements for 2005 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, 2005.

2. Allocation of Net Income

The allocation of net income between our general partner and limited partners is as follows (in thousands):

	Three Months Ended March 31,
	2005			2006
Allocation of net income to general partner:
Net income	$	42,123		$	48,313
Charges direct to general partner:
Reimbursable G&A costs		1,043			412
Previously indemnified environmental charges		466			600
Total direct charges to general partner		1,509			1,012
Income before direct charges to general partner		43,632			49,325
General partner’s share of distributions (a)		17.54	%		25.63	%
General partner’s allocated share of net income before direct charges		7,655			12,640
Direct charges to general partner		(1,509	)		(1,012	)
Net income allocated to general partner	$	6,146		$	11,628
Net income	$	42,123		$	48,313
Less: net income allocated to general partner		6,146			11,628
Net income allocated to limited partners	$	35,977		$	36,685

(a) The increase in the general partner’s share of distributions is because we increased our quarterly distributions per limited partner unit from $0.48 associated with the first quarter of 2005 to $0.565 associated with the first quarter of 2006. Our general partner owns the incentive distribution rights which entitle it to receive a higher percentage of our total distributions as we increase our distributions to our limited partners. See Note 13-Distributions for details of the distributions we have declared and paid during 2005 and 2006.

5

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Charges in excess of the G&A expense cap were $1.0 million and $0.4 million for the three months ended March 31, 2005 and 2006, respectively. These amounts represent G&A expenses charged against our income during each respective period for which we either have been or will be reimbursed by our general partner under the terms of the new omnibus agreement. Consequently, these amounts have been charged directly against our general partner’s allocation of net income. We record these reimbursements by our general partner as a capital contribution. During 2004, we and our general partner entered into an agreement with The Williams Companies, Inc. (“Williams”) to settle Williams’ indemnification obligations to us (see Note 11—Commitments and Contingencies). Following this settlement, the expenses associated with these previously indemnified costs have been charged directly to our general partner. We believe we will collect the full amount of the indemnification settlement from Williams and accordingly will continue to allocate amounts associated with previously indemnified costs to our general partner.

3. Comprehensive Income

A reconciliation of net income to comprehensive income follows below (in thousands). For information on all of our derivative instruments, see Note 10 – Derivative Financial Instruments.

	Three Months Ended March 31,
	2005		2006
Net income	$	42,123	$	48,313
Change in fair value of product hedges		—		55
Amortization of net loss on cash flow hedges		53		53
Other comprehensive income (loss)		53		108
Comprehensive income	$	42,176	$	48,421

4. 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, operating expenses, environmental expenses, product purchases and equity earnings.

The non-generally accepted accounting principles 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 management uses to evaluate performance. Operating margin is an important 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, such as depreciation and amortization and G&A costs, that management does not consider when evaluating the core profitability of an operation.

6

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

	Three Months Ended March 31, 2005
	(in thousands)
	Petroleum Products Pipeline System			Petroleum Products Terminals		Ammonia Pipeline System		Elimin- ations			Total
Transportation and terminals revenues	$	85,271		$	25,510	$	2,701	$	(790	)	$	112,692
Product sales revenues		142,804			2,670		—		—			145,474
Affiliate management fee revenue		167			—		—		—			167
Total revenues		228,242			28,180		2,701		(790	)		258,333
Operating expenses		35,129			9,182		1,402		(1,458	)		44,255
Environmental		842			38		320		—			1,200
Product purchases		130,125			1,311		—		(125	)		131,311
Equity earnings		(518	)		—		—		—			(518	)
Operating margin		62,664			17,649		979		793			82,085
Depreciation and amortization		8,394			3,601		182		793			12,970
Affiliate G&A expenses		11,059			3,522		545		—			15,126
Segment profit	$	43,211		$	10,526	$	252	$	—		$	53,989

	Three Months Ended March 31, 2006
	(in thousands)
	Petroleum Products Pipeline System			Petroleum Products Terminals		Ammonia Pipeline System		Elimin- ations			Total
Transportation and terminals revenues	$	90,749		$	35,475	$	4,721	$	(754	)	$	130,191
Product sales revenues		143,719			5,177		—		—			148,896
Affiliate management fee revenue		173			—		—		—			173
Total revenues		234,641			40,652		4,721		(754	)		279,260
Operating expenses		38,778			11,837		2,004		(1,506	)		51,113
Environmental		1,908			121		243		—			2,272
Product purchases		130,463			3,259		—		(127	)		133,595
Equity earnings		(719	)		—		—		—			(719	)
Operating margin		64,211			25,435		2,474		879			92,999
Depreciation and amortization		9,562			4,570		190		879			15,201
Affiliate G&A expenses		10,818			3,676		533		—			15,027
Segment profit	$	43,831		$	17,189	$	1,751	$	—		$	62,771

During the first quarter of 2006, we began facilitating certain product sales between a supplier and customer. We have determined that, under Emerging Issues Task Force Issue No. 99-19, “Recording Revenue Gross as a Principle Versus Net as an Agent,” we were acting as an agent relative to these transactions. Accordingly, we have recorded these transactions as net instead of gross. Had these transactions been recorded at their gross amounts, our petroleum products pipeline system’s product sales revenues and product purchases would have increased by $30.3 million.

5. Related Party Disclosures

Affiliate Entity Transactions

In March 2004, we acquired a 50% ownership interest in Osage Pipe Line Company, LLC (“Osage Pipeline”). We operate the Osage pipeline for which we are paid a management fee. During both the three months ended March 31, 2005 and 2006, we received operating fees from Osage Pipeline of $0.2 million, which we reported as affiliate management fee revenues.

7

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following table summarizes costs and expenses from various affiliate companies with us and are reflected in the cost and expenses in the accompanying consolidated statements of income (in thousands):

	Three Months Ended March 31,
	2005	2006
MGG - allocated operating expenses	15,819	—
MGG - allocated G&A expenses	15,126	5,082
MGG GP - allocated operating expenses	—	17,987
MGG GP - allocated G&A expenses	—	9,945

In June 2003, we and our general partner entered into a services agreement with MGG pursuant to which MGG agreed to provide the employees necessary to conduct our operations. We reimbursed MGG for all payroll and benefit costs it incurred from January 1, 2005 through December 24, 2005. On December 24, 2005, the employees necessary to conduct our operations, were transferred to MGG GP, and the services agreement with MGG was terminated and a new services agreement with MGG GP was executed. Consequently, we now reimburse MGG GP for costs of employees necessary to conduct our operations. In June 2003, we and our general partner entered into an agreement with MGG whereby MGG agreed to reimburse us for G&A expenses in excess of a G&A cap as defined in the omnibus agreement. The amount of G&A costs that either has been or will be reimbursed by MGG to us was $1.0 million and $0.4 million for the three months ended March 31, 2005 and 2006, respectively.

Williams and certain of its affiliates had indemnified us against certain environmental costs. The environmental indemnifications we had with Williams were settled during 2004. In addition, in June 2003 MGG agreed to assume from Williams certain indemnified obligations to us. See Note 11—Commitments and Contingencies for information relative to this settlement.

Other Related Party Transactions

MGG, which owns our general partner, is partially owned by an affiliate of the Carlyle/Riverstone Global Energy and Power Fund II, L.P. (“CRF”). Two of the members of our general partner’s eight-member board of directors are nominees of CRF. On January 25, 2005, CRF, through affiliates, acquired general and limited partner interests in SemGroup, L.P. (“SemGroup”). CRF’s total combined general and limited partner interest in SemGroup is approximately 30%. One of the members of the seven-member board of directors of SemGroup’s general partner is a nominee of CRF, with three votes on that board. We, through our affiliates, are a party to a number of arms-length transactions with SemGroup and its affiliates. A summary of these transactions is provided in the following table (in millions):

	January 25, 2005 Through March 31, 2005		Three Months Ended March 31, 2006
Sales of petroleum products	$	25.8	$	28.2
Purchases of petroleum products		19.8		11.0
Terminalling and other services revenues		1.2		1.6
Storage tank lease revenues		0.4		0.8
Storage tank lease expense		0.2		0.2

In addition to the above, we provide common carrier transportation services to SemGroup. As of December 31, 2005 and March 31, 2006, we had recognized a receivable of $6.2 million and $5.9 million, respectively, from and a payable of $6.1 million and $1.2 million, respectively, to SemGroup and its affiliates. The receivable is included with the accounts receivable amounts and the payable is included with the accounts payable amounts on our consolidated balance sheets.

CRF also has an ownership interest in the general partner of Buckeye Partners, L.P. (“Buckeye”). During the three months ended March 31, 2005, our operating expenses included $0.3 million of costs we incurred with Norco Pipe Line Company, LLC, which is a subsidiary of Buckeye.

The board of directors of our general partner has adopted a Board of Directors Conflict of Interest Policy and Procedure. In compliance with this policy, CRF has adopted procedures internally to assure that our proprietary and confidential information is protected from disclosure to SemGroup and Buckeye. As part of these procedures, none of the nominees of CRF will serve on our general partner’s board of directors and on SemGroup’s or Buckeye’s general partner’s board of directors at the same time.

8

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

During May 2005, our general partner’s board of directors appointed John P. DesBarres as an independent board member. Mr. DesBarres currently serves as a board member for American Electric Power Company, Inc. of Columbus, Ohio. During the three months ended March 31, 2006, our operating expenses included $0.7 million of costs that we incurred with Public Service Company of Oklahoma, which is a subsidiary of American Electric Power Company, Inc.

Because our distributions have exceeded target levels as specified in our partnership agreement, our general partner receives 50% of any incremental cash distributions per limited partner unit. The executive officers of MGG GP collectively own approximately 2.9% of MGG Midstream Holdings, L.P., the owner of MGG GP and, therefore, also indirectly benefit from these distributions. Assuming we have sufficient available cash to continue to pay distributions on all of our outstanding units for four quarters at our current quarterly distribution level of $0.565 per unit, our general partner would receive distributions of approximately $54.7 million in 2006 on its combined 2% general partner interest and incentive distribution rights.

During February 2006, MGG sold 35% of its MGG common units in an initial public offering. We did not receive any of the proceeds from MGG’s initial public offering and do not expect our ownership structure or operations to be materially impacted by this transaction. In connection with the closing of this offering, we amended our partnership agreement to remove the requirements for our general partner to maintain its current 2% interest in any future offering of our limited partner units. In addition, we amended our partnership agreement to restore the incentive distribution rights to the same level as before an amendment made in connection with our October 2004 pipeline system acquisition, which reduced the incentive cash distributions paid to our general partner by $5.0 million for 2005 and $3.0 million for 2006. In return, MGG made a capital contribution to us on February 9, 2006 equal to $4.2 million, which represents the present value of the remaining reductions in our general partner’s incentive cash distributions.

6. Inventory

Inventory at December 31, 2005 and March 31, 2006 was as follows (in thousands):

	December 31, 2005		March 31, 2006
Refined petroleum products	$	56,680	$	37,046
Natural gas liquids		9,693		12,600
Transmix		9,589		10,759
Additives		1,805		1,975
Other		388		388
Total inventory	$	78,155	$	62,768

7. Equity Investment

We use the equity method to account for our 50% ownership interest in Osage Pipeline. The remaining 50% interest is owned by National Cooperative Refining Association (“NCRA”). Our agreement with NCRA calls for equal sharing of Osage Pipeline’s net income. Summarized financial information for Osage Pipeline for the three months ended March 31, 2005 and 2006 is presented below (in thousands):

	Three Months Ended March 31,
	2005		2006
Revenues	$	2,342	$	3,288
Net income	$	1,368	$	1,770

Condensed balance sheets for Osage Pipeline as of December 31, 2005 and March 31, 2006 are presented below (in thousands):

	December 31, 2005		March 31, 2006
Current assets	$	4,767	$	4,370
Noncurrent assets	$	4,535	$	4,688
Current liabilities	$	431	$	568
Members’ equity	$	8,871	$	8,490

9

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

	Three Months Ended March 31,
	2005			2006
Initial investment / investment at beginning of period	$	25,084		$	24,888
Earnings in equity investment:
Proportionate share of earnings		684			885
Amortization of excess investment		(166	)		(166	)
Net earnings in equity investment		518			719
Cash distributions		(350	)		(1,075	)
Equity investment at end of period	$	25,252		$	24,532

Our initial investment in Osage Pipeline included an excess net investment amount of $21.7 million, which is being amortized over the average lives of Osage Pipeline’s assets. 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. The unamortized excess investment at December 31, 2005 and March 31, 2006 was $20.5 million and $20.3 million, respectively.

8. Employee Benefit Plans

MGG GP sponsors a pension plan for union employees, a pension plan for non-union employees and a post-retirement benefit plan for selected employees. The following table presents our consolidated net periodic benefit costs related to these plans during the three months ended March 31, 2005 and 2006 (in thousands):

	Three Months Ended March 31, 2005					Three Months Ended March 31, 2006
	Pension Benefits			Other Post- Retirement Benefits		Pension Benefits			Other Post- Retirement Benefits
Components of Net Periodic Benefit Costs:
Service cost	$	1,271		$	86	$	1,229		$	140
Interest cost		498			186		541			270
Expected return on plan assets		(451	)		—		(558	)		—
Amortization of prior service cost		169			450		169			450
Amortization of actuarial loss		—			—		252			115
Net periodic benefit cost	$	1,487		$	722	$	1,633		$	975

9. Debt

Debt at December 31, 2005 and March 31, 2006 was as follows (in thousands):

	December 31, 2005		March 31, 2006
Magellan Pipeline notes:
Current portion	$	14,345	$	14,345
Long-term portion		270,074		268,798
Total Magellan Pipeline notes		284,419		283,143
6.45% Notes due 2014		249,546		249,557
5.65% Notes due 2016		250,019		246,206
Revolving credit facility		13,000		28,000
Total debt	$	796,984	$	806,906

10

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Our debt and the debt of our consolidated subsidiaries is non-recourse to our general partner.

Magellan Pipeline Notes. During October 2002, Magellan Pipeline entered into a private placement debt agreement with a group of financial institutions for $302.0 million of fixed-rate notes. The maturity date of the notes is October 7, 2007; however, we repaid $15.1 million of the notes on October 7, 2005, which represented 5.0% of the outstanding balance on that date, and we will be required to repay an additional 5.0% of the principal amount outstanding on October 7, 2006. The outstanding principal amount of the notes at December 31, 2005 and March 31, 2006 was decreased by $2.5 million and $3.8 million, respectively, for the change in the fair value of the associated hedge (see Note 10–Derivative Financial Instruments). The interest rate of the notes is fixed at 7.7%; however, including the impact of the associated fair value hedge, which effectively swaps $250.0 million of the fixed-rate notes to floating-rate debt, the weighted-average interest rate for the notes at March 31, 2005 and March 31, 2006 was 7.0% and 8.5%, respectively. We make deposits in an escrow account in anticipation of semi-annual interest payments on these notes and the cash deposits are secured; however, the notes themselves are unsecured. These deposits of $5.5 million at December 31, 2005 and $11.1 million at March 31, 2006 were reflected as restricted cash on our consolidated balance sheets.

6.45% Notes due 2014.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 notes were issued for the discounted price of 99.8%, or $249.5 million, and the discount is being accreted over the life of the notes. Including the impact of the amortization of the realized gains on the interest hedges associated with these notes (see Note 10–Derivative Financial Instruments), the effective interest rate of these notes is 6.3%. Interest is payable semi-annually in arrears on June 1 and December 1 of each year.

5.65% Notes due 2016.On October 7, 2004, we issued $250.0 million of aggregate principal of 5.65% notes due 2016. The notes were issued for the discounted price of 99.9%, or $249.7, million, and the discount is being accreted over the life of the notes. Including the impact of hedges associated with these notes (see Note 10–Derivative Financial Instruments), the weighted-average interest rate of these notes at March 31, 2005 and March 31, 2006 was 5.2% and 5.9%, respectively. Interest is payable semi-annually in arrears on April 15 and October 15 of each year. The outstanding principal amount of the notes at December 31, 2005 and March 31, 2006 was increased by $0.3 million and decreased by $3.5 million, respectively, for the change in the fair value of the associated hedge (see Note 10–Derivative Financial Instruments).

The indenture under which the 6.45% and 5.65% 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 these covenants.

Revolving Credit Facility.In 2004, we entered into a five-year $175.0 million revolving credit facility with a syndicate of banks. The maturity date of the revolver is May 25, 2009. Borrowings under this revolving credit facility are unsecured and bear interest at LIBOR plus a spread ranging from 0.6% to 1.5% based on our credit ratings. The weighted-average rate on the revolver at March 31, 2006 was 5.5%. Borrowings under this facility were $13.0 million and $28.0 million at December 31, 2005 and March 31, 2006, respectively. The net proceeds from the revolving credit facility were used for general corporate purposes, including capital expenditures. $1.1 million of the facility was obligated for letters of credit at both December 31, 2005 and March 31, 2006, which is not reflected as debt on our consolidated balance sheets. There was no revolver amount outstanding at March 31, 2005. Interest is also assessed on the unused portion of the credit facility at a rate from 0.15% to 0.35% depending on our credit rating.

10. Derivative Financial Instruments

We use interest rate derivatives to help us manage interest rate risk. The following table summarizes hedges we have settled associated with various debt offerings (dollars in millions):

Hedge	Date	Gain/(Loss)	Amortization Period
Interest rate hedge	October 2002	$(1.0)	5-year life of Magellan Pipeline notes
Interest rate swaps and treasury lock	May 2004	5.1	10-year life of 6.45% notes
Interest rate swaps	October 2004	(6.3)	12-year life of 5.65% notes

In addition to the above, we have entered into the following interest rate swap agreements:

• During May 2004, we entered into certain interest rate swap agreements to hedge against changes in the fair value of a portion of the Magellan Pipeline senior notes. We have accounted for these interest rate hedges as fair value hedges.

11

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The notional amounts of the interest rate swap agreements total $250.0 million. Under the terms of the interest rate swap agreements, we receive 7.7% (the weighted-average interest rate of the outstanding Magellan Pipeline senior notes) and 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 maturity date of the Magellan Pipeline senior notes. Payments settle in April and October each year with LIBOR set in arrears. During each settlement period, we record the impact of this swap based on our best estimate of LIBOR. Any differences between actual LIBOR determined on the settlement date and our estimate of LIBOR result in an adjustment to our interest expense. A 0.25% change in LIBOR would result in an annual adjustment to our interest expense associated with this hedge of $0.6 million. The fair value of the instruments associated with this hedge at December 31, 2005 and March 31, 2006 was $(2.5) million and $(3.8) million, respectively, which was recorded to other noncurrent liabilities and long-term debt.

• In October 2004, we entered into an interest rate swap agreement to hedge against changes in the fair value of a portion of the $250.0 million of senior notes due 2016 which were issued in October 2004. The notional amount of this agreement is $100.0 million and effectively converts $100.0 million of our 5.65% fixed-rate senior notes issued in October 2004 to floating-rate debt. Under the terms of the agreement, we receive the 5.65% fixed rate of the notes and pay LIBOR plus 0.6%. The agreement began on October 15, 2004 and terminates on October 15, 2016, which is the maturity date of these senior notes. Payments settle in April and October each year with LIBOR set in arrears. During each settlement period we will record the impact of this swap based on our best estimate of LIBOR. Any differences between actual LIBOR determined on the settlement date and our estimate of LIBOR will result in an adjustment to our interest expense. A 0.25% change in LIBOR would result in an annual adjustment to our interest expense of $0.3 million associated with this hedge. The fair value of this hedge at December 31, 2005 and March 31, 2006, was $0.3 million and $(3.5) million, respectively, which was recorded to other noncurrent assets and long-term debt at December 31, 2005 and noncurrent liabilities and long-term debt at March 31, 2006.

In February 2006, we entered into a forward sales contract for 0.1 million barrels of gasoline that we expect to produce from our petroleum products blending operations. These barrels will be sold at the Platts average price during September 2006. Concurrent with that transaction, we entered into three derivative swap contracts to hedge against price changes associated with the sale of that product, in which we agreed to buy 0.1 million barrels of gasoline at the Platts average price in September 2006 and sell 0.1 million barrels of gasoline at the fixed price of $77.28 per barrel. Our objective in entering into this derivative was to lock in a gross margin on the expected sale of 0.1 million barrels of gasoline in September 2006. The fair value of these hedging instruments at March 31, 2006 was $0.1 million, which was recorded to other current assets and other comprehensive income.

11. Commitments and Contingencies

Estimated liabilities for environmental costs were $58.2 million and $56.8 million at December 31, 2005 and March 31, 2006, respectively. These estimates are provided on an undiscounted basis and have been classified as current or noncurrent 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. Our environmental liabilities include accruals associated with theEnvironmental Protection Agency (“EPA”)Issue,Kansas City, Kansas Releaseand Independence, Kansas Release, which are discussed as follows:

EPA Issue. In July 2001, the 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 systematic problems with petroleum discharges from pipeline operations. That inquiry primarily focused on Magellan Pipeline, which we subsequently acquired. 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, which 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 releases 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 releases if the EPA were to successfully seek and obtain injunctive relief. We responded to the March 2004 information request in a timely manner and have entered into an agreement that provides both parties an opportunity to negotiate a settlement prior to initiating litigation. This matter was included in the indemnification settlement with Williams (seeEnvironmental Indemnification Settlementdiscussion below). We have accrued an amount for this matter based on our best estimates that is less than $22.0 million. Due to the uncertainties described above, it is reasonably possible that the amounts we have recorded for this environmental liability could change in the near term. Management is unable to determine with any accuracy what those amounts could be and they could be material to our results of operations and cash flows.

12

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Kansas City, Kansas Release. During the second quarter of 2005, we experienced a line break and product release of approximately 2,900 barrels of product on our petroleum products pipeline near our Kansas City, Kansas terminal. As of March 31, 2006, we have estimated the costs associated with this release of approximately $2.7 million. We have spent $1.7 million on remediation associated with this release and have $1.0 million of associated environmental liabilities at March 31, 2006. We have recorded a receivable of $1.2 million from our insurance carrier associated with this release. We have not been assessed a penalty by the EPA or any other regulatory agency relative to this release and we are unable to estimate with any certainty what penalties, if any, might be assessed. However, if penalties are assessed, the recognition of such obligations, which could occur in the near term, could be material to our results of operations and cash flows.

Independence, Kansas Release. During the first quarter of 2006, we experienced a line break and product release of approximately 3,200 barrels of product on our petroleum products pipeline near Independence, Kansas. As of March 31, 2006, we have estimated costs associated with this release to be approximately $2.8 million and we have spent $1.3 million on remediation resulting in an associated environmental liability at March 31, 2006 of $1.5 million. We have recorded a receivable of $1.3 million from our insurance carrier associated with this release. We have not been assessed a penalty by the EPA or any other regulatory agency relative to this release and we are unable to estimate with any certainty what penalties, if any, might be assessed. However, if penalties are assessed, the recognition of such obligations, which could occur in the near term, could be material to our results of operations and cash flows.

Environmental Indemnification Settlement. Prior to May 2004, Williams had agreed to indemnify us against certain environmental losses, among other things, associated with assets that Williams contributed to us at the time of our initial public offering or which we subsequently acquired from Williams. 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 these indemnifications. We received $35.0 million and $27.5 million from Williams on July 1, 2004 and 2005, respectively, and expect to receive installment payments from Williams of $20.0 million and $35.0 million on July 1, 2006 and 2007, respectively. While the settlement agreement releases Williams from its environmental and certain indemnifications, other indemnifications remain in effect. These remaining indemnifications cover issues involving employee benefits matters, issues involving rights of way, easements and real property, including asset titles, and unlimited losses and damages related to tax liabilities.

As of December 31, 2005 and March 31, 2006, known liabilities that would have been covered by Williams’ previous indemnity agreements were $43.1 million and $41.2 million, respectively. Through March 31, 2006, we have spent $21.7 million of the $117.5 million indemnification settlement amount for indemnified matters, including $7.1 million of capital costs. The cash we have received from the indemnity settlement is not reserved and has been used for our various other cash needs, including expansion capital spending.

MGG Indemnification Obligation.As part of its negotiations with Williams for the June 2003 acquisition of Williams’ interest in us, MGG assumed Williams’ obligations for $21.9 million of our known environmental liabilities. To the extent the environmental and other Williams indemnity claims against MGG are less than $21.9 million, MGG will pay Williams the remaining difference between $21.9 million and the indemnity claims paid by MGG. Recorded liabilities associated with this indemnification were $5.5 million and $4.7 million at December 31, 2005 and March 31, 2006, respectively.

Environmental Receivables.Upon MGG’s assumption of Williams’ environmental obligations to us, as discussed in MGG Indemnification Obligation above, we recorded a receivable from MGG of $21.9 million. Our receivable balance with MGG at December 31, 2005 and March 31, 2006 was $6.7 million and $5.5 million, respectively. Environmental receivables from insurance carriers were $2.1 million and $3.5 million at December 31, 2005 and March 31, 2006, respectively.

Unrecognized product gains. Our operations generate product overage and shortages. When we experience net product losses, we recognize expense for those losses in the period in which they occur. When we experience product gains however, we have product on hand for which we have no cost basis. As a result, we are unable to recognize these overage barrels as inventory on our balance sheets. Therefore, these overages are not recognized in our financial statements until the associated barrels are either sold or are used to offset product losses. The combined net product overages for our operations as of March 31, 2006, had a market value of approximately $18.9 million. However, the actual amounts we will recognize in future periods will depend on product prices at the time the associated barrels are either sold or used to offset future product losses.

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 on our future financial position, results of operations or cash flows.

12. Long-Term Incentive Plan

We have a long-term incentive plan for certain employees who perform services for us and directors of our general partner. The long-term incentive plan primarily consists of two components: phantom units and unit options. To date, there have been no unit options granted. The long-term incentive plan permits the grant of awards covering an aggregate of 1.4 million common units. The compensation committee of our general partner’s board of directors administers the long-term incentive plan.

13

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

We adopted Statement of Financial Accounting Standard (“SFAS”) No. 123(R) on January 1, 2006 using the modified prospective application method, which required us to account for all of our equity-based incentive awards granted prior to January 1, 2006, using the fair value method as defined in SFAS No. 123 instead of our previous methodology of using the intrinsic value method as defined in Accounting Principles Bulletin (“APB”) No. 25. Due to the structure of our award grants prior to January 1, 2006, we recognized compensation expense under APB No. 25 in much the same manner as that required under SFAS No. 123; therefore, the impact of the change from accounting for the award grants under APB No. 25 to SFAS No. 123 on our results of operations, financial position and cash flows was insignificant.

The board of directors of our general partner made the following grants to certain employees when those employees became dedicated to providing services to us:

• In October 2003, 21,280 phantom units were granted pursuant to the long-term incentive plan. Of these awards, 20,340 units vested during 2003 and 2004. The remaining 940 units vested on July 31, 2005.

• In January 2004, 21,712 phantom units were granted pursuant to the long-term incentive plan. Of these awards, 10,866 units vested on July 31, 2004 and 10,846 units vested on July 31, 2005.

In February 2004, our general partner issued approximately 159,000 phantom units award grants 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 ranges from zero up to a total of 313,000, as adjusted for estimated forfeitures and retirements; 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 for any reason other than for retirement, death or disability prior to the vesting date. If an award recipient retires, dies or becomes disabled prior to the end of the vesting period, the recipient’s grant will be prorated based upon the completed months of employment during the vesting period and the award will be paid at the end of the vesting period. These awards do not have an early vesting feature except when there is a change in control of our general partner. We have estimated the number of units that will be awarded under this grant to be 300,000, the value of which on March 31, 2006 was $9.9 million. The unrecognized estimated compensation expense associated with these awards as of March 31, 2006 was $2.5 million.

In February 2005, our general partner issued approximately 161,000 phantom units award grants 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 long-term performance metrics. The number of phantom units that could ultimately be issued under this award ranges from zero units up to a total of 317,000 as adjusted for estimated forfeitures and retirements; 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 20%. The units will vest at the end of 2007. These units are subject to forfeiture if employment is terminated for any reason other than for retirement, death or disability prior to the vesting date. If an award recipient retires, dies or becomes disabled prior to the end of the vesting period, the recipient’s grant will be prorated based upon the completed months of employment during the vesting period and the award will be paid at the end of the vesting period. These awards do not have an early vesting feature except when there is a change in control of our general partner. We have estimated the number of units that will be awarded under this grant to be 283,000, the value of which on March 31, 2006 was $9.3 million. The unrecognized estimated compensation expense associated with these awards as of March 31, 2006 was $5.4 million.

In February 2006, our general partner issued approximately 168,000 phantom units award grants 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 long-term performance metrics. The number of units that could ultimately be issued under this award range from zero units up to a total of approximately 330,000 units, as adjusted for estimated forfeitures and retirements. These units are subject to forfeiture if employment is terminated for any reason other than for retirement, death or disability prior to the vesting date. If an award recipient retires, dies or becomes disabled prior to the end of the vesting period, the recipient’s grant will be prorated based upon the completed months of employment during the vesting period and the award will be paid at the end of the vesting period. These awards do not have an early vesting feature except when there is a change in control of our general partner. These awards are being accounted for as follows:

• Of the unit awards granted in February 2006, approximately 134,000 are based on the attainment of long-term performance metrics. The number of units that could ultimately vest under this component of the award range from zero

14

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

to approximately 264,000 as adjusted for expected forfeitures and retirements. Upon vesting, these award grants must be paid out to the employees in units; therefore, we have accounted for these awards using the equity method. The fair value of the awards on the grant date was $24.47 per unit; which was based on our unit price on the grant date less the present value of the estimated cash distributions on those units during the vesting period. We have accrued for these awards based on the probability of a standard payout. The unrecognized compensation expense associated with these awards as of March 31, 2006 was $3.1 million which will be recognized over the next 33 months. There was no impact on our cash from operating or financing activities during the three months ended March 31, 2006 associated with these awards.

• Of the unit awards granted in February 2006, approximately 34,000 are based on personal performance at the discretion of the compensation committee. The number of units that could ultimately vest under this component of the award range from zero to approximately 66,000 as adjusted for expected forfeitures and retirements. Because vesting criteria for these awards are partially based on conditions other than service, performance or market conditions, we have accounted for these awards using the liability method, as such, the compensation expense we recognize is based on the period-end closing price of our units and the percentage of the service period completed at each period end. We have accrued for these awards based on the probability of a standard payout. The value of these awards at March 31, 2006, was $1.1 million and the unrecognized estimated compensation costs on that date was $1.0 million. There was no impact on our cash from operating or financing activities during the three months ended March 31, 2006 associated with these awards.

Our equity-based incentive compensation expense for the three months ended March 31, 2005 and 2006 is summarized as follows (in thousands):

	Three Months Ended March 31,
	2005		2006
2003 awards	$	683	$	(86	)
October 2003 awards		3		(3	)
January 2004 awards		44		(4	)
2004 awards		878		682
2005 awards		414		751
2006 awards		—		189
Total	$	2,022	$	1,529

13. Distributions

We paid the following distributions during 2005 and 2006 (in thousands, except per unit amounts):

Cash Distribution Payment Date	Per Unit Cash Distribution Amount	Common Units	Subordinated Units	General Partner	Total Cash Distribution
02/14/05	$0.45625	$26,390	$3,887	$5,201	$35,478
05/13/05	0.48000	29,127	2,726	6,778	38,631
08/12/05	0.49750	30,189	2,825	7,939	40,953
11/14/05	0.53125	32,236	3,018	10,178	45,432
Total	$1.96500	$117,942	$12,456	$30,096	$160,494
02/14/06	$0.55250	$33,526	$3,138	$12,839	$49,503
05/13/06 (a)	0.56500	37,494	—	13,668	51,162
Total	$1.11750	$71,020	$3,138	$26,507	$100,665

(a) Our general partner declared this cash distribution on April 26, 2006 to be paid on May 15, 2006, to unitholders of record at the close of business on May 8, 2006.

In February 2006, we amended our partnership agreement to restore the incentive distribution rights to the same level as before an amendment made in connection with our October 2004 pipeline system acquisition, which reduced the incentive distributions paid to our general partner by $1.3 million for 2004, $5.0 million for 2005 and $3.0 million for 2006. In return, MGG made a capital contribution to us on February 9, 2006 equal to the present value of the remaining reductions in incentive distributions, or $4.2 million.

15

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

14. 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):

	For The Three Months Ended March 31, 2005
	Income (Numerator)		Units (Denominator)	Per Unit Amount
Basic net income per limited partner unit	$	35,977	66,361	$	0.54
Effect of dilutive restricted unit grants		—	106		—
Diluted net income per limited partner unit	$	35,977	66,467	$	0.54

	For The Three Months Ended March 31, 2006
	Income (Numerator)		Units (Denominator)	Per Unit Amount
Basic net income per limited partner unit	$	36,685	66,361	$	0.55
Effect of dilutive restricted unit grants		—	121		—
Diluted net income per limited partner unit	$	36,685	66,482	$	0.55

Units reported as dilutive securities are related to phantom unit grants (see Note 12 – Long-Term Incentive Plan).

15. Partners’ Capital

Our subordination period ended on December 31, 2005, when we met the final financial test provided for in our partnership agreement. As a result, on January 31, 2006, one day following the distribution record date, the 5,679,696 outstanding subordinated units representing limited partner interests in us converted to common units.

16. Subsequent Events

On April 26, 2006, our general partner declared a quarterly distribution of $0.565 per unit to be paid on May 15, 2006, to unitholders of record at the close of business on May 8, 2006 (see Note 13—Distributions for details).

In May 2006, we agreed on terms to amend and restate our existing revolving credit facility to increase the size from $175.0 million to $400.0 million and lower the associated interest rate to LIBOR plus a spread ranging from 0.3% to 0.7% when facility borrowings are less than $200.0 million or from 0.3% to 0.8% when facility borrowings are greater than $200.0 million. In addition, the maturity date of the revolving credit facility is being extended by two years.

16

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Introduction

We are 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. As of March 31, 2006, our three operating segments include:

• petroleum products pipeline system, which is primarily comprised of our 8,500-mile petroleum products pipeline system, including 45 terminals;

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

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

The following discussion provides an analysis of the results for each of our operating segments, an overview of our liquidity and capital resources and other items related to our company. The following discussion and analysis should be read in conjunction with (i) our accompanying interim consolidated financial statements and related notes and (ii) our consolidated financial statements, related notes and management’s discussion and analysis of financial condition and results of operations included in our Annual Report on Form 10-K for the year ended December 31, 2005.

Significant Events

During February 2006, Magellan Midstream Holdings, L.P. (“MGG”), the owner of our general partner interest, sold 35% of its common units in an initial public offering. We did not receive any of the proceeds from MGG’s initial public offering and do not expect our ownership structure or operations to be materially impacted by this transaction. In connection with the closing of this offering, we amended our partnership agreement to remove the requirement for our general partner to maintain its 2% interest in any future offering of our limited partner units. In addition, we amended our partnership agreement to restore the incentive distribution rights to the same level as before an amendment made in connection with our October 2004 pipeline system acquisition, which reduced the incentive distributions paid to our general partner by $1.3 million for 2004, $5.0 million for 2005 and $3.0 million for 2006. In return, MGG made a capital contribution to us on February 9, 2006 equal to the present value of the remaining reductions in incentive distributions, or $4.2 million.

Recent Developments

Distribution. On April 26, 2006, the board of directors of our general partner declared a quarterly cash distribution of $0.565 per unit for the period of January 1 through March 31, 2006, representing our twentieth consecutive quarterly distribution increase since our initial public offering in February 2001. We intend to pay the quarterly distribution on May 15, 2006 to unitholders of record on May 8, 2006.

Approval of board members.On April 26, 2006, we held our fourth annual unitholder meeting. Proxy statements were mailed in advance to unitholders of record on February 28, 2006. Our unitholders approved the appointment of N. John Lancaster, Jr., George A. O’Brien, Jr. and Thomas S. Souleles to continue serving in their capacity as members of our general partner’s board of directors until our 2009 annual meeting. No other matters requiring a unitholder vote were discussed.

Conversion of subordinatedunits. Our subordination period ended on December 31, 2005, when we met the final financial test provided for in our partnership agreement. As a result, on January 31, 2006, one day following the distribution record date, the 5,679,696 outstanding subordinated units representing limited partner interests in us converted to common units.

Revolving Credit Facility. In May 2006, we agreed on terms to amend and restate our existing revolving credit facility to increase the size from $175.0 million to $400.0 million and lower the rate to LIBOR plus a spread ranging from 0.3% to 0.7% when facility borrowings are less than $200.0 million or from 0.3% to 0.8% when facility borrowings are greater than $200.0 million. In addition, the maturity date of the revolving credit facility is being extended by two years.

17

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 measure used by management to evaluate the economic performance of our 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 margin is not a generally accepted accounting principles (“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. Operating profit includes expense items, such as depreciation and amortization and general and administrative (“G&A”) costs, which management does not consider when evaluating the core profitability of an operation.

Three Months Ended March 31, 2005 Compared to Three Months Ended March 31, 2006

	Three Months Ended March 31,
	2005			2006
Financial Highlights (in millions)
Revenues:
Transportation and terminals revenues:
Petroleum products pipeline system	$	85.3		$	90.7
Petroleum products terminals		25.5			35.5
Ammonia pipeline system		2.7			4.7
Intersegment eliminations		(0.8	)		(0.7	)
Total transportation and terminals revenues		112.7			130.2
Product sales		145.5			148.9
Affiliate management fees		0.1			0.2
Total revenues		258.3			279.3
Operating and environmental expenses:
Petroleum products pipeline system		36.0			40.7
Petroleum products terminals		9.2			12.0
Ammonia pipeline system		1.7			2.2
Intersegment eliminations		(1.5	)		(1.5	)
Total operating and environmental expenses		45.4			53.4
Product purchases		131.3			133.6
Equity earnings		(0.5	)		(0.7	)
Operating margin		82.1			93.0
Depreciation and amortization		13.0			15.2
Affiliate G&A expenses		15.1			15.0
Operating profit	$	54.0		$	62.8
Operating Statistics
Petroleum products pipeline system:
Transportation revenue per barrel shipped	$	1.020		$	1.026
Transportation barrels shipped (million barrels)		65.7			69.0
Petroleum products terminals:
Marine terminal facilities:
Average storage capacity utilized per month (million barrels)		16.5			19.1
Throughput (million barrels)		12.4			10.9
Inland terminals:
Throughput (million barrels)		26.1			27.7
Ammonia pipeline system:
Volume shipped (thousand tons)		152			216

18

Transportation and terminals revenues for the three months ended March 31, 2006 were $130.2 million compared to $112.7 million for the three months ended March 31, 2005, an increase of $17.5 million, or 16%. This increase was a result of:

• an increase in petroleum products pipeline system revenues of $5.4 million, or 6%, primarily related to increased diesel fuel shipments during the current period. We earned more ancillary revenues related to additive and terminal services during 2006, partially offset by a settlement payment we received during first-quarter 2005 related to our no longer operating the Rio Grande pipeline effective April 1, 2005;

• an increase in petroleum products terminals revenues of $10.0 million, or 39%, primarily due to the recognition of revenue during first-quarter 2006 related to a variable-rate terminalling agreement and results from our Wilmington, Delaware marine terminal, which we acquired on September 1, 2005. Under the previously-mentioned variable-rate terminalling agreement, we provided storage rental and throughput fees based on discounted rates plus a variable fee, which was based on a percentage of the net profits from certain trading activities conducted by our customer. During the first-quarter 2006, we recognized revenues of $6.4 million from the variable fee portion of the agreement once our customer’s trading profits were determinable at the end of the contract term, which expired January 31, 2006. Upon expiration of this agreement, we negotiated a similar agreement pursuant to which we will receive a share of any net trading profits above a specified amount but we will not share in any net trading losses. We cannot predict what revenues, if any, we may realize from this variable-rate agreement. Revenues also increased at our inland terminals due to higher additive fees and throughput volumes; and

• an increase in ammonia pipeline system revenues of $2.0 million, or 74%, due to higher tariffs associated with our new transportation agreements, which became effective July 1, 2005, and increased volumes. Transportation volumes were higher because first-quarter 2005 volumes were negatively affected by planned maintenance work at a customer’s ammonia facilities and additional production in the current period as a result of lower natural gas prices than those experienced in late 2005.

Operating and environmental expenses combined were $53.4 million for the three months ended March 31, 2006 compared to $45.4 million for the three months ended March 31, 2005, an increase of $8.0 million, or 18%. By business segment, this increase was principally the result of:

• an increase in petroleum products pipeline system expenses of $4.7 million, or 13%, primarily attributable to higher power costs, less favorable product overages, increased property taxes and higher environmental expenses related to a January 2006 pipeline release;

• an increase in petroleum products terminals expenses of $2.8 million, or 30%. This increase was primarily related to expenses associated with our Wilmington marine terminal which we acquired in September 1, 2005, and higher power, maintenance and property taxes at our other terminals; and

• an increase in ammonia pipeline system expenses of $0.5 million, or 29%, primarily attributable to higher power costs resulting from additional shipments and higher system integrity costs. We expect the amount of system integrity spending to be significantly higher during 2006 due to the timing of high consequence area testing mandated by federal regulations.

Product sales revenues primarily result from a third-party product supply agreement, our petroleum product blending operations and from fractionating transmix. Revenues from product sales were $148.9 million for the three months ended March 31, 2006, while product purchases were $133.6 million, resulting in gross margin from these transactions of $15.3 million. The gross margin resulting from product sales and purchases for the 2006 period increased $1.1 million compared to gross margin for the 2005 period of $14.2 million, reflecting product sales for the three months ended March 31, 2005 of $145.5 million and product purchases of $131.3 million. The gross margin increase in 2006 primarily resulted from the impact of high gasoline prices on our petroleum products blending and fractionation operations. We believe the gross margin could be substantially lower in the future once refined petroleum product prices stabilize.

Operating margin increased $10.9 million, or 13%, primarily due to incremental operating results from our recently-acquired Wilmington marine facility, revenues from a variable-rate terminalling agreement and improved utilization of our assets.

Depreciation and amortization expense was $15.2 million for the three months ended March 31, 2006 compared to $13.0 million for the three months ended March 31, 2005, an increase of $2.2 million, or 17%. This increase is primarily related to asset acquisitions and capital improvements over the past year and the acceleration of depreciation for our terminal automation systems that we are in the process of upgrading.

Interest expense, net of interest income, for the three months ended March 31, 2006 was $13.4 million compared to $11.4 million for the three months ended March 31, 2005, an increase of $2.0 million, or 18%. Our average debt outstanding, excluding fair

19

value adjustments for interest rate hedges, increased to $817.0 million during first-quarter 2006 from $802.0 million during first-quarter 2005 primarily due to borrowings under our revolving credit facility to fund our capital spending and working capital needs. Further, the weighted-average interest rate on our borrowings, after giving effect to the impact of associated fair value hedges, increased to 6.9% for the 2006 period from 6.3% for the 2005 period primarily due to rising interest rates.

Net income for the three months ended March 31, 2006 was $48.3 million compared to $42.1 million for the three months ended March 31, 2005, an increase of $6.2 million, or 15%.

Liquidity and Capital Resources

Cash Flows and Capital Expenditures

Net cash provided by operating activities was $50.5 million and $66.7 million for the three months ended March 31, 2006 and 2005, respectively. The $16.2 million decrease from 2005 to 2006 was primarily attributable to:

• a net increase in accounts receivable and other accounts receivable which resulted in a decrease in cash provided by operating activities of $7.9 million between the periods; and

• a decrease in accrued product purchases of $11.0 million in 2006 compared to an increase in 2005 of $10.3 million which resulted in a reduction of cash from operating activities between the periods of $21.3 million. During 2006, our purchases of petroleum products declined as we reduced our petroleum products inventory levels. The 2005 increase reflected increasing product prices during that period and higher volumes associated with our third-party supply agreement.

These decreases were partially offset by:

• increased net income of $6.2 million primarily due to incremental operating results from our recently-acquired Wilmington marine facility, revenue from a variable-rate terminalling agreement and improved utilization of our assets; and

• changes in inventory levels between first-quarter 2005 and first-quarter 2006, which resulted in an increase in cash from operating activities between the periods of $9.1 million. High inventory levels at December 31, 2005 resulted from our third-party supply agreement customer not taking all of its nominated volumes. During first-quarter 2006, our customer purchased products in excess of its nominated volumes, resulting in lower inventory levels at the end of first-quarter 2006.

Net cash provided (used) by investing activities for the three months ended March 31, 2006 and 2005 was ($21.5) million and $62.5 million, respectively. During 2006, we spent $24.5 million for capital expenditures. In 2005, our sales of marketable securities, net of purchases, generated $75.7 million of cash, and we spent $13.2 million for capital expenditures. Total maintenance capital spending before indemnifications and reimbursements was $3.6 million and $3.1 million during first-quarter 2006 and 2005, respectively. Please seeCapital Requirements below for further discussion of capital expenditures as well as maintenance capital amounts net of indemnifications.

Net cash used by financing activities for the three months ended March 31, 2006 and 2005 was $29.7 million and $35.4 million, respectively, and primarily consisted of cash distributions paid to our unitholders. During 2006, net borrowings on our revolving credit facility partially offset distributions paid.

During first-quarter 2006, we paid $49.5 million in cash distributions to our unitholders and general partner. Based on the declared quarterly distribution of $0.565 per unit associated with the first quarter of 2006, we intend to pay $51.2 million in distributions during second quarter 2006. If we continue to pay cash distributions at this current level and the number of outstanding units remains the same, total cash distributions of $204.6 million will be paid on an annual basis. Of this amount, $54.7 million, or 27%, is 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. Capital spending for our businesses consists primarily of:

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

20

• expansion 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 first-quarter 2006, we spent maintenance capital of $2.9 million, excluding $0.7 million of spending on environmental projects that would have been covered by indemnifications settled in May 2004. We have received $62.5 million to date under this settlement agreement. Please see Environmental below for additional discussion of this indemnification settlement.

For 2006, we expect to incur maintenance capital expenditures for our existing businesses of approximately $27.0 million, excluding the following:

• $7.0 million for environmental projects that would have been covered by the indemnifications discussed above; and

• $2.0 million that we expect to receive from insurance proceeds for the replacement of docks at our Marrero, Louisiana marine terminal. These docks remain operational but were damaged by Hurricane Katrina in third-quarter 2005 and must be replaced.

In addition to maintenance capital expenditures, we also incur expansion capital expenditures at our existing facilities. During first-quarter 2006, we spent cash of approximately $20.9 million for organic growth opportunities. Based on projects currently underway or in advanced stages of development, we currently plan to spend approximately $175.0 million on organic growth capital during 2006, exclusive of amounts associated with future acquisitions.

Liquidity

As of March 31, 2006, total debt reported on our consolidated balance sheet was 806.9 million, as described below. The difference between this amount and the $814.9 million face value of our outstanding debt is due to adjustments associated with the fair value hedges we have in place for a portion of our outstanding senior notes and unamortized discounts on debt issuances.

5.65% Senior Notes due 2016.On October 15, 2004, we sold $250.0 million of 5.65% senior notes due 2016 in an underwritten public offering as part of the long-term financing of the pipeline system assets we acquired in October 2004. The notes were issued at 99.9% of par, and we received proceeds after underwriters’ fees and expenses of approximately $247.6 million. Including the impact of pre-issuance hedges associated with these notes and the swap of $100.0 million of the notes from fixed-rate to floating-rate, the weighted-average interest rate on the notes at March 31, 2006 was 5.9%.

6.45% Senior Notes due 2014.On May 25, 2004, we sold $250.0 million of 6.45% senior notes due 2014 in an underwritten public offering at 99.8% of par. We received proceeds after underwriters’ fees and expenses of approximately $246.9 million. Including the impact of pre-issuance hedges associated with these notes, the effective interest rate on these notes at March 31, 2006 was 6.3%.

Magellan Pipeline Notes. In connection with the long-term financing of our acquisition of Magellan Pipeline, we and Magellan Pipeline entered into a note purchase agreement on October 1, 2002. As of March 31, 2006, $286.9 million of senior notes were outstanding pursuant to this agreement The maturity date of these notes is October 7, 2007, with a scheduled prepayment equal to 5% of the outstanding balance on October 7, 2006. We guarantee payment of interest and principal by Magellan Pipeline. The notes are unsecured except for cash deposited monthly by Magellan Pipeline into a cash escrow account in anticipation of semi-annual interest payments. The weighted-average interest rate for the senior notes, including the impact of the swap of $250.0 million of the notes from fixed-rate to floating-rate debt, was 8.5% at March 31, 2006.

Revolving Credit Facility.In May 2004, we entered into a five-year $125.0 million revolving credit facility, which we subsequently increased to $175.0 million in September 2004. 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 March 31, 2006, $28.0 million was outstanding under this facility, and $1.1 million of the facility was obligated for letters of credit. The obligations for letters of credit are not reflected as debt on our consolidated balance sheets. As of March 31, 2006, the weighted-average interest rate on borrowings outstanding under this facility was 5.5%. MMP is in the process of amending and restating this credit facility. Please seeRevolving Credit Facility under “Recent Developments” in this Management’s Discussion and Analysis of Financial Condition and Results of Operations for further discussion of this matter.

The debt instruments described above include various covenants. In addition to certain financial ratio covenants, these covenants limit our ability to, among other things, incur indebtedness secured by certain liens, encumber our assets, make certain investments, engage in certain sale-leaseback transactions and consolidate, merge or dispose of all or substantially all of our assets. We are in compliance with these covenants.

21

Interest Rate Derivatives. We utilize interest rate derivatives to manage interest rate risk. In conjunction with our existing debt instruments, we were engaged in the following derivative transactions as of March 31, 2006:

• In October 2004, we entered into a $100.0 million interest rate swap agreement to hedge against changes in the fair value of a portion of our 5.65% senior notes due 2016. This agreement effectively changes the interest rate on $100.0 million of those notes to a floating rate of six-month LIBOR plus 0.6%, with LIBOR set in arrears. This swap agreement expires on October 15, 2016, the maturity date of the 5.65% senior notes; and

• In May 2004, we entered into $250.0 million of interest rate swap agreements to hedge against changes in the fair value of a portion of the Magellan Pipeline senior notes. These agreements effectively change the interest rate on $250.0 million of the senior notes from a fixed rate of 7.7% to a floating rate of six-month LIBOR plus 3.4%, with LIBOR set in arrears. These swap agreements expire on October 7, 2007, the maturity date of the Magellan Pipeline senior notes.

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 March 31, 2006. Because accounting rules required the acquisition of Magellan Pipeline to be recorded at historical book values 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.

Credit Ratings. Our current credit ratings are BBB by Standard and Poor’s and Baa3 by Moody’s Investor Services.

Environmental

Various governmental authorities in the jurisdictions in which we conduct our operations 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, we record liabilities when site restoration and environmental remediation obligations are either known or considered probable and can be reasonably estimated.

Prior to May 2004, The Williams Companies, Inc. (“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. In May 2004, we entered into an agreement with Williams under which Williams agreed to pay us $117.5 million to release it from those indemnification obligations. To date, we have received $62.5 million from Williams and expect to receive the remaining balance in installments of $20.0 million and $35.0 million on July 1 of 2006 and 2007, respectively. As of March 31, 2006, known liabilities that would have been covered by these indemnifications were $41.2 million. In addition, we have spent $21.7 million through March 31, 2006 that would have been covered by these indemnifications, including $7.1 million of capital costs.

At the time of MGG’s purchase of our general partner interest in June 2003, MGG assumed obligations to indemnify us for $21.9 million of known environmental liabilities. Through March 31, 2006, we have incurred $17.2 million of costs associated with this indemnification obligation, leaving a remaining liability of $4.7 million. Our receivable balance with MGG on March 31, 2006 was $5.5 million.

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 systematic problems with petroleum discharges from pipeline operations. That inquiry primarily focused on Magellan Pipeline, which we subsequently acquired in April 2002. 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, which 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 submitted all information requested to date. We have met with the EPA and the DOJ and anticipate negotiating a final settlement with both agencies in 2006. We have accrued an amount that is less than $22.0 million associated with this matter. Due to the uncertainties described above, it is reasonably possible that the amounts we have recorded for this environmental liability could change in the near term. Management is unable to determine with any accuracy what those amounts could be and they could be material to our results of operations or cash flows.

22

Other Items

Galena Park marine terminal expansion. During late 2005 and early 2006, we executed a series of long-term terminalling agreements with several customers pursuant to which we will construct 30 new storage tanks at our Galena Park, Texas marine terminal. Tank construction has begun and we expect the new tanks to be placed into service during 2006 and 2007. We believe these new agreements will significantly contribute to our results of operations and cash flows once construction is complete and the 30 new tanks have been placed into service.

Line break and product release. On January 13, 2006, we experienced a line break and product release of approximately 3,200 barrels from our petroleum products pipeline near Independence, Kansas. We are in the process of estimating the repair and remediation costs associated with the release. We have insurance coverage for this incident with a maximum deductible of $1.5 million. We are unable to estimate with any degree of certainty what penalties, if any, might be assessed by the EPA or other governmental agency associated with this release, which would not be covered by our insurance policy. Our net cost for repair and remediation plus any penalties that may be assessed could be material to our results of operations or cash flows.

Unrecognized product gains. Our operations generate product overage and shortages. When we experience net product losses, we recognize expense for those losses in the period in which they occur. When we experience product gains however, we have product on hand for which we have no cost basis. As a result, we are unable to recognize these overage barrels as inventory on our balance sheets. Therefore, these overages are not recognized in our financial statements until the associated barrels are either sold or are used to offset product losses. The net product overages for our operations as of March 31, 2006, had a market value of approximately $18.9 million. However, the actual amounts we will recognize in future periods will depend on product prices at the time the associated barrels are either sold or used to offset future product losses.

Affiliate transactions. In June 2003, we and our general partner entered into a services agreement with MGG pursuant to which MGG agreed to provide the employees necessary to conduct our operations. We reimbursed MGG for all payroll and benefit costs it incurred from January 1, 2005 through December 24, 2005. On December 24, 2005, the employees necessary to conduct our business operations were transferred to MGG’s general partner, and the services agreement with MGG was terminated and a new services agreement with MGG’s general partner was executed. Consequently, we now reimburse MGG’s general partner for costs of employees necessary to conduct our operations. Also in June 2003, we and our general partner entered into an agreement with MGG whereby MGG agreed to reimburse us for G&A expenses in excess of a G&A cap as defined in the omnibus agreement.

We were allocated $18.0 million and $15.8 million of operating expenses from MGG and its general partner for the three months ended March 31, 2006 and 2005, respectively, and $15.0 million and $15.1 million of G&A expenses for the three months ended March 31, 2006 and 2005, respectively. MGG will reimburse us $0.4 million of G&A costs for the three months ended March 31, 2006.

In March 2004, we acquired a 50% ownership interest in a crude oil pipeline company. In April 2004, we began operating the related pipeline, for which we received operating fees of $0.2 million for the three months ended March 31, 2006 and 2005. We report these fees as affiliate management fee revenue.

Related party agreements. MGG is partially owned by an affiliate of Carlyle/Riverstone Global Energy and Power Fund II, L.P. (“CRF”). Two members of our general partner’s eight-member board of directors are nominees of CRF. On January 25, 2005, CRF, through affiliates, acquired general and limited partner interests in SemGroup. CRF’s total combined general and limited partner interest in SemGroup is approximately 30%. One of the members of the seven-member board of directors of SemGroup’s general partner is a nominee of CRF, with three votes on that board.

We are a party to a number of arms-length transactions with SemGroup and its affiliates. For the three months ended March 31, 2006 and 2005 we recognized revenues from SemGroup related to the sale of petroleum products of $28.2 million and $25.8 million, respectively; terminalling and other services of $1.6 million and $1.2 million, respectively; and leased storage tanks of $0.8 million and $0.4 million, respectively. We also provide common carrier transportation services to SemGroup. Additionally, during the three months ended March 31, 2006 and 2005, we recognized unrelated product purchases from SemGroup of $11.0 million and $19.8 million, respectively, and expenses for leased storage tanks of $0.2 million for both periods.

As of March 31, 2006, we had recognized a receivable of $5.9 million from and a payable of $1.2 million to SemGroup and its affiliates.

23

During the first quarter of 2006, SemGroup disclosed that it was attempting to acquire Transmontaigne, Inc., a publicly traded refined petroleum products marketing and distribution company that is a customer of ours and competes with us to an extent in various markets that we serve.

CRF also has an ownership interest in the general partner of Buckeye Partners, L.P. (“Buckeye”). We do not have a significant relationship with Buckeye and do not have extensive operations in the geographic areas primarily served by Buckeye.

The board of directors of our general partner has adopted a policy to address board of director conflicts of interests. In compliance with this policy, CRF has adopted procedures internally to assure that our proprietary and confidential information is protected from disclosure to SemGroup and Buckeye. As part of these procedures, none of the nominees of CRF will serve on our general partner’s board of directors and on SemGroup’s or Buckeye’s general partner’s board of directors at the same time.

NEW ACCOUNTING PRONOUNCEMENTS

In February 2006, the Financial Accounting Standards Board (“FASB”) issued Financial Staff Position (“FSP”) No. FAS 123(R)-4,Classification of Options and Similar Instruments Issued as Employee Compensation That Allow for Cash Settlement Upon the Occurrence of a Contingent Event.Statement of Financial Accounting Standard (“SFAS”) No. 123(R) previously required options or similar instruments to be classified as liabilities if the entity could be required under any circumstances to settle the option or similar instrument by transferring cash or other assets. FSP No. FAS 123(R)-4 amends SFAS No. 123(R) so that a cash settlement feature that can be exercised only upon the occurrence of a contingent event that is outside the employee’s control does not necessarily require the instrument to be classified as liability until it becomes probable that the event will occur. The guidance in this FSP was required to be applied in the first reporting period beginning after the date the FSP was posted to the FASB website. The adoption of this FSP during the first quarter of 2006 had no impact on our accounting for equity-based incentive compensation expense.

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 have established policies to monitor and control these market risks. We also enter into derivative agreements to help manage our exposure to commodity price and interest rate risks. We do not have foreign exchange 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 March 31, 2006, we had $28.0 million outstanding on our variable rate revolving credit facility. We had no other variable interest debt outstanding; however, because of certain interest rate swap agreements discussed below, we are exposed to interest rate market risk on an additional $350.0 million of our debt. Considering these interest rate swap agreements and the amount outstanding on our revolving credit facility as of March 31, 2006, our annual interest expense would change by $0.9 million if LIBOR were to change by 0.25%.

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 senior 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 agreements, we receive 7.7% (the interest rate on the Magellan Pipeline Series B senior notes) and 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 set in arrears.

During October 2004, we entered into an interest rate swap agreement to hedge against changes in the fair value of a portion of the $250.0 million of senior notes due 2016. We have accounted for this interest rate hedge as a fair value hedge. The notional amount of the interest rate swap agreement is $100.0 million. Under the terms of the agreement, we receive 5.65% (the interest rate of the $250.0 million senior notes) and pay LIBOR plus 0.6%. This hedge effectively converts $100.0 million of our 5.65% fixed-rate debt to floating-rate debt. The interest rate swap agreement began on October 15, 2004 and expires on October 15, 2016. Payments settle in April and October of each year with LIBOR set in arrears.

As of March 31, 2006, we had entered into futures contracts, qualifying as normal purchases, for the purchase of approximately 0.3 million barrels of petroleum products. The notional value of these agreements, with maturities from April 2006 through November 2006, was approximately $21.8 million.

24

As of March 31, 2006, we had entered into futures contracts, qualifying as normal sales, for the sale of approximately 0.6 million barrels of petroleum products. The notional value of these agreements, with maturities from April 2006 through October 2006, was approximately $46.2 million.

In February 2006, we entered into a forward sales contract for 0.1 million barrels of gasoline we expect to produce from our petroleum products blending operations. These barrels will be sold at the Platts average price during September 2006. Concurrently, we entered into three derivative swap contracts to hedge against price changes associated with the sale of that product, in which we agreed to buy 0.1 million barrels of gasoline at the Platts average price in September 2006 and sell 0.1 million barrels of gasoline at the fixed price of $77.28 per barrel. Our objective in entering into this derivative was to lock in a gross margin on the expected sale of 0.1 million barrels of gasoline in September 2006.

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 and Chief 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 breakdowns can occur because of simple error or mistake. 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 no substantial changes in our internal controls since December 31, 2005.

FORWARD-LOOKING STATEMENTS

Certain matters discussed in this Quarterly Report on Form 10-Q include forward-looking statements that discuss our expected future results based on current and pending business operations.

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 future results to differ materially from actual results or from any projected, forecasted, estimated or budgeted amounts which we have discussed in this report:

• price fluctuations for natural gas liquids and refined petroleum products;

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

• weather patterns materially different than historical trends;

• development of alternative energy sources;

25

• changes in demand for storage in our petroleum products terminals;

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

• our ability to manage interest rate and commodity price exposures;

• our ability to satisfy our product purchase obligations at historical purchase terms;

• changes in our tariff rates implemented by the Federal Energy Regulatory Commission, the United States Surface Transportation Board and state regulatory agencies;

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

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

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

• an increase in the competition our operations encounter;

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

• the treatment of us as a corporation for federal income tax purposes or if we become subject to entity-level taxation for state tax purposes;

• our ability to make and integrate acquisitions and successfully complete our business strategy;

• changes in general economic conditions in the United States;

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

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

• 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;

• a change of control of our general partner could, under certain circumstances, result in our debt or the debt of our subsidiaries becoming due and payable;

• the condition of the capital markets in the United States;

• the effect of changes in accounting policies;

• the potential that internal controls may not be adequate, weaknesses may be discovered or remediation of any identified weaknesses may not be successful and the impact these could have on our unit price;

• Williams’ and other third-parties’ ability to pay the amounts owed to us under indemnification agreements;

• conflicts of interests between us, our general partner, MGG, MGG’s general partner and related parties of MGG and its general partner;

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

• supply disruption; and

26

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

PART II

OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

In July 2001, the 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 systematic problems with petroleum discharges from pipeline operations. That inquiry primarily focused on Magellan Pipeline, which we subsequently acquired. 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, which 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 releases 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 releases if the EPA were to successfully seek and obtain injunctive relief. We responded to the March 2004 information request in a timely manner and have entered into an agreement that provides both parties an opportunity to negotiate a settlement prior to initiating litigation. We have accrued an amount for this matter based on our best estimates that is less than $22.0 million. Due to the uncertainties described above, it is reasonably possible that the amounts we have recorded for this environmental liability could change in the near term. Management is unable to determine with any accuracy what those amounts could be and they could be material to our results of operations and cash flows.

During the second quarter of 2005, we experienced a product release involving approximately 2,900 barrels of gasoline from our petroleum products pipeline near our Kansas City, Kansas terminal. In regards to this release, we responded on a timely basis to an EPA request for information pursuant to Section 308 of the Act. We can provide no assurances that we will not be assessed civil or other statutory penalties of $100,000 or more by the EPA or other regulatory agencies associated with this release.

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 1A. RISK FACTORS

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2005, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K are not our only risks. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

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

None.

ITEM 5. OTHER INFORMATION

None.

27

ITEM 6. EXHIBITS

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 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.

28

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 May 9, 2006.

MAGELLAN MIDSTREAM PARTNERS, L.P.
By:	/s/ Magellan GP, LLC
	its General Partner

/s/ John D. Chandler

John D. Chandler

Chief Financial Officer

and Treasurer (Principal Accounting and Financial Officer)

29

INDEX TO EXHIBITS

EXHIBIT NUMBER	DESCRIPTION
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 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.

30