Edgar Filing: MAGELLAN MIDSTREAM PARTNERS LP

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Form 10-Q

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, 2009

¨	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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company.

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 5, 2009, there were 66,953,879 outstanding common units of Magellan Midstream Partners, L.P., that trade on the New York Stock Exchange under the ticker symbol “MMP.”


PART I
FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS		2
CONSOLIDATED STATEMENTS OF INCOME		2
CONSOLIDATED BALANCE SHEETS		3
CONSOLIDATED STATEMENTS OF CASH FLOWS		4
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS		5
1.	Organization and Basis of Presentation	5
2.	Accounting Policies—Allocation of Net Income and Earnings Per Unit	6
3.	Comprehensive Income	7
4.	Segment Disclosures	7
5.	Related Party Disclosures	8
6.	Inventory	9
7.	Employee Benefit Plans	10
8.	Debt	10
9.	Derivative Financial Instruments	11
10.	Commitments and Contingencies	14
11.	Long-Term Incentive Plan	15
12.	Distributions	17
13.	Assignment of Supply Agreement	18
14.	Simplification Agreement	18
15.	Reimbursable Costs	19
16.	Subsequent Events	19
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		20
Introduction		20
Recent Developments		20
Results of Operations		21
Liquidity and Capital Resources		24
Off-Balance Sheet Arrangements		26
Environmental		26
Other Items		26
New Accounting Pronouncements		28
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		30
ITEM 4. CONTROLS AND PROCEDURES		31
Forward-Looking Statements		32

PART II
OTHER INFORMATION

ITEM 1.	LEGAL PROCEEDINGS	34
ITEM 1A.	RISK FACTORS	34
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	37
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	37
ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	37
ITEM 5.	OTHER INFORMATION	37
ITEM 6.	EXHIBITS	37

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,
	2008			2009
Transportation and terminals revenues	$	144,592		$	154,888
Product sales revenues		201,718			57,716
Affiliate management fee revenues		183			190

Total revenues		346,493			212,794
Costs and expenses:
Operating		55,592			60,727
Product purchases		177,568			52,630
Depreciation and amortization		17,176			19,315
Affiliate general and administrative		17,780			20,525

Total costs and expenses		268,116			153,197
Gain on assignment of supply agreement		26,492			—
Equity earnings		405			519

Operating profit		105,274			60,116
Interest expense		12,936			15,549
Interest income		(293	)		(223	)
Interest capitalized		(1,302	)		(936	)
Debt placement fee amortization		168			220
Other income		—			(82	)

Income before provision for income taxes		93,765			45,588
Provision for income taxes		443			357

Net income	$	93,322		$	45,231


Allocation of net income:
Limited partners’ interest	$	73,763		$	22,921
General partner’s interest		19,559			22,310

Net income	$	93,322		$	45,231


Basic and diluted net income per limited partner unit	$	1.10		$	0.34

Weighted average number of limited partner units outstanding used for basic and diluted net income per limited partner unit calculation		66,772			67,074

See notes to consolidated financial statements.

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(In thousands)


	December 31, 2008			March 31, 2009
				(Unaudited)
ASSETS

Current assets:
Cash and cash equivalents	$	33,241		$	15,070
Accounts receivable (less allowance for doubtful accounts of $462 and $370 at December 31, 2008 and March 31, 2009, respectively)		37,517			42,055
Other accounts receivable		11,073			12,866
Affiliate accounts receivable		378			3,475
Inventory		47,734			65,825
Energy commodity derivative contracts		20,200			2,151
Reimbursable costs		8,176			11,767
Other current assets		7,264			10,328

Total current assets		165,583			163,537
Property, plant and equipment		2,724,326			2,768,348
Less: accumulated depreciation		674,317			691,442

Net property, plant and equipment		2,050,009			2,076,906
Equity investments		23,190			22,149
Long-term receivables		7,119			6,433
Goodwill		26,809			26,809
Other intangibles (less accumulated amortization of $8,290 and $8,761 at December 31, 2008 and March 31, 2009, respectively)		5,539			5,068
Debt placement costs (less accumulated amortization of $2,937 and $3,157 at December 31, 2008 and March 31, 2009, respectively)		7,649			7,429
Other noncurrent assets		10,217			8,913

Total assets	$	2,296,115		$	2,317,244


LIABILITIES AND PARTNERS’ CAPITAL

Current liabilities:
Accounts payable	$	39,441		$	42,872
Affiliate accounts payable		1,942			558
Affiliate payroll and benefits		18,119			15,408
Accrued interest payable		15,077			21,860
Accrued taxes other than income		20,151			18,448
Environmental liabilities		19,634			17,595
Deferred revenue		21,492			24,248
Accrued product purchases		23,874			40,229
Energy commodity derivatives deposit		18,994			—
Other current liabilities		16,534			19,881

Total current liabilities		195,258			201,099
Long-term debt		1,083,485			1,125,089
Long-term affiliate payable		445			469
Long-term affiliate pension and benefits		31,787			33,872
Other deferred liabilities		7,532			6,404
Environmental liabilities		22,166			21,681
Commitments and contingencies
Partners’ capital:
Partners’ capital		978,046			950,941
Accumulated other comprehensive loss		(22,604	)		(22,311	)

Total partners’ capital		955,442			928,630

Total liabilities and partners’ capital	$	2,296,115		$	2,317,244

See notes to consolidated financial statements.

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, in thousands)


	Three Months Ended March 31,
	2008			2009
Operating Activities:
Net income	$	93,322		$	45,231
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		17,176			19,315
Debt placement fee amortization expense		168			220
Loss on sale and retirement of assets		103			1,253
Equity earnings		(405	)		(519	)
Distributions from equity investment		1,300			1,550
Equity-based incentive compensation expense		1,484			3,217
Amortization of prior service cost and actuarial loss		377			334
Gain on assignment of supply agreement		(26,492	)		—
Changes in operating assets and liabilities:
Accounts receivable and other accounts receivable		8,484			(6,331	)
Affiliate accounts receivable		(684	)		(3,097	)
Inventory		20,267			(18,091	)
Energy commodity derivative contracts, net of margin deposit		—			(5,211	)
Reimbursable costs		332			(3,591	)
Accounts payable		(6,348	)		3,732
Affiliate accounts payable		(2,873	)		364
Affiliate payroll and benefits		(10,166	)		(2,711	)
Accrued interest payable		11,632			6,783
Accrued taxes other than income		(2,296	)		(1,703	)
Accrued product purchases		6,591			16,355
Supply agreement deposit		(18,500	)		—
Current and noncurrent environmental liabilities		(131	)		(2,524	)
Other current and noncurrent assets and liabilities		2,543			7,560

Net cash provided by operating activities		95,884			62,136
Investing Activities:
Property, plant and equipment:
Additions to property, plant and equipment		(54,882	)		(47,585	)
Proceeds from sale of assets		909			—
Changes in accounts payable		(4,497	)		(301	)
Acquisition of business		(12,010	)		—

Net cash used by investing activities		(70,480	)		(47,886	)
Financing Activities:
Distributions paid		(63,793	)		(71,015	)
Net borrowings under revolver		33,500			42,000
Capital contributions by affiliate		1,637			408
Simplification of capital structure		—			(2,854	)
Increase in outstanding checks		3,252			2,490
Settlement of tax withholdings on long-term incentive compensation		—			(3,450	)

Net cash used by financing activities		(25,404	)		(32,421	)

Change in cash and cash equivalents		—			(18,171	)
Cash and cash equivalents at beginning of period		—			33,241

Cash and cash equivalents at end of period	$	—		$	15,070

Supplemental non-cash financing transactions:
Issuance of common units in settlement of long-term incentive plan awards	$	8,536		$	1,943

See notes to consolidated financial statements.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.	Organization and Basis of Presentation

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, and our units are traded on the New York Stock Exchange under the ticker symbol “MMP.” Magellan GP, LLC, a Delaware limited liability company, serves as our general partner and owns an approximate 2% general partner interest in us as well as all of our incentive distribution rights. Magellan GP, LLC is a wholly-owned subsidiary of Magellan Midstream Holdings, L.P., a publicly traded Delaware limited partnership. We and Magellan GP, LLC have contracted with Magellan Midstream Holdings GP, LLC to provide all general and administrative (“G&A”) services and operating functions required for our operations. Our organizational structure at March 31, 2009 and that of our affiliate entities, as well as how we refer to these affiliates in our notes to consolidated financial statements, is provided below.

LOGO

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 marketing strategies and business knowledge.

In the opinion of management, our accompanying consolidated financial statements, which are unaudited except for the consolidated balance sheet as of December 31, 2008, which is derived from audited financial statements, include all normal and recurring adjustments necessary to present fairly our financial position as of March 31, 2009, and the results of operations and cash flows for the three months ended March 31, 2008 and 2009. The results of operations for the three months ended March 31, 2009 are not necessarily indicative of the results to be expected for the full year ending December 31, 2009.

Pursuant to the rules and regulations of the Securities and Exchange Commission, the financial statements in this report 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, 2008.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2.	Accounting Policies—Allocation of Net Income and Earnings Per Unit

On January 1, 2009, we adopted Emerging Issues Task Force (“EITF”) Issue No. 07-4, Application of the Two-Class method under FASB Statement No. 128, Earnings Per Share, to Master Limited Partnerships. Under EITF No. 07-4, the excess of distributions over earnings or excess of earnings over distributions for each period are allocated to the entities’ general partner based on the general partner’s ownership interest at the time. We have retrospectively applied the provisions of EITF No. 07-4 to the three months ended March 31, 2008. Until January 1, 2009, our accounting practice, for purposes of calculating earnings per unit, was to allocate net income to the general partner based on the general partner’s share of total or pro forma distributions, as applicable, including incentive distribution rights.

Under EITF No. 07-4, for the accounting periods included in this report, the allocation of net income between our general partner and limited partners was as follows (in thousands, except percentages):


	Three Months Ended March 31,
	2008			2009
Net income	$	93,322		$	45,231
Direct charges to the general partner:
Reimbursable G&A costs		408			—
Previously indemnified environmental charges		1,529			670

Total direct charges to general partner		1,937			670

Income before direct charges to general partner		95,259			45,901
Less: Distributions paid for the quarter		65,795			71,015

Undistributed income / (distributions in excess of income)	$	29,464		$	(25,114	)


Ownership interests:
Limited partners		98.011	%		98.017	%
General partner		1.989	%		1.983	%

Total ownership interests		100.000	%		100.000	%


Allocation of net income:
Limited partner allocation:
Allocation of undistributed income / (distributions in excess of income)	$	28,878		$	(24,616	)
Cash distributions paid for the quarter		44,885			47,537

Net income allocated to limited partners	$	73,763		$	22,921


General partner allocation:
Allocation of undistributed income / (distributions in excess of income)	$	586		$	(498	)
Cash distributions paid for the quarter		20,910			23,478
Direct charges to general partner		(1,937	)		(670	)

Net income allocated to general partner	$	19,559		$	22,310


Limited partners’ allocation of net income	$	73,763		$	22,921
General partner’s allocation of net income		19,559			22,310

Net income	$	93,322		$	45,231

The reimbursable G&A costs above represent G&A expenses charged against our income during the periods presented that were required to be reimbursed to us by our general partner under the terms of an omnibus agreement between us and MGG GP. Because the limited partners do not share in these costs, we have allocated these G&A expense amounts directly to our general partner. We recorded these reimbursements by our general partner as capital contributions. Prior to 2008, we and our general partner entered into an agreement with a former affiliate to settle certain of our former affiliate’s indemnification obligations to us. Under this agreement, our former affiliate paid us $117.5 million, which we recorded as a capital contribution from our general partner. Current period costs associated with this indemnification agreement settlement are designated as “previously indemnified environmental charges.” Since our limited partners do not share in these costs, we have allocated these amounts directly to our general partner.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The difference between the amounts of net income allocated to the limited and general partners and the related earnings per unit calculations under EITF No. 07-4 and our previous accounting methodology for the three months ended March 31, 2008 is provided in the table below (in thousands):


	(in thousands, except per unit amounts)
	Current Accounting Under EITF 07-4		As Previously Reported		Difference
Three Months Ended March 31, 2008
Net income allocated to limited partners	$	73,763	$	59,620	$	14,143
Net income allocated to general partner		19,559		33,702		(14,143	)

Net income	$	93,322	$	93,322	$	—


Basic and diluted net income per limited partner unit	$	1.10	$	0.89	$	0.21

Weighted average number of limited partner units outstanding used for basic and diluted net income per unit calculation		66,772		66,772		—

3.	Comprehensive Income

Comprehensive income is the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from nonowner sources. Comprehensive income includes all changes in equity during a period except those resulting from investments by and distributions to owners. The term other comprehensive income or other comprehensive loss refers to revenues, expenses, gains and losses that, under generally accepted accounting principles (“GAAP”), are included in comprehensive income but excluded from net income. A reconciliation of net income to comprehensive income follows below (in thousands). For information on all of our derivative instruments, see Note 9 – Derivative Financial Instruments.


	Three Months Ended March 31,
	2008			2009
Net income	$	93,322		$	45,231
Change in fair value of cash flow hedges		(6,706	)		—
Amortization of net gain on cash flow hedges		(41	)		(41	)
Amortization of prior service cost and actuarial loss		377			334

Other comprehensive income (loss)		(6,370	)		293

Comprehensive income	$	86,952		$	45,524

4.	Segment Disclosures

Our reportable segments are strategic business units that offer different products and services. Our segments are managed separately because each segment requires different marketing strategies and business knowledge. Management evaluates performance based on segment operating margin, which includes revenues from affiliates and external customers, operating expenses, product purchases and equity earnings. Transactions between our business segments are conducted and recorded on the same basis as transactions with third-party entities.

We believe that investors benefit from having access to the same financial measures being used by management. Operating margin, which is presented in the tables below, is an important measure used by management to evaluate 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 margin is not a GAAP measure, but the components of operating margin are

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 tables below. Operating profit includes expense items, such as depreciation and amortization and affiliate G&A expenses, that management does not consider when evaluating the core profitability of our operations.


	Three Months Ended March 31, 2008
	(in thousands)
	Petroleum Products Pipeline System			Petroleum Products Terminals		Ammonia Pipeline System			Intersegment Eliminations			Total
Transportation and terminals revenues	$	106,323		$	33,601	$	5,420		$	(752	)	$	144,592
Product sales revenues		192,897			8,821		—			—			201,718
Affiliate management fee revenue		183			—		—			—			183

Total revenues		299,403			42,422		5,420			(752	)		346,493
Operating expenses		42,260			12,529		2,254			(1,451	)		55,592
Product purchases		174,621			3,077		—			(130	)		177,568
Gain on assignment of supply agreement		(26,492	)		—		—			—			(26,492	)
Equity earnings		(405	)		—		—			—			(405	)

Operating margin		109,419			26,816		3,166			829			140,230
Depreciation and amortization expense		10,381			5,764		202			829			17,176
Affiliate G&A expenses		12,741			4,115		924			—			17,780

Operating profit	$	86,297		$	16,937	$	2,040		$	—		$	105,274


	Three Months Ended March 31, 2009
	(in thousands)
	Petroleum Products Pipeline System			Petroleum Products Terminals		Ammonia Pipeline System			Intersegment Eliminations			Total
Transportation and terminals revenues	$	114,769		$	38,153	$	3,229		$	(1,263	)	$	154,888
Product sales revenues		54,232			3,484		—			—			57,716
Affiliate management fee revenue		190			—		—			—			190

Total revenues		169,191			41,637		3,229			(1,263	)		212,794
Operating expenses		43,955			15,384		3,118			(1,730	)		60,727
Product purchases		51,588			1,536		—			(494	)		52,630
Equity earnings		(519	)		—		—			—			(519	)

Operating margin		74,167			24,717		111			961			99,956
Depreciation and amortization expense		11,275			6,804		275			961			19,315
Affiliate G&A expenses		14,848			5,069		608			—			20,525

Operating profit (loss)	$	48,044		$	12,844	$	(772	)	$	—		$	60,116

5.	Related Party Disclosures

Affiliate Entity Transactions

We own a 50% interest in a crude oil pipeline company and are paid a management fee for its operation. During each of the three months ended March 31, 2008 and 2009, we received operating fees from this pipeline company of $0.2 million, which we reported as affiliate management fee revenue.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table summarizes affiliate costs and expenses that are reflected in the accompanying consolidated statements of income (in thousands):


	Three Months Ended March 31,
	2008		2009
MGG GP - allocated operating expenses	$	20,920	$	22,676
MGG GP - allocated G&A expenses	$	11,873	$	13,167

Under our services agreement with MGG GP, we reimburse MGG GP for costs of employees necessary to conduct our operations. The affiliate payroll and benefits accruals associated with this agreement at December 31, 2008 and March 31, 2009 were $18.1 million and $15.4 million, respectively, and the long-term affiliate pension and benefits accruals associated with this agreement at December 31, 2008 and March 31, 2009 were $31.8 million and $33.9 million, respectively. We settle our affiliate payroll, payroll-related expenses and non-pension postretirement benefit costs with MGG GP on a monthly basis. We settle our long-term affiliate pension liabilities through payments to MGG GP when MGG GP makes contributions to its pension funds.

Historically, MGG reimbursed us for G&A expenses (excluding equity-based compensation) in excess of a G&A cap. The amount of G&A costs required to be reimbursed by MGG to us under this agreement was $0.4 million for the three months ended March 31, 2008. We have not received and will not receive any reimbursements under this agreement for excess G&A costs for 2009 and beyond.

Other Related Party Transactions

One of our general partner’s former independent board members, John P. DesBarres, served as a board member for American Electric Power Company, Inc. (“AEP”) of Columbus, Ohio until December 2008. For the three months ended March 31, 2008, our operating expenses included $0.6 million of power costs incurred with Public Service Company of Oklahoma (“PSO”), which is a subsidiary of AEP. We had no amounts payable to or receivable from PSO or AEP at March 31, 2008.

Because our distributions have exceeded target levels as specified in our partnership agreement, our general partner receives approximately 50% of any incremental cash distributed per limited partner unit. As of March 31, 2009, our executive officers collectively owned a beneficial interest of approximately 1% of MGG, the owner of our general partner. Therefore, our executive officers benefit from distributions paid to our general partner. 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 $0.71 per unit, our general partner would receive annual distributions of approximately $93.9 million on its combined general partner interest and incentive distribution rights.

6.	Inventory

Inventory at December 31, 2008 and March 31, 2009 was as follows (in thousands):


	December 31, 2008		March 31, 2009
Refined petroleum products	$	20,917	$	22,484
Transmix		13,099		21,101
Natural gas liquids		7,534		14,472
Additives		6,184		7,768

Total inventory	$	47,734	$	65,825

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7.	Employee Benefit Plans

MGG GP sponsors two pension plans for certain union employees, a pension plan for certain non-union employees, a postretirement benefit plan for selected employees and a defined contribution plan. The following table presents our consolidated net periodic benefit costs related to the pension plans and other postretirement benefit plan during the three months ended March 31, 2008 and 2009 (in thousands):


	Three Months Ended March 31, 2008					Three Months Ended March 31, 2009
	Pension Benefits			Other Post- Retirement Benefits		Pension Benefits			Other Post- Retirement Benefits
Components of net periodic benefit costs:
Service cost	$	1,413		$	141	$	1,389		$	116
Interest cost		654			278		784			279
Expected return on plan assets		(619	)		—		(686	)		—
Amortization of prior service cost		169			44		169			44
Amortization of actuarial loss		16			148		57			64

Net periodic benefit cost	$	1,633		$	611	$	1,713		$	503

Debt

Our debt at December 31, 2008 and March 31, 2009 was as follows (in thousands):


	December 31, 2008		March 31, 2009		Weighted-Average Interest Rate at March 31, 2009 (1)
Revolving credit facility	$	70,000	$	112,000	1.0%
6.45% Notes due 2014		249,681		249,693	6.3%
5.65% Notes due 2016		253,328		253,220	5.7%
6.40% Notes due 2018		261,555		261,251	5.9%
6.40% Notes due 2037		248,921		248,925	6.3%

Total debt	$	1,083,485	$	1,125,089

(1)	Weighted-average interest rate includes the impact of the amortization of discounts and gains and losses realized on various cash flow hedges (see Note 9—Derivative Financial Instruments for detailed information regarding the amortization of these gains and losses).

Our debt is non-recourse to our general partner.

Revolving Credit Facility. The total borrowing capacity under our revolving credit facility, which matures in September 2012, is $550.0 million. Borrowings under the facility are unsecured and bear interest at LIBOR plus a spread ranging from 0.3% to 0.8% based on our credit ratings and amounts outstanding under the facility. Additionally, a commitment fee is assessed at a rate from 0.05% to 0.125%, depending on our credit ratings. Borrowings under this facility are used primarily for general purposes, including capital expenditures. As of March 31, 2009, $112.0 million was outstanding under this facility, and $3.9 million was obligated for letters of credit. Amounts obligated for letters of credit are not reflected as debt on our consolidated balance sheets.

6.45% Notes due 2014. In May 2004, we sold $250.0 million aggregate principal of 6.45% notes due 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.

5.65% Notes due 2016. In October 2004, we issued $250.0 million of 5.65% notes due 2016 in an underwritten public offering. 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. The outstanding principal amount of the notes was increased by $3.5 million and $3.4 million at December 31, 2008 and March 31, 2009, respectively, for the unamortized portion of a gain realized upon termination of a related interest rate swap (see Note 9—Derivative Financial Instruments).

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6.40% Notes due 2018. In July 2008, we issued $250.0 million of 6.40% notes due 2018 in an underwritten public offering. The outstanding principal amount of the notes was increased by $11.7 million and $11.3 million at December 31, 2008 and March 31, 2009, respectively, for the unamortized portion of gains realized upon termination or discontinuation of hedge accounting treatment of associated interest rate swaps (see Note 9—Derivative Financial Instruments).

6.40% Notes due 2037. In April 2007, we issued $250.0 million of 6.40% notes due 2037 in an underwritten public offering. The notes were issued for the discounted price of 99.6%, or $248.9 million, and the discount is being accreted over the life of the notes.

9.	Derivative Financial Instruments

Commodity Derivatives

Our petroleum products blending activities generate gasoline products and we can estimate the timing and quantities of sales of these products. We use forward sales contracts to lock in forward sales prices and most of the gross margins realized from our blending activities related to these contracts. We account for these forward sales contracts as normal sales.

In addition to forward sales contracts, we use New York Mercantile Exchange (“NYMEX”) contracts to lock in forward sales prices. Although these NYMEX contracts represent an economic hedge against price changes on the petroleum products we expect to sell in the future, they do not qualify as normal sales or for hedge accounting treatment under Statement of Financial Accounting Standard (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities (as amended); therefore, we recognize the change in fair value of these contracts currently in earnings. During first quarter 2009, we closed our positions on NYMEX contracts associated with the sale of 0.6 million barrels of gasoline and realized total gains of $14.8 million, a majority of which was recorded to earnings in the third and fourth quarters of 2008 through mark-to-market valuations of these contracts. At March 31, 2009, the fair value of our open NYMEX contracts, representing 0.8 million barrels of petroleum products, was a net gain of $1.8 million, of which $2.1 million was recorded as energy commodity derivative contracts and $(0.3) million was recorded as other current liabilities on our consolidated balance sheet. These open NYMEX contracts mature between April 2009 and December 2009. At March 31, 2009, we had made deposits of $4.3 million in margin cash for these contracts, which was included in other current assets on our consolidated balance sheet.

Interest Rate Derivatives

We use interest rate derivatives to help manage interest rate risk. As of March 31, 2009, we had two offsetting interest rate swap agreements outstanding:

•

In July 2008, we entered into a $50.0 million interest rate swap agreement (“Derivative A”) to hedge against changes in the fair value of a portion of the $250.0 million of 6.40% notes due 2018. Derivative A effectively converted $50.0 million of those notes from a 6.40% fixed rate to a floating rate of six-month LIBOR plus 1.83%. Derivative A terminates in July 2018. We originally accounted for Derivative A as a fair value hedge. On December 8, 2008, in order to capture the economic value of Derivative A at that time, we entered into an offsetting derivative, as described below, and discontinued hedge accounting. The $5.4 million fair value of Derivative A at that time was recorded as an adjustment to long-term debt which is being amortized over the remaining life of the 6.40% fixed-rate notes due 2018. For the three months ended March 31, 2009, a loss of $0.8 million was recorded to other income on our consolidated statement of income resulting from the change in fair value of Derivative A.

•

In December 2008, concurrent with the discontinuance of hedge accounting for Derivative A, we entered into an offsetting $50.0 million interest rate swap agreement with a different financial institution pursuant to which we pay a fixed rate of 6.40% and receive a floating rate of six-month LIBOR plus 3.23%. This agreement terminates in July 2018. We entered into this agreement to offset changes in the fair value of Derivative A, excluding changes due to changes in counterparty credit risks. We did not designate this agreement as a hedge for accounting purposes. For the three months ended March 31, 2009, a gain of $0.9 million was recorded to other income on our consolidated statement of income resulting from the change in fair value of this agreement.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following is a summary of the current impact of our historical derivative activity on accumulated other comprehensive loss (“AOCL”) as of and for the three months ended March 31, 2008 and 2009 (in thousands):


				Effective Portion of Gains
				As of March 31, 2008			Three Months Ended March 31, 2008			As of March 31, 2009			Three Months Ended March 31, 2009
Hedge	Total Gain (Loss) Realized on Settlement of Hedge			Unamortized Amount Recognized in AOCL			Amount Reclassified to Interest Expense from AOCL			Unamortized Amount Recognized in AOCL			Amount Reclassified to Interest Expense from AOCL
Cash flow hedges (date executed):
Interest rate swaps 6.40% Notes (April 2007)	$	5,255		$	5,088		$	(44	)	$	4,913		$	(44	)
Interest rate swaps 5.65% Notes (October 2004)		(6,279	)		(4,469	)		131			(3,946	)		131
Interest rate swaps and treasury lock 6.45% Notes (May 2004)		5,119			3,157			(128	)		2,645			(128	)

Total cash flow hedges				$	3,776		$	(41	)	$	3,612		$	(41	)

There was no ineffectiveness recognized on the financial instruments disclosed in the above tables during the three months ended March 31, 2008 and 2009. As of March 31, 2009, the net gain estimated to be reclassified to interest expense over the next twelve months from AOCL is less than $0.1 million.

The changes in derivative gains (losses) included in AOCL for the three months ended March 31, 2008 and 2009 are as follows (in thousands):


	Three Months Ended March 31,
Derivative Gains (Losses) Included in AOCL	2008			2009
Beginning balance	$	3,817		$	3,653
Change in fair value of cash flow hedges		(6,706	)		—
Amortization of net gain on cash flow hedges		(41	)		(41	)

Ending balance	$	(2,930	)	$	3,612

The following is a summary of the current impact of our historical derivative activity on long-term debt resulting from the termination of or the discontinuance of hedge accounting treatment of our fair value hedges as of and for the three months ended March 31, 2009 (in thousands):


			As of March 31, 2009		Three Months Ended March 31, 2009
Hedge	Total Gain Realized		Unamortized Amount Recorded in Long-term Debt		Amount Reclassified to Interest Expense from Long-term Debt
Fair value hedges (date executed):
Interest rate swaps 6.40% Notes (July 2008)	$	11,652	$	11,270	$	(304	)
Interest rate swap 5.65% Notes (October 2004)		3,830		3,434		(114	)

Total fair value hedges			$	14,704	$	(418	)

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following is a summary of the effect of derivatives accounted for under SFAS No. 133 that are not designated as hedging instruments on our consolidated statement of income for the three months ended March 31, 2009 (in thousands):


Derivative Instrument	Location of Gain (Loss) Recognized on Derivative	Amount of Gain (Loss) Recognized on Derivative
Interest rate swap agreements	Other income	$	82
NYMEX commodity contracts	Product sales revenues		(3,537	)

Total		$	(3,455	)

The following is a summary of the fair value of derivatives accounted for under SFAS No. 133 that are not designated as hedging instruments as of March 31, 2009 (in thousands):


	Asset Derivatives			Liability Derivatives
Derivative Instrument	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Interest rate swap agreements, current portion	Other current assets	$	333	Other current liabilities	$	178
Interest rate swap agreements, noncurrent portion	Other noncurrent assets		6,031	Other deferred liabilities		677
NYMEX commodity contracts	Energy commodity derivative contracts		2,151	Other current liabilities		334

Total		$	8,515		$	1,189

Fair Value Measurements

The following tables summarize the fair value measurements of our NYMEX commodity contracts and interest rate swap agreements as of December 31, 2008 and March 31, 2009, based on the three levels established by SFAS No. 157, Fair Value Measurements (in thousands):


				Asset Fair Value Measurements as of December 31, 2008 using:
	Total			Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
NYMEX commodity contracts	$	20,200		$	20,200		$	—		$	—
Interest rate swap agreements (date executed):
$50.0 million (July 2008)		7,542			—			7,542			—
$50.0 million (December 2008)		(1,770	)		—			(1,770	)		—

				Asset Fair Value Measurements as of March 31, 2009 using:
	Total			Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
NYMEX commodity contracts:
Asset derivatives	$	2,151		$	2,151			—			—
Liability derivatives		(334	)		(334	)		—			—
Interest rate swap agreements (date executed):
$50.0 million (July 2008)		6,364			—			6,364			—
$50.0 million (December 2008)		(855	)		—			(855	)		—

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10.

Commitments and Contingencies

Environmental Liabilities. Liabilities recognized for estimated environmental costs were $41.8 million and $39.3 million at December 31, 2008 and March 31, 2009, respectively. Environmental liabilities 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 liabilities will be paid over the next ten years. Environmental expenses recognized as a result of changes in our environmental liabilities are included in operating expenses on our consolidated statements of income. Environmental expense was $2.8 million and $1.3 million for the three months ended March 31, 2008 and 2009, respectively.

Our environmental liabilities included, among other items, accruals for an ammonia Environmental Protection Agency (“EPA”) issue. In February 2007, we received notice from the Department of Justice (“DOJ”) that the EPA had requested the DOJ to initiate a lawsuit alleging violations of Sections 301 and 311 of the Clean Water Act (“the Act”) with respect to two releases of anhydrous ammonia from our ammonia pipeline system that was operated by a third party at the time of the releases. The DOJ stated that the maximum statutory penalty for alleged violations of the Act for both releases combined was approximately $13.2 million. The DOJ also alleged that the third-party operator of our ammonia pipeline was liable for penalties pursuant to Section 103 of the Comprehensive Environmental Response, Compensation and Liability Act for failure to report the releases on a timely basis, with the statutory maximum for those penalties as high as $4.2 million for which the third-party operator has requested indemnification. In March 2007, we also received a demand from the third-party operator for defense and indemnification in regards to a DOJ criminal investigation regarding whether certain actions or omissions of the third-party operator constituted violations of federal criminal statutes. The third-party operator has subsequently settled this criminal investigation with the DOJ by paying a $1.0 million fine. The DOJ stated in its notice to us that it does not expect us or the third-party operator to pay the penalties at the statutory maximum; however, it may seek injunctive relief if the parties cannot agree on any necessary corrective actions. We have accrued an amount for these matters based on our best estimates that is less than the maximum statutory penalties. We are currently in discussions with the EPA, DOJ and the third-party operator regarding these two releases. Adjustments to our recorded liability, which could occur in the near term, could be material to our results of operations and cash flows.

Environmental Receivables. Receivables from insurance carriers related to environmental matters were $4.5 million and $3.9 million at December 31, 2008 and March 31, 2009, respectively.

Unrecognized Product Gains. Our petroleum products terminals operations generate product overages and shortages that result from metering inaccuracies, product evaporation or expansion, product releases and product contamination. Most of the contracts we have with our customers state that we bear the risk of loss (or gain) from these conditions. When our petroleum products terminals experience net product shortages, we recognize expense for those losses in the periods in which they occur. When our petroleum products terminals experience net product overages, we have product on hand for which we have no cost basis. Therefore, these net overages are not recognized in our financial statements until the associated barrels are either sold or used to offset product losses. The net unrecognized product overages for our petroleum products terminals operations had a market value of approximately $3.3 million as of March 31, 2009. 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 these 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 financial position, results of operations or cash flows.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11.

Long-Term Incentive Plan

Plan Description

We have a long-term incentive plan (“LTIP”) for certain MGG GP employees who perform services for us and for directors of our general partner. The LTIP primarily consists of phantom units and permits the grant of awards covering an aggregate of 3.2 million limited partner units. The remaining units available under the LTIP at March 31, 2009 total 1.3 million. The compensation committee of our general partner’s board of directors (the “Compensation Committee”) administers the LTIP and has approved the unit awards discussed below:

Vested Unit Awards


Grant Date	Unit Awards Granted	Forfeitures	Adjustments to Unit Awards for Attaining Above- Target Financial Results	Units Paid Out on Vesting Date	Vesting Date	Value of Unit Awards on Vesting Date (Millions)
February 2005	160,640	11,348	149,292	298,584	12/31/07	$	12.9
June 2006	1,170	—	1,170	2,340	12/31/07	$	0.1
February 2006	168,105	13,730	154,143	308,518	12/31/08	$	9.3
Various 2006	9,201	2,640	6,561	13,122	12/31/08	$	0.4
March 2007	2,640	—	—	2,640	12/31/08	$	0.1

In January 2008, we settled the cumulative amounts of the February 2005 and June 2006 award grants by issuing 196,856 limited partner units and distributing those units to the participants. The difference between the limited partner units issued to the participants and the total units accrued for represented the minimum tax withholdings associated with this award settlement. We paid associated tax withholdings and employer taxes totaling $5.1 million in January 2008.

In January 2009, we settled the cumulative amounts of the remaining 2006 and March 2007 award grants by issuing 209,321 limited partner units and distributing those units to the participants. The difference between the limited partner units issued to the participants and the total units accrued for represented the minimum tax withholdings associated with this award settlement. We paid associated tax withholdings and employer taxes totaling $4.0 million in January 2009.

Performance-Based Unit Awards

The incentive awards discussed below are subject to forfeiture if employment is terminated for any reason other than 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 award grant is prorated based upon the completed months of employment during the vesting period and the award is settled at the end of the vesting period. Our agreement with the LTIP participants requires the LTIP awards described below to be paid out in our common limited partner units. The award grants do not have an early vesting feature except under certain circumstances following a change in control of our general partner.

On December 3, 2008, MGG purchased its general partner from MGG MH. When this transaction closed, a change in control occurred as defined in our LTIP. Even though a change in control has occurred, participants in the LTIP must resign voluntarily for good reason or be terminated involuntarily for other than performance reasons within two years of December 3, 2008 in order to receive enhanced LTIP payouts.

For each of the award grants listed below, the payout calculation for 80% of the unit awards will be based solely on the attainment of a financial metric established by the Compensation Committee. This portion of the award grants has been accounted for as equity. The payout calculation for the remaining 20% of the unit awards will be based on both the attainment of a financial metric and the individual employee’s personal performance as determined by the Compensation Committee. This portion of the award grants has been accounted for as a liability.

The table below summarizes the performance based unit awards granted by the Compensation Committee that have not vested as of March 31, 2009. There was no impact to our cash flows associated with these award grants for the periods presented in this report.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


Grant Date	Unit Awards Granted	Estimated Forfeitures	Adjustment to Unit Awards in Anticipation of Achieving Above/ (Below) Target Financial Results		Total Unit Award Accrual	Vesting Date	Unrecognized Compensation Expense (Millions) (1)		Intrinsic Value of Unvested Awards at March 31, 2009 (Millions)
2007 awards:
Tranche 1:	53,230	1,597	51,633		103,266	12/31/09	$	0.8	$	3.0
Tranche 2:	53,230	1,597	(40,430	)	11,203	12/31/09		0.1		0.3
Tranche 3:	53,230	1,597	21,535		73,168	12/31/09		1.7		2.1
2008 awards	189,832	5,695	—		184,137	12/31/10		2.9		5.4
2009 awards	275,194	8,257	—		266,937	12/31/11		4.9		7.8

Total	624,716	18,743	32,738		638,711		$	10.4	$	18.6

(1)	Unrecognized compensation expense will be recognized over the remaining vesting periods of the awards.

The unit awards approved during 2007 are broken into three equal tranches, with each tranche vesting on December 31, 2009. We began accruing for Tranche 1 in the first quarter of 2007, Tranche 2 in the first quarter of 2008 and Tranche 3 in the first quarter of 2009, when the Compensation Committee established the financial metric associated with each respective tranche. The unit awards allocated to each tranche are expensed over their respective vesting periods. As of March 31, 2009, the accruals for the payout of Tranches 1, 2 and 3 were 200%, 22% and 142%, respectively.

At its February 2009 meeting, the Compensation Committee adjusted the threshold, target and stretch performance levels for the 2008 awards to reflect the downturn in the economic environment in which we now operate. The Compensation Committee felt that the modifications were necessary to ensure that the motivational and retention features of the awards remain potent in the current economic environment and maintain the link necessary to encourage our key employees to maximize our long-term financial results. At December 31, 2008, the accrual for the payout of the 2008 awards was 30%. As a result of the adjustment made by the Compensation Committee to the 2008 performance metric, the accrual for the payout of the adjusted 2008 unit awards at March 31, 2009 was 100%.

Retention Awards

The retention awards below are subject to forfeiture if employment is terminated or the employee resigns from their current position for any reason prior to the applicable vesting date. The award grants do not have an early vesting feature. The award grants listed below have been accounted for as equity.


Grant Date	Unit Awards Granted	Estimated Forfeitures	Total Unit Award Accrual	Vesting Date	Unrecognized Compensation Expense (Millions) (1)		Intrinsic Value of Unvested Awards at March 31, 2009 (Millions)
Various	14,248	428	13,820	12/31/10	$	0.3	$	0.4
Various	41,688	1,876	39,812	12/31/11		0.7		1.2

	55,936	2,304	53,632		$	1.0	$	1.6

(1)	Unrecognized compensation expense will be recognized over the remaining vesting periods of the awards.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Fair Value of Unit Awards


	2007 Awards		2008 Awards		2009 Awards		Retention Awards
Weighted-average per unit grant date fair value of equity awards (a)	$	32.20	$	27.77	$	19.60	$	24.08
March 31, 2009 per unit fair value of liability awards (b)	$	27.24	$	24.39	$	21.43		n/a

(a)	Except for the retention awards, approximately 80% of the unit awards are accounted for as equity. Fair value is calculated as our unit price on the grant date less the present value of estimated cash distributions during the vesting period.

(b)	Approximately 20% of the unit awards are accounted for as liabilities. Fair value is calculated as our unit price at the end of each accounting period less the present value of estimated cash distributions during the remaining portion of the vesting period.

Compensation Expense Summary

Our equity-based incentive compensation expense is summarized as follows (in thousands):


	Three Months Ended
	March 31, 2008						March 31, 2009
	Equity Method		Liability Method		Total		Equity Method		Liability Method		Total
2005 awards	$	—	$	26	$	26	$	—	$	—	$	—
2006 awards		475		175		650		—		—		—
2007 awards		376		80		456		934		195		1,129
2008 awards		268		64		332		1,256		292		1,548
2009 awards		—		—		—		349		95		444
Retention awards		20				20		96		—		96

Total	$	1,139	$	345	$	1,484	$	2,635	$	582	$	3,217

12.

Distributions

We paid the following distributions during 2008 and 2009 (in thousands, except per unit amounts):


Date Cash Distribution Paid	Per Unit Cash Distribution Amount		Common Units		General Partner		Total Cash Distribution
02/14/08	$	0.6575	$	43,884	$	19,909	$	63,793
05/15/08		0.6725		44,885		20,910		65,795
08/14/08		0.6875		45,886		21,911		67,797
11/14/08		0.7025		46,887		22,912		69,799

Total	$	2.7200	$	181,542	$	85,642	$	267,184


02/13/09	$	0.7100	$	47,537	$	23,478	$	71,015
05/15/09(a)		0.7100		47,537		23,478		71,015

Total	$	1.4200	$	95,074	$	46,956	$	142,030

(a)	Our general partner declared this cash distribution in April 2009 to be paid on May 15, 2009 to unitholders of record at the close of business on May 5, 2009.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13.

Assignment of Supply Agreement

As part of our acquisition of a pipeline system in October 2004, we assumed a third-party supply agreement. Under this agreement, we were obligated to supply petroleum products to one of our customers until 2018. At the time of this acquisition, we believed that the profits we would receive from the supply agreement were below the fair value of our tariff-based shipments on this pipeline and we established a liability for the expected shortfall. On March 1, 2008, we assigned this supply agreement and sold related inventory of $47.6 million to a third-party entity. Further, we returned our former customer’s cash deposit, which was $16.5 million at the time of the assignment. During first quarter 2008, we obtained a full release from the supply customer; therefore, we had no future obligation to perform under this supply agreement, even in the event the third-party assignee was unable to perform its obligations under the agreement. As a result, we wrote off the unamortized amount of the liability and recognized a gain of $26.5 million.

14.

Simplification Agreement

In March 2009, we and our general partner and MGG and its general partner entered into an Agreement Relating to Simplification of Capital Structure (the “Simplification Agreement”). Pursuant to the Simplification Agreement, we will amend and restate our existing partnership agreement to provide for the transformation of the incentive distribution rights and approximate 2% general partner interest owned by MMP GP, our general partner, into common units in us and a non-economic general partner interest (the “transformation”). Once the transformation is complete, MMP GP, MGG’s wholly-owned subsidiary, will distribute the common units in us that it receives in the transformation to MGG (the “unit distribution”). Once the transformation and unit distribution are complete, pursuant to a Contribution and Assumption Agreement among MGG, MGG MH (MGG’s general partner), us and MMP GP (our general partner): (i) MGG will contribute 100% of its member interests in its general partner to our general partner; (ii) MGG will contribute 100% of the member interests in our general partner to us; (iii) MGG will contribute to us all of its cash and assets, other than the common units in us it receives in the unit distribution; and (iv) we will assume all of MGG’s liabilities (collectively, the “contributions”). Once the transformation, unit distribution and contributions are complete, pursuant to the Simplification Agreement, MGG will dissolve and wind-up and distribute the common units in us it receives in the unit distribution to its unitholders (the “redistribution”).

Pursuant to the Simplification Agreement, MGG will receive approximately 39.6 million of our common units in the transformation and unit distribution and each of MGG’s unitholders will receive 0.6325 of our common units in the redistribution for each MGG common unit. Our unitholders will continue to own their existing common units.

Our general partner will continue to manage us after the simplification and our management team will continue in their respective roles. Additionally, three of the four members of MGG’s general partner’s board of directors will join the board of directors of our general partner following completion of the simplification. The other member of MGG’s general partner’s board of directors, Patrick C. Eilers, also serves as an independent member of our general partner’s board of directors.

The terms of the Simplification Agreement were unanimously approved by the conflicts committee of the board of directors of our general partner and MGG’s general partner. Each conflicts committee is comprised solely of independent directors and was previously delegated authority by the board of directors to negotiate and authorize the terms of the simplification.

We incurred $2.9 million of costs associated with the simplification of our capital structure during the current quarter. In accordance with SFAS No. 160, we charged these costs directly to equity. This amount was reported under the caption “Simplification of capital structure” in the financing activities section of our consolidated statements of cash flows.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

15.

Reimbursable Costs

The reimbursable costs reported as current assets on our consolidated balance sheets were $8.2 million and $11.8 million at December 31, 2008 and March 31, 2009, respectively. These balances primarily represent costs we have incurred related to claims we have not yet filed with our insurance carriers but for which we expect to be reimbursed.

16.

Subsequent Events

In April 2009, our general partner declared a quarterly distribution of $0.71 per unit to be paid on May 15, 2009 to unitholders of record at the close of business on May 5, 2009. Total distributions to be paid under this declaration are approximately $71.0 million.

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, 2009, our three operating segments include:

•

petroleum products pipeline system, which is primarily comprised of our approximately 8,700-mile petroleum products pipeline system, including 49 terminals;

•

petroleum products terminals, which principally includes our seven marine terminal facilities and 27 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 partnership. 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, 2008.

Recent Developments

Simplification Agreement. In March 2009, we and our general partner and Magellan Midstream Holdings, L.P. (“MGG”) and its general partner entered into an Agreement Relating to Simplification of Capital Structure (the “Simplification Agreement”). Pursuant to the Simplification Agreement, we will amend and restate our existing partnership agreement to provide for the transformation of the incentive distribution rights and approximate 2% general partner interest owned by Magellan GP, LLC, our general partner, into common units in us and a non-economic general partner interest (the “transformation”). Once the transformation is complete, Magellan GP, LLC, MGG’s wholly-owned subsidiary, will distribute the common units in us that it receives in the transformation to MGG (the “unit distribution”). Once the transformation and unit distribution are complete, pursuant to a Contribution and Assumption Agreement among MGG, Magellan Midstream Holdings GP, LLC (MGG’s general partner), us and Magellan GP, LLC (our general partner): (i) MGG will contribute 100% of its member interests in its general partner to our general partner; (ii) MGG will contribute 100% of the member interests in our general partner to us; (iii) MGG will contribute to us all of its cash and assets, other than the common units in us it receives in the unit distribution; and (iv) we will assume all of MGG’s liabilities (collectively, the “contributions”). Once the transformation, unit distribution and contributions are complete, pursuant to the Simplification Agreement, MGG will dissolve and wind-up and distribute the common units in us it receives in the unit distribution to its unitholders (the “redistribution”).

Currently, we are a consolidated subsidiary of MGG. MGG controls and operates us through its 100% ownership interest in our general partner. Assuming the simplification of the capital structure as described above is approved by both our and MGG’s unitholders, our general partner and MGG’s general partner will legally become our wholly-owned subsidiaries and MGG will be dissolved. For accounting purposes, however, MGG will be considered the accounting acquirer of its non-controlling interest. Therefore, in accordance with SFAS No. 160, Non-Controlling Interests in Consolidated Financial Statements, the changes in MGG’s ownership interest of us will be accounted for as an equity transaction and no gain or loss will be recognized as a result of the simplification of the capital structure. Because MGG will be the surviving accounting entity, the amounts reported on our consolidated balance sheet for property, plant and equipment will increase by approximately $165.0 million and accumulated depreciation will increase by approximately $140.0 million. Additionally, depreciation and amortization expense on our consolidated income statement will increase by approximately $13.0 million on an annual basis.

The simplification is expected to be consummated in the third quarter of 2009, subject to customary closing conditions including majority approval of our and MGG’s unitholders.

We and MGG have filed a joint proxy statement/prospectus and other documents with the Securities and Exchange Commission (“SEC”) in relation to the simplification. Investors and security holders are urged to read these documents carefully because they contain important information regarding us, MGG and the simplification. A definitive joint proxy statement/prospectus is being sent to unitholders of us and MGG seeking their approvals as contemplated by the Simplification Agreement. Investors and unit holders may obtain a free copy of the joint proxy statement/prospectus and other documents containing information about us and MGG, without charge, at the SEC’s website at www.sec.gov. Copies of the joint proxy statement/prospectus and the SEC filings incorporated by reference in the joint proxy statement/prospectus may also be obtained free of charge by contacting investor relations at (918) 574-7650, or by accessing www.magellanlp.com or www.mgglp.com.

We, MGG and the officers and directors of the general partner of each partnership may be deemed to be participants in the solicitation of proxies from their security holders. Information about these persons can be found in the annual report and proxy statement for each partnership as filed with the SEC, and additional information about such persons may be obtained from the joint proxy statement/prospectus.

This communication shall not constitute an offer to sell or the solicitation of an offer to sell or the solicitation of an offer to buy any securities, nor shall there be any sale of securities in any jurisdiction in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of any such jurisdiction.

Cash distribution. During April 2009, the board of directors of our general partner declared a quarterly cash distribution of $0.71 per unit for the period of January 1 through March 31, 2009. This quarterly cash distribution will be paid on May 15, 2009 to unitholders of record on May 5, 2009.

Unitholder vote results. During April 2009, we held our annual unitholder meeting. Proxy statements were mailed in advance to unitholders of record on February 24, 2009. Our unitholders elected George A. O’Brien, Jr. to continue serving as a member of our general partner’s board of directors until our 2012 annual meeting. No other matters requiring a unitholder vote were presented.

Results of Operations

We believe that investors benefit from having access to the same financial measures being utilized by management. Operating margin, which is presented in the table below, is an important measure used by management to evaluate 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 margin is not a generally accepted accounting principles (“GAAP”) measure, but the components of operating margin are computed 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 expense and affiliate general and administrative (“G&A”) costs, which management does not consider when evaluating the core profitability of our operations. Additionally, product margin, which management primarily uses to evaluate the profitability of our petroleum products blending and fractionation activities, is provided in the table below. Product margin is a non-GAAP measure; however, its components, product sales and product purchases, are determined in accordance with GAAP.

Three Months Ended March 31, 2008 Compared to Three Months Ended March 31, 2009


	Three Months Ended March 31,						Variance Favorable (Unfavorable)
	2008			2009			$ Change			% Change
Financial Highlights ($ in millions, except operating statistics)

Transportation and terminals revenues:
Petroleum products pipeline system	$	106.3		$	114.8		$	8.5		8
Petroleum products terminals		33.6			38.2			4.6		14
Ammonia pipeline system		5.4			3.2			(2.2	)	(41	)
Intersegment eliminations		(0.7	)		(1.3	)		(0.6	)	(86	)

Total transportation and terminals revenues		144.6			154.9			10.3		7
Affiliate management fee revenues		0.2			0.2			—		—
Operating expenses:
Petroleum products pipeline system		42.3			44.0			(1.7	)	(4	)
Petroleum products terminals		12.5			15.4			(2.9	)	(23	)
Ammonia pipeline system		2.3			3.1			(0.8	)	(35	)
Intersegment eliminations		(1.5	)		(1.8	)		0.3		20

Total operating expenses		55.6			60.7			(5.1	)	(9	)

Product margin:
Product sales		201.7			57.7			(144.0	)	(71	)
Product purchases		177.6			52.6			125.0		70

Product margin		24.1			5.1			(19.0	)	(79	)
Gain on assignment of supply agreement		26.5			—			(26.5	)	(100	)
Equity earnings		0.4			0.5			0.1		25

Operating margin		140.2			100.0			(40.2	)	(29	)
Depreciation and amortization expense		17.1			19.4			(2.3	)	(13	)
Affiliate G&A expense		17.8			20.5			(2.7	)	(15	)

Operating profit		105.3			60.1			(45.2	)	(43	)

Interest expense (net of interest income and interest capitalized)		11.3			14.4			(3.1	)	(27	)
Debt placement fee amortization		0.2			0.2			—		—
Other income		—			(0.1	)		0.1		N/A

Income before provision for income taxes		93.8			45.6			(48.2	)	(51	)
Provision for income taxes		0.5			0.4			0.1		20

Net income	$	93.3		$	45.2		$	(48.1	)	(52	)


Operating Statistics
Petroleum products pipeline system:
Transportation revenue per barrel shipped	$	1.153		$	1.145
Volume shipped (million barrels)		68.9			71.7
Petroleum products terminals:
Marine terminal average storage utilized (million barrels per month)		22.8			25.1
Inland terminal throughput (million barrels)		27.1			26.0
Ammonia pipeline system:
Volume shipped (thousand tons)		220			124

Transportation and terminals revenues increased $10.3 million as shown below:

•

an increase in petroleum products pipeline system revenues of $8.5 million primarily attributable to higher revenues related to leased storage and capacity leases and higher transportation revenues. The higher leased storage revenues resulted from new storage contracts related to our increase in storage capacity. The higher transportation revenues resulted from an increase in gasoline shipments reflecting an overall increase in consumer demand for gasoline. The higher gasoline shipments were partially offset by lower diesel fuel shipments due primarily to weak industrial and agricultural demand during first quarter 2009;

•

an increase in petroleum products terminals revenues of $4.6 million due to higher revenues at both our marine and inland terminals. Marine revenues increased primarily at our Galena Park, Texas facility due to leasing new storage tanks placed in service during 2008 and higher storage rates. Inland revenues benefitted from higher fees due to ethanol blending; and

•

a decrease in ammonia pipeline system revenues of $2.2 million due to lower shipments primarily due to operational issues at two of our customers’ plants and unfavorable weather conditions in first quarter 2009, which slowed demand for ammonia, partially offset by higher average tariffs.

Operating expenses increased by $5.1 million as shown below:

•

an increase in petroleum products pipeline system expenses of $1.7 million primarily due to higher maintenance spending resulting from more testing and rehabilitation work being performed, higher personnel costs and less favorable product overages. Lower environmental expenses and favorable power costs reflecting lower prices for natural gas and electricity which reduced utility costs in the current quarter partially offset the previously discussed unfavorable expense items;

•

an increase in petroleum products terminals expenses of $2.9 million due primarily to gains recognized in first quarter 2008 from insurance proceeds received for hurricane damages sustained during 2005. Additionally, higher utility costs, maintenance integrity costs and personnel costs contributed to the increase; and

•

an increase in ammonia pipeline system expenses of $0.8 million primarily due to higher environmental costs resulting from increases in several accruals related to historical releases.

Product sales revenues primarily resulted from our petroleum products blending activities, terminal product gains and transmix fractionation. Product margin decreased $19.0 million primarily because of the timing differences of when profits on product sales are recognized under forward sales contracts, which we were using in first quarter 2008, versus under New York Mercantile Exchange (“NYMEX”) contracts, which we have been predominately using to hedge price changes for future product sales since third quarter 2008. We applied normal sales accounting to the forward sales contracts we entered into; therefore, all of the profit on product sales under these agreements that matured in the first quarter of 2008 was recognized in that period, which was when the physical sale of the product occurred. Because the NYMEX contracts we have been using do not qualify for hedge accounting, we mark these contracts to market at the end of each accounting period. As a result, we recognized profits of $15.3 million in the third and fourth quarters of 2008 on NYMEX contracts related to physical product sales during first quarter 2009. In addition, during the current quarter, we recognized $3.1 million of losses on NYMEX contracts related to products whose physical sales will occur in the second, third and fourth quarters of 2009. See Other Items below for further discussion of our NYMEX contracts.

The gross margin we realize on product sales activities can be substantially higher in periods when refined petroleum prices increase and substantially lower in periods when product prices decline or stabilize given that we follow an average inventory valuation methodology which results in each period’s product purchases being influenced by the value of products held in that period’s beginning inventory. Given the current pricing environment for petroleum products, we expect our product margin for 2009 to be substantially lower than in 2008.

The 2008 period benefited from a $26.5 million gain on the assignment of a third-party supply agreement during March 2008. The gain resulted from the write-off of the unamortized amount of a liability we recognized related to the fair value of the agreement, which we assumed as part of our acquisition of certain pipeline assets in October 2004.

Depreciation and amortization expense increased by $2.3 million related to expansion capital projects placed into service over the past year.

Affiliate G&A expense increased by $2.7 million between periods primarily due to higher equity-based incentive compensation expense, higher personnel costs and higher costs associated with potential growth projects. Equity-based incentive compensation expense increased principally due to additional accruals recognized from the modification of our 2008 unit awards and because the expense associated with the final tranche of the awards issued in 2007 is being recognized over a shorter period.

Interest expense, net of interest income and interest capitalized, increased $3.1 million. Our average debt outstanding, excluding fair value adjustments for interest rate hedges, increased to $1,093.0 million for the 2009 period from $960.0 million for the 2008 period principally due to borrowings for expansion capital expenditures. The weighted-average interest rate on our borrowings increased to 5.6% in first quarter 2009 from 5.3% in first quarter 2008.

Liquidity and Capital Resources

Cash Flows and Capital Expenditures

Net cash provided by operating activities was $95.9 million and $62.1 million for the three months ended March 31, 2008 and 2009, respectively. The $33.8 million decrease from 2008 to 2009 was primarily attributable to:

•

a decrease in net income of $21.6 million, excluding the $26.5 million non-cash gain on assignment of the supply agreement in 2008;

•

a $38.4 million decrease in cash resulting from an $18.1 million increase in inventory in 2009 versus a $20.3 million decrease in inventory in 2008 primarily due to the sale of petroleum products inventory when we assigned our product supply agreement to a third party in March 2008; and

•

a $14.8 million decrease in cash resulting from a $6.3 million increase in accounts receivable and other accounts receivable in 2009 versus an $8.5 million decrease in 2008 due primarily to the timing of payments received from our customers.

These decreases were partially offset by:

•

an $18.5 million favorable cash flow variance in the current quarter resulting from the repayment of the supply agreement deposit in 2008 associated with the assignment of our product supply agreement to a third party;

•

a $10.1 million increase in cash resulting from a $3.7 million increase in accounts payable in 2009 versus a $6.4 million decrease in 2008 due primarily to the timing of invoices received from our vendors and suppliers; and

•

a $9.8 million increase in cash resulting from a $16.4 million increase in accrued product purchases in 2009 versus a $6.6 million increase in 2008 due primarily to the timing of invoices received from our vendors and suppliers.

Net cash used by investing activities for the three months ended March 31, 2008 and 2009 was $70.5 million and $47.9 million, respectively. During 2009, we spent $47.6 million for capital expenditures, which included $11.3 million for maintenance capital, including $0.9 million of spending that would have been covered by an indemnification settlement with a former affiliate, and $36.3 million for expansion capital. During 2008, we spent $54.9 million for capital expenditures, which included $7.8 million for maintenance capital, including $0.3 million of spending that would have been covered by our indemnification settlement, and $47.1 million for expansion capital. Additionally, we acquired a petroleum products terminal in Bettendorf, Iowa for $12.0 million in first quarter 2008.

Net cash used by financing activities for the three months ended March 31, 2008 and 2009 was $25.4 million and $32.4 million, respectively. During 2009, we paid cash distributions of $71.0 million to our unitholders and general partner while net borrowings on our revolving credit facility primarily to finance expansion capital projects were $42.0 million. During 2008, we paid cash distributions of $63.8 million to our unitholders and general partner while net borrowings on our revolving credit facility primarily to finance expansion capital projects and acquisitions were $33.5 million.

During first quarter 2009, we paid $71.0 million in cash distributions to our unitholders and general partner. Based on the declared quarterly distribution of $0.71 per unit associated with the first quarter of 2009, we will pay $71.0 million in distributions during second quarter 2009. If we continue to pay cash distributions at this level and the number of outstanding units remains the same, total cash distributions of $284.1 million would be paid on an annual basis. Of this amount, $93.9 million, or 33%, would be paid to our general partner on its approximate 2% ownership interest and incentive distribution rights. If the Simplification Agreement is approved, cash distributions will no longer be paid to the general partner, but our common units outstanding will increase to approximately 106.6 million units. In that event, a total annual distribution of approximately $302.7 million would be necessary to maintain the current quarterly distribution level of $0.71 per unit.

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

•

expansion capital expenditures to acquire additional complementary assets to grow our business and to expand or upgrade our existing facilities, which we refer 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 2009, our maintenance capital spending was $11.3 million, including $0.9 million of spending that would have been covered by our indemnification settlement with a former affiliate. We have received the entire $117.5 million under our indemnification settlement agreement.

For 2009, we expect to incur maintenance capital expenditures for our existing businesses of approximately $42.0 million, including $7.0 million of maintenance capital that has already been reimbursed to us through our indemnification settlement or will be reimbursed by third parties.

In addition to maintenance capital expenditures, we also incur expansion capital expenditures at our existing facilities. During first quarter 2009, we spent $36.3 million for organic growth projects. Based on the progress of expansion projects already underway, we expect to spend approximately $220.0 million of growth capital during 2009, with an additional $40.0 million in 2010 to complete these projects.

Liquidity

As of March 31, 2009, total debt reported on our consolidated balance sheet was $1,125.1 million. The difference between this amount and the $1,112.0 million face value of our outstanding debt results from gains and losses realized on various cash flow hedges and unamortized discounts on debt issuances.

Revolving Credit Facility. The total borrowing capacity under our revolving credit facility, which matures in September 2012, is $550.0 million. Borrowings under the facility are unsecured and bear interest at LIBOR plus a spread ranging from 0.3% to 0.8% based on our credit ratings and amounts outstanding under the facility. Additionally, a commitment fee is assessed at a rate from 0.05% to 0.125%, depending on our credit ratings. Borrowings under this facility are used primarily for general purposes, including capital expenditures. As of March 31, 2009, $112.0 million was outstanding under this facility with a weighted-average interest rate of 1.0%, and $3.9 million was obligated for letters of credit. Amounts obligated for letters of credit are not reflected as debt on our consolidated balance sheets.

6.45% Notes due 2014. In May 2004, we sold $250.0 million of 6.45% notes due 2014 in an underwritten public offering at 99.8% of par. Including the impact of amortizing the gains realized on pre-issuance hedges associated with these notes, the effective interest rate of these notes is 6.3%.

5.65% Notes due 2016. In October 2004, we sold $250.0 million of 5.65% notes due 2016 in an underwritten public offering at 99.9% of par. The outstanding principal amount of the notes was increased by $3.4 million at March 31, 2009 for the unamortized portion of a gain realized upon termination of a related interest rate swap. Including the impact of amortizing this gain, as well as gains realized on pre-issuance hedges associated with these notes, the effective interest rate of these notes is 5.7%.

6.40% Notes due 2018. In July 2008, we issued $250.0 million of 6.40% notes due 2018 in an underwritten public offering. The outstanding principal amount of the notes was increased by $11.3 million at March 31, 2009 for the unamortized portion of gains realized upon termination or discontinuation of hedge accounting treatment of associated interest rate swaps. Including the impact of amortizing these gains, the effective interest rate of these notes is 5.9%

6.40% Notes due 2037. In April 2007, we issued $250.0 million of 6.40% notes due 2037 in an underwritten public offering at 99.6% of par. Including the impact of amortizing the gains realized on pre-issuance hedges associated with these notes, the effective interest rate on these notes is 6.3%.

Interest rate derivatives. We use interest rate derivatives to help manage interest rate risk. As of March 31, 2009, we had two offsetting interest rate swap agreements outstanding:

•

Credit ratings. Our current corporate credit ratings are BBB by Standard and Poor’s and Baa2 by Moody’s Investor Services.

Off-Balance Sheet Arrangements

None.

Environmental

Our operations are subject to federal, state and local environmental laws and regulations. We have accrued liabilities for estimated costs at our facilities and properties. We record liabilities when environmental costs are probable and can be reasonably estimated. The determination of amounts recorded for environmental liabilities involves significant judgments and assumptions by management. Due to the inherent uncertainties involved in determining environmental liabilities, it is reasonably possible that the actual amounts required to extinguish these liabilities could be materially different from those we have recognized.

Ammonia EPA issue. In February 2007, we received notice from the Department of Justice (“DOJ”) that the Environmental Protection Agency (“EPA”) had requested the DOJ to initiate a lawsuit alleging violations of Sections 301 and 311 of the Clean Air Act (“the Act”) with respect to two releases of anhydrous ammonia from our ammonia pipeline system that was operated by a third party at the time of the releases. The DOJ stated that the maximum statutory penalty for alleged violations of the Act for both releases combined was approximately $13.2 million. The DOJ also alleged that the third-party operator of our ammonia pipeline was liable for penalties pursuant to Section 103 of the Comprehensive Environmental Response, Compensation and Liability Act for failure to report the releases on a timely basis, with the statutory maximum for those penalties as high as $4.2 million for which the third-party operator has requested indemnification. In March 2007, we also received a demand from the third-party operator for defense and indemnification in regards to a DOJ criminal investigation regarding whether certain actions or omissions of the third-party operator constituted violations of federal criminal statutes. The third-party operator subsequently settled this criminal investigation with the DOJ by paying a $1.0 million fine. The DOJ stated in its notice to us that it does not expect us or the third-party operator to pay the penalties at the statutory maximum; however, it may seek injunctive relief if the parties cannot agree on any necessary corrective actions. We have accrued an amount for these matters based on our best estimates that is less than the maximum statutory penalties. We are currently in discussions with the EPA, DOJ and the third-party operator regarding these two releases. Adjustments to our recorded liability, which could occur in the near term, could be material to our results of operations and cash flows.

Other Items

NYMEX contracts. Gains and losses on NYMEX contracts are recognized in income when these contracts are marked to market at the end of each accounting period, and realized when the related physical sale of the product occurs and the NYMEX contracts are settled. The following table provides a summary of gains realized in the current quarter and the periods in which the related gains and losses were recognized in our consolidated statement of income (in millions).


Period in Which Gains / (Losses) Were Recorded to Income
2008
Third Quarter	Fourth Quarter		Current Quarter			Total Gains Realized In Current Quarter
$ 3.5	$	11.8	$	(0.4	)	$	14.9

The following table provides a summary of the periods in which unrealized gains and losses have been recognized on our NYMEX contracts that were open as of March 31, 2009 (in millions).


	Period in Which Gains / (Losses) Were Recorded to Income
	2008
Period Physical Sale Will Occur	Third Quarter		Fourth Quarter		Current Quarter			Total Mark-to-Market Gains / (Losses) Recognized
2^nd Quarter 2009	$	1.0	$	3.9	$	(1.4	)	$	3.5
3^rd Quarter 2009		—		—		(0.6	)		(0.6	)
4^th Quarter 2009		—		—		(1.1	)		(1.1	)

Totals	$	1.0	$	3.9	$	(3.1	)	$	1.8

Pipeline tariff increase. The Federal Energy Regulatory Commission (“FERC”) regulates the rates charged on interstate common carrier pipeline operations primarily through an index methodology, which establishes the maximum amount by which tariffs can be adjusted. Approximately 40% of our tariffs are subject to this indexing methodology while the remaining 60% of the tariffs can be adjusted at our discretion based on competitive factors. The current approved methodology is the annual change in the producer price index for finished goods (“PPI-FG”) plus 1.3%. As of April 30, 2009, the indicated change in PPI-FG for 2008 is approximately 6.3%. At this level, we would be allowed to increase our indexed rates by an amount up to 7.6% subject to market conditions. We expect to change the majority of our tariffs by this amount on July 1, 2009.

Board of directors of our general partner. The total number of directors on our general partner’s board of directors is currently set at eight and there are four vacancies. Three vacancies were created when representatives of MGG Midstream Holdings, L.P. (“MGG MH”), a former affiliate, resigned from our board in 2006 and 2008 in conjunction with various governance changes. The fourth vacancy was due to the death of one of three independent directors in December 2008. The New York Stock Exchange corporate governance listing standards require all publicly traded companies to have at least three independent directors serving on the audit committee. At our general partner’s April 2009 board of directors meeting, Patrick C. Eilers was affirmatively determined to be an independent member of that board and was elected to serve on the audit committee. Following these actions, our general partner’s board of directors is in compliance with the New York Stock Exchange’s corporate governance listing standards. If the Simplification Agreement (see Recent Developments) is approved by our and MGG’s unitholders, the three independent members of MGG’s general partner’s board of directors will join the board of directors of our general partner.

Unrecognized product gains. Our petroleum products terminals operations generate product overages and shortages that result from metering inaccuracies, product evaporation or expansion, product releases and product contamination. Most of the contracts we have with our customers state that we bear the risk of loss (or gain) from these conditions. When our petroleum products terminals experience net product shortages, we recognize expense for those losses in the periods in which they occur. When our petroleum products terminals experience net product overages, we have product on hand for which we have no cost basis. Therefore, these net overages are not recognized in our financial statements until the associated barrels are either sold or used to offset product losses. The net unrecognized product overages for our petroleum products terminals operations had a market value of approximately $3.3 million as of March 31, 2009. 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. We own a 50% interest in a crude oil pipeline company and are paid a management fee for its operation. During the three months ended March 31, 2009, we received operating fees from this pipeline company of $0.2 million, which we reported as affiliate management fee revenue.

The following table summarizes affiliate costs and expenses that are reflected in our consolidated statement of income (in thousands):


	Three Months Ended March 31, 2009
MGG GP - allocated operating expenses	$	22,676
MGG GP - allocated G&A expenses	$	13,167

Under our services agreement with Magellan Midstream Holdings GP, LLC (“MGG GP”), we reimburse MGG GP for costs of employees necessary to conduct our operations. The affiliate payroll and benefits accruals associated with this agreement at March 31, 2009 were $15.4 million, and the long-term affiliate pension and benefits accruals associated with this agreement at March 31, 2009 were $33.9 million. We settle our affiliate payroll, payroll-related expenses and non-pension postretirement benefit costs with MGG GP on a monthly basis. We settle our long-term affiliate pension liabilities through payments to MGG GP when MGG GP makes contributions to its pension funds.

Because our cash distributions have exceeded target levels as specified in our partnership agreement, our general partner receives approximately 50% of any incremental cash distributed per limited partner unit. As of March 31, 2009, our executive officers collectively owned a beneficial interest of approximately 1% of MGG, the owner of our general partner. Therefore, our executive officers indirectly benefit from distributions paid to our general partner. Assuming we have sufficient available cash to continue to pay cash distributions on all of our outstanding units for four quarters at our current quarterly distribution level of $0.71 per unit, our general partner would receive annual cash distributions of approximately $93.9 million on its combined general partner interest and incentive distribution rights.

New Accounting Pronouncements

In December 2008, the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position (“FSP”) FAS 132(R)-1, Employers’ Disclosures about Postretirement Benefit Plan Assets. This FSP expands the disclosure requirements for employer pension plans and other postretirement benefit plans to include factors that are pertinent to an understanding of investment policies and strategies. The additional disclosure requirements include: (i) for annual financial statements, the fair value of each major category of plan assets separately for pension and other postretirement plans, (ii) a narrative description of the basis used to determine the expected long-term rate of return on asset assumptions, (iii) information to enable users of financial statements to assess the inputs and valuation techniques used to develop fair value measurements of plan assets at the annual reporting date, and (iv) for fair value measurements using unobservable inputs, disclosure of the effect of the measurements on changes in plan assets for the period. This FSP is effective for fiscal years ending after December 15, 2009, with early application permitted. Provisions of this FSP are not required for earlier periods that are presented for comparative purposes. Adoption of this FSP will not have a material impact on our financial position, results of operations or cash flows.

In September 2008, the FASB issued Emerging Issues Task Force (“EITF”) No. 08-6 Equity Method Investment Accounting Considerations. This EITF requires entities to measure its equity method investments initially at cost in accordance with SFAS No. 141(R) Business Combinations. Further, the EITF clarified that entities should not separately test an investee’s underlying indefinite-lived intangible asset for impairment; however, they are required to recognize other-than-temporary impairments of an equity method investment in accordance with Accounting Principles Bulletin No. 18, The Equity Method of Accounting for Investments in Common Stock. In addition, entities are required to account for a share issuance by an equity method investee as if the investor had sold a proportionate share of its investment. Any gain or loss to the investor resulting from an investee’s share issuance is to be recognized in earnings. We adopted this EITF on January 1, 2009, which is applicable to both interim and annual periods and is to be applied prospectively. Our adoption of this EITF did not have a material impact on our financial position, results of operations or cash flows.

In June 2008, the FASB issued FASB FSP No. EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities. This FSP clarifies that unvested share-based payment awards that contain non-forfeitable rights to distributions or distribution equivalents, whether paid or unpaid, are participating securities as defined in SFAS No. 128, Earnings Per Share, and are to be included in the computation of earnings per unit pursuant to the two-class method. We adopted this FSP on January 1, 2009, which is applicable to both interim and annual periods, with prior period earnings per unit data retrospectively adjusted. Our adoption of this FSP did not have a material impact on our financial position, results of operations or cash flows.

In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles. This Statement identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements that are presented in conformity with GAAP in the United States. The Statement will not change our current accounting practices.

In April 2008, the FASB issued FSP No. FAS 142-3, Determination of the Useful Life of Intangible Assets. This FSP amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, Goodwill and Other Intangible Assets. This FSP also expands the disclosures required for recognized intangible assets. We adopted this FSP on January 1, 2009, which is applicable to both interim and annual periods. Our adoption of this FSP did not have a material impact on our financial position, results of operations or cash flows.

On January 1, 2009, we adopted EITF Issue No. 07-4, Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships. Under EITF No. 07-4, the excess of distributions over earnings and/or excess of earnings over distributions for each period are allocated to the entities’ general partner based solely on the general partner’s ownership interest at the time. For purposes of calculating earnings per unit, our previous accounting practice was to allocate net income to the general partner based on the general partner’s share of total or pro forma distributions, as appropriate, including incentive distribution rights. The effect of adopting this EITF is: (i) for periods when net income exceeds distributions, our reported earnings per limited partner unit will be higher than under our previous accounting practice and (ii) for periods when distributions exceed net income, our reported earnings per limited partner unit will be lower than under our previous accounting practice. These differences will be material for those periods where there are material differences between our net income and the distributions we pay. For the periods included in this report, the differences between our previous methodology and those calculated under EITF 07-4 are provided in the table below:


	Under EITF No. 07-4		Under Previous Accounting		Difference
	(in thousands, except per unit amounts)
Three Months Ended March 31, 2009
Net income allocated to limited partners	$	22,921	$	30,725	$	(7,804	)

Basic earnings per unit	$	0.34	$	0.46	$	(0.12	)

Diluted earnings per unit	$	0.34	$	0.46	$	(0.12	)


Three Months Ended March 31, 2008
Net income allocated to limited partners	$	73,763	$	59,620	$	14,143

Basic earnings per unit	$	1.10	$	0.89	$	0.21

Diluted earnings per unit	$	1.10	$	0.89	$	0.21

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities. SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, established, among other things, the disclosure requirements for derivative instruments and for hedging activities. SFAS No. 161 amends SFAS No. 133, requiring qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts and gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. We adopted SFAS No. 161 on January 1, 2009, which is applicable for both interim and annual periods. Our adoption of this statement did not have a material impact on our financial position, results of operations or cash flows.

In December 2007, the FASB issued SFAS No. 141(R), Business Combinations. This Statement requires, among other things, that entities: (i) recognize, with certain exceptions, 100% of the fair values of assets acquired, liabilities assumed and non-controlling interests in acquisitions of less than a 100% controlling interest when the acquisition constitutes a change in control of the acquired entity; (ii) measure acquirer shares issued in consideration for a business combination at fair value on the acquisition date; (iii) recognize contingent consideration arrangements at their acquisition-date fair values, with subsequent changes in fair value generally reflected in earnings; (iv) recognize, with certain exceptions, pre-acquisition loss and gain contingencies at their acquisition-date fair values; (v) expense, as incurred, acquisition-related transaction costs; and (vi) capitalize acquisition-related restructuring costs only if the criteria in SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities (as amended) are met as of the acquisition date. We adopted this Statement on January 1, 2009, and our initial adoption did not have a material impact on our financial position, results of operations or cash flows.

In December 2007, the FASB issued SFAS No. 160, Non-Controlling Interests in Consolidated Financial Statements. This Statement requires, among other things, that: (i) the non-controlling interest be clearly identified and presented in the consolidated statement of financial position within equity, but separate from the parent’s equity; (ii) the amount of consolidated net income attributable to the parent and to the non-controlling interest be clearly identified and presented on the face of the consolidated statement of income; (iii) all changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for consistently (as equity transactions); (iv) when a subsidiary is deconsolidated, any retained non-controlling equity investment in the former subsidiary be initially measured at fair value. The gain or loss on the deconsolidation of the subsidiary is measured using the fair value of any non-controlling equity investment rather than the carrying amount of that retained investment; and (v) sufficient disclosures be made to clearly identify and distinguish between the interests of the parent and the interests of non-controlling owners. We adopted SFAS No. 160 on January 1, 2009, which is applicable for both interim and annual periods. Our adoption of this Statement did not have a material impact on our financial position, results of operations or cash flows.

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We may be exposed to market risk through changes in commodity prices and interest rates. We 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.

Commodity Price Risk

We use derivatives to help us manage product purchases and sales. Derivatives that qualify for and are designated as normal purchases and sales are accounted for using traditional accrual accounting. As of March 31, 2009, we had commitments under forward purchase contracts for product purchases of approximately 60 thousand barrels that are being accounted for as normal purchases totaling approximately $3.2 million, and we had commitments under forward sales contracts for product sales of approximately 330 thousand barrels that are being accounted for as normal sales totaling approximately $18.7 million.

In addition to forward sales agreements, we use New York Mercantile Exchange (“NYMEX”) contracts to lock in forward sales prices. Although these NYMEX agreements represent an economic hedge against price changes on the petroleum products we expect to sell in the future, they do not meet the requirements for hedge accounting treatment under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (as amended); therefore, we have recognized the change in fair value of these agreements currently in earnings. During first quarter 2009, we closed our positions on contracts associated with the sale of 610 thousand barrels of gasoline, and we realized total gains of $14.9 million, a majority of which was recorded to earnings in the third and fourth quarters of 2008 through mark-to-market valuations of these contracts. At March 31, 2009, the net fair value of our open contracts, representing 0.8 million barrels of petroleum product, was $1.8 million, of which $2.1 million was recorded as energy commodity derivative contracts and $(0.3) million was recorded as other current liabilities on our consolidated balance sheet. These contracts mature between April 2009 and December 2009. Based on our open NYMEX contracts at March 31, 2009, a $1.00 per barrel increase in the price of the NYMEX contract for reformulated gasoline blendstock for oxygen blending (“RBOB”) gasoline would result in a $0.8 million decrease in our product sales revenues and a $1.00 per barrel decrease in the price of the NYMEX contract for RBOB would result in a $0.8 million increase in our product sales revenues. However, the increases or decreases in product sales revenues we recognize from our open NYMEX contracts are substantially offset by higher or lower product sales revenues when the physical sale of the product occurs. These contracts may be for the purchase or sale of product in markets different from those in which we are attempting to hedge our exposure, resulting in hedges that do not eliminate all price risks.

Interest Rate Risk

As of March 31, 2009, we had $112.0 million outstanding on our variable rate revolving credit facility. Based on the amount outstanding on our revolving credit facility as of March 31, 2009, our annual interest expense would change by $0.1 million if LIBOR were to change by 0.125%.

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. Additionally, these disclosure controls and practices are effective in ensuring that information required to be disclosed is accumulated and communicated to our Chief Executive Officer and Chief Financial Officer to allow timely decisions regarding required disclosures.

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 not guarantees of future performance and subject to numerous assumptions, uncertainties and risks that are difficult to predict. Therefore, actual outcomes and results may be materially different from the results stated or implied in such forward-looking statements included in this report.

The following are among the important factors that could cause future results to differ materially from any projected, forecasted, estimated or budgeted amounts that we have discussed in this report:

•

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

•

price fluctuations for refined petroleum products and natural gas liquids and expectations about future prices for these products;

•

changes in general economic conditions, interest rates and price levels in the United States;

•

changes in the financial condition of our customers;

•

our ability to secure financing in the credit and capital markets in amounts and on terms that will allow us to execute our growth strategy and maintain adequate liquidity;

•

development of alternative energy sources, increased use of biofuels such as ethanol and biodiesel, increased conservation or fuel efficiency, regulatory developments or other trends that could affect demand for our services;

•

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

•

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;

•

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;

•

weather patterns materially different than historical trends;

•

an increase in the competition our operations encounter;

•

the occurrence of natural disasters, terrorism, operational hazards or unforeseen interruptions for which we are not adequately insured;

•

the treatment of us as a corporation for federal or state income tax purposes or if we become subject to significant forms of other taxation;

•

our ability to identify growth projects or to complete identified growth projects on time and at projected costs;

•

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

•

changes in laws and 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;

•

the effect of changes in accounting policies;

•

the potential that our 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;

•

the ability of third parties to perform on their contractual obligations to us;

•

conflicts of interests between us, our general partner and MGG;

•

supply disruption; and

•

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

This list of important factors is not exclusive. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events, changes in assumptions or otherwise.

PART II

OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

Ammonia EPA issue. In February 2007, we received notice from the Department of Justice (“DOJ”) that the Environmental Protection Agency (“EPA”) had requested the DOJ to initiate a lawsuit alleging violations of Sections 301 and 311 of the Clean Air Act (“the Act”) with respect to two releases of anhydrous ammonia from our ammonia pipeline system that was operated by a third party at the time of the releases. The DOJ stated that the maximum statutory penalty for alleged violations of the Act for both releases combined was approximately $13.2 million. The DOJ also alleged that the third-party operator of our ammonia pipeline was liable for penalties pursuant to Section 103 of the Comprehensive Environmental Response, Compensation and Liability Act for failure to report the releases on a timely basis, with the statutory maximum for those penalties as high as $4.2 million, for which the third-party operator has requested indemnification. In March 2007, we also received a demand from the third-party operator for defense and indemnification in regards to a DOJ criminal investigation regarding whether certain actions or omissions of the third-party operator constituted violations of federal criminal statutes. The third-party operator has subsequently settled this criminal investigation with the DOJ by paying a $1.0 million fine. The DOJ stated in its notice to us that it does not expect us or the third-party operator to pay the penalties at the statutory maximum; however, it may seek injunctive relief if the parties cannot agree on any necessary corrective actions. We have accrued an amount for these matters based on our best estimates that is less than the maximum statutory penalties. We are currently in discussions with the EPA, DOJ and the third-party operator regarding these two releases. Adjustments to our recorded liability, which could occur in the near term, could be material to our results of operations and cash flows.

In June 2008, we received a Notice of Probable Violation (“NOPV”) from the Department of Transportation, Pipeline and Hazardous Materials Safety Administration (“DOT PHMSA”) with a preliminary assessed civil penalty of $0.8 million for alleged violations associated with a May 2005 pipeline release that occurred in the Fairfax Industrial District of Kansas City, Kansas. The violations principally involve allegations of failing to follow our system integrity plan. We submitted a request on a timely basis and a hearing was held in March 2009. We are currently in the process of preparing our post-hearing brief.

In May 2006, we received a NOPV from the DOT PHMSA alleging two areas of non-compliance with 40 CFR 452 (Pipeline Integrity Management in High Consequence Areas); specifically that (1) adequate technical justification was not presented for our formula in calculating the spill volume of refined product for an overall spread analysis and (2) the baseline assessment plan was not established by risk priority. DOT PHMSA has preliminarily assessed a civil penalty of $0.2 million for both allegations. A hearing was held in September 2006. We submitted our post-hearing brief in October 2006. In February 2007, we responded to a series of questions from the hearing officer. No further response from DOT PHMSA has been received to date.

In April 2005, we received a NOPV from the Office of Pipeline Safety (“OPS”) as a result of an inspection of our operator qualification records and procedures. The NOPV alleges that probable violations of 49 CFR Part 195.505 occurred in regards to our operator qualification program. The OPS preliminarily assessed a civil penalty of $0.2 million. We submitted a response to the NOPV, participated in a hearing at our request with the OPS and submitted a post-hearing brief. In February 2009, we received and accepted an offer from the OPS to settle this matter for $0.1 million.

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 these 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.

ITEM 1A.

RISK FACTORS

In addition to the 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, 2008, 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.

We have updated our risk factors as follows since issuing our Annual Report on Form 10-K:

Risks Related to the Simplification and Related Matters

While the simplification agreement is in effect, MGG’s opportunities to enter into different business combination transactions with other parties on more favorable terms may be limited, and we and MGG may be limited in our ability to pursue other attractive business opportunities.

While the simplification agreement is in effect, MGG is prohibited from initiating, soliciting or knowingly encouraging the submission of any acquisition proposal or from participating in any discussions or negotiations regarding any acquisition proposal, subject to certain exceptions. As a result of these provisions in the simplification agreement, MGG’s opportunities to enter into more favorable transactions may be limited. Likewise, if MGG were to sell directly to a third party, it might have received more value with respect to the general partner interest in us and our incentive distribution rights based on the value of the business at such time.

We and MGG have also agreed to refrain from taking certain actions with respect to our businesses and financial affairs pending completion of the simplification or termination of the simplification agreement. These restrictions could be in effect for an extended period of time if completion of the simplification is delayed. These limitations do not preclude us from conducting our business in the ordinary or usual course or from acquiring assets or businesses so long as such activity does not materially affect our or MGG’s ability to complete the matters contemplated by the simplification agreement.

In addition to the economic costs associated with pursuing the simplification, MGG’s general partner’s management and our general partner’s management will continue to devote substantial time and other human resources to the proposed simplification, which could limit MGG’s and our ability to pursue other attractive business opportunities, including potential joint ventures, stand-alone projects and other transactions. If either we or MGG is unable to pursue such other attractive business opportunities, then the growth prospects and the long-term strategic position of the business and our business following the simplification could be adversely affected.

Our existing unitholders will be diluted by the simplification and will have reduced voting power.

The simplification will dilute the ownership position of our existing unitholders. After the simplification, our existing unitholders will have reduced voting power. Pursuant to the simplification agreement, MGG unitholders will receive approximately 39.6 million of our common units as a result of the simplification. Immediately following the liquidation and redistribution, we will be owned approximately 62.8% by our current unitholders and approximately 37.2% by former MGG unitholders.

The number of our outstanding common units will increase as a result of the simplification, which could make it more difficult to pay the current level of quarterly distributions.

As of March 30, 2009, there were approximately 67.0 million of our common units outstanding. We will issue approximately 39.6 million of our common units in connection with the simplification. Accordingly, the dollar amount required to pay the current per unit quarterly distributions will increase, which will increase the likelihood that we will not have sufficient funds to pay the current level of quarterly distributions to all of our common unitholders. Using the amount of $0.71 per common unit paid with respect to the fourth quarter of 2008, the cash distribution paid to our unitholders totaled $47.5 million, resulting in a distribution of $23.5 million to the general partner for its general partner interest and incentive distribution rights. Therefore, our combined total distribution paid with respect to the fourth quarter of 2008 was $71.0 million. Pursuant to the simplification agreement, MGG unitholders will receive approximately 39.6 million of our common units as a result of simplification. The combined pro forma distribution of our common units with respect to the fourth quarter 2008, had the simplification been completed prior to such distribution, would result in $0.71 per unit being distributed on approximately 106.6 million of our common units, or a total of $75.7 million, with the general partner no longer receiving any distributions. As a result, we will be required to distribute an additional $4.7 million per quarter in order to maintain the distribution level of $0.71 per common unit paid with respect to the fourth quarter of 2008.

Although the elimination of the incentive distribution rights may increase the cash available for distribution to our common units in the future, this source of funds may not be sufficient to meet the overall increase in cash required to maintain the current level of quarterly distributions to holders of our common units.

Failure to complete the simplification or delays in completing the simplification could negatively impact MMP common unit prices and MGG common unit prices and future business and operations.

If the simplification is not completed for any reason, we and MGG may be subject to a number of material risks, including the following:

•

we will not realize the benefits expected from the simplification, including a potentially enhanced financial and competitive position;

•

the price of our common units or MGG common units may decline to the extent that the current market price of these securities reflects a market assumption that the simplification will be completed; and

•

some costs relating to the simplification, such as certain investment banking fees and legal and accounting fees, must be paid even if the simplification is not completed.

The costs of the simplification could adversely affect our operations and cash flows available for distribution to our unitholders.

We and MGG estimate the total costs of the simplification to be approximately $13.4 million, primarily consisting of investment banking and legal advisors’ fees, accounting fees, financial printing and other related costs. These costs could adversely affect our operations and cash flows available for distributions to our unitholders. In addition, the foregoing estimate is preliminary and is subject to change.

Our amended and restated partnership agreement that will be in effect following the simplification limits the ability of our general partner to withdraw as our general partner and limits the ability of our unitholders to remove our general partner.

Under our amended and restated partnership agreement, to the fullest extent permitted by law, our general partner may not withdraw as our general partner at any time for any reason except in the event that the general partner has transferred all of its general partner interest in us in accordance with our amended and restated partnership agreement. In addition, our general partner may not be removed unless the removal is approved by the vote of the holders of 100% of the outstanding units, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of 100% of our outstanding units.

Tax Risks Related to the Simplification

No ruling has been obtained with respect to the tax consequences of the simplification.

No ruling has been or will be requested from the Internal Revenue Service, or IRS, with respect to the tax consequences of the simplification. Instead, we and MGG are relying on the opinions of our respective counsel as to the tax consequences of the simplification, and counsel’s conclusions may not be sustained if challenged by the IRS.

The intended tax consequences of the simplification are dependent upon our and MGG being treated as a partnership for tax purposes.

The treatment of the simplification as nontaxable to our unitholders and MGG unitholders is dependent upon our and MGG being treated as a partnership for federal income tax purposes. If either we or MGG were treated as a corporation for federal income tax purposes, the consequences of the simplification would be materially different and would be taxable to an MGG unitholder.

An existing unitholder of ours may be required to recognize gain as a result of the decrease in his allocable share of our nonrecourse liabilities as a result of the simplification.

As a result of the simplification, the allocable shares of nonrecourse liabilities allocated to our existing unitholders will be recalculated to take into account common units issued by us in the transformation. If an existing unitholder of ours experiences a reduction in their share of nonrecourse liabilities as a result of the transformation, a “reducing debt shift,” such unitholder will be deemed to have received a cash distribution equal to the amount of the reduction. A reduction in an unitholder’s share of liabilities will result in a corresponding basis reduction in an unitholder’s common units. A reducing debt shift and the resulting deemed cash distribution may, under certain circumstances, result in the recognition of taxable gain by an unitholder of ours. If the reduction in an unitholder’s share of nonrecourse liabilities and the resulting deemed cash distribution exceeds such unitholder’s common unit basis, such unitholder would recognize gain in an amount equal to such excess. Although we have not received an opinion with respect to the shift of nonrecourse liabilities, we do not expect that any constructive cash distribution will exceed an existing unitholder’s tax basis in his common units.

We estimate that the transformation will result in an increase in the amount of net income (or decrease in the amount of net loss) allocable to all of our existing unitholders for the period from January 1, 2009 through December 31, 2010 (the “Projection Period”).

We estimate that the effectiveness of the simplification will result in an increase in the amount of net income (or decrease in the amount of net loss) allocable to all of our existing unitholders for the Projection Period. In addition, the federal income tax liability of an existing unitholder could be increased during the Projection Period if we make a future offering of our common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the Projection Period, such as to repay indebtedness currently outstanding or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate currently applicable to our assets.

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.

ITEM 6.

EXHIBITS


*Exhibit 2.1	–	Agreement Relating to Simplification of Capital Structure by and among Magellan Midstream Partners, L.P., Magellan GP, LLC, Magellan Midstream Holdings, L.P. and Magellan Midstream Holdings GP, LLC (filed as Exhibit 2.1 to Form 8-K filed March 4, 2009).

*Exhibit 4.1	–	Amendment No. 1 dated as of March 3, 2009 to Unit Purchase Rights Agreement dated as of December 4, 2008, between Magellan Midstream Partners, L.P. and Computershare Trust Company, N.A. (filed as Exhibit 4.1 to Form 8-K filed March 4, 2009).

Exhibit 12	–	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.

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

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 6, 2009.


MAGELLAN MIDSTREAM PARTNERS, L.P.

By:		Magellan GP, LLC,
		its General Partner

/s/ John D. Chandler
John D. Chandler Chief Financial Officer and Treasurer (Principal Accounting and Financial Officer)

INDEX TO EXHIBITS


EXHIBIT NUMBER		DESCRIPTION
*2.1		Agreement Relating to Simplification of Capital Structure by and among Magellan Midstream Partners, L.P., Magellan GP, LLC, Magellan Midstream Holdings, L.P. and Magellan Midstream Holdings GP, LLC (filed as Exhibit 2.1 to Form 8-K filed March 4, 2009).

*4.1		Amendment No. 1 dated as of March 3, 2009 to Unit Purchase Rights Agreement dated as of December 4, 2008, between Magellan Midstream Partners, L.P. and Computershare Trust Company, N.A. (filed as Exhibit 4.1 to Form 8-K filed March 4, 2009).

12		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.

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

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company