Edgar Filing: MAGELLAN MIDSTREAM PARTNERS LP

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 June 30, 2008

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

For the transition period from to

Commission File No.: 1-16335

Magellan Midstream Partners, L.P.

(Exact name of registrant as specified in its charter)


Delaware		73-1599053
(State or other jurisdiction of incorporation or organization)		(IRS Employer Identification No.)

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

(Address of principal executive offices and zip code)

(918) 574-7000

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

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

Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨ 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 August 4, 2008, there were 66,743,730 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
	CONSOLIDATED STATEMENTS OF INCOME		2
	CONSOLIDATED BALANCE SHEETS		3
	CONSOLIDATED STATEMENTS OF CASH FLOWS		4
	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
	1.	Organization and Basis of Presentation	5
	2.	Allocation of Net Income	6
	3.	Comprehensive Income	7
	4.	Segment Disclosures	7
	5.	Related Party Disclosures	10
	6.	Inventory	11
	7.	Employee Benefit Plans	12
	8.	Debt	13
	9.	Derivative Financial Instruments	14
	10.	Commitments and Contingencies	15
	11.	Long-Term Incentive Plan	17
	12.	Distributions	19
	13.	Net Income Per Unit	19
	14.	Assignment of Supply Agreement	20
	15.	Recent Accounting Standard	20
	16.	Subsequent Events	21
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Introduction		22
	Recent Developments		22
	Results of Operations		22
	Liquidity and Capital Resources		28
	Off-Balance Sheet Arrangements		30
	Environmental		30
	Other Items		31
	New Accounting Pronouncements		32
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			33
ITEM 4. CONTROLS AND PROCEDURES			33
Forward-Looking Statements			34

PART II
OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS			36
ITEM 1A. RISK FACTORS			37
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			38

PART I

FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except per unit amounts)

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2007			2008			2007			2008
Transportation and terminals revenues	$	150,070		$	162,367		$	293,221		$	306,959
Product sales revenues		177,902			110,364			326,565			312,082
Affiliate management fee revenue		183			183			356			366

Total revenues		328,155			272,914			620,142			619,407
Costs and expenses:
Operating		60,027			56,965			121,002			112,557
Product purchases		156,588			75,292			290,568			252,860
Depreciation and amortization		15,695			17,434			31,135			34,610
Affiliate general and administrative		17,741			18,454			35,426			36,234

Total costs and expenses		250,051			168,145			478,131			436,261
Gain on assignment of supply agreement		—			—			—			26,492
Equity earnings		1,106			1,377			1,869			1,782

Operating profit		79,210			106,146			143,880			211,420
Interest expense		15,072			12,751			29,939			25,687
Interest income		(746	)		(291	)		(1,117	)		(584	)
Interest capitalized		(1,205	)		(1,110	)		(2,102	)		(2,412	)
Debt placement fee amortization		1,154			169			1,799			337
Debt prepayment premium		1,984			—			1,984			—
Other (income) expense		699			(249	)		699			(249	)

Income before provision for income taxes		62,252			94,876			112,678			188,641
Provision for income taxes		800			502			1,524			945

Net income	$	61,452		$	94,374		$	111,154		$	187,696

Allocation of net income:
Limited partners’ interest	$	43,790		$	53,736		$	80,641		$	113,356
General partner’s interest		17,662			40,638			30,513			74,340

Net income	$	61,452		$	94,374		$	111,154		$	187,696


Basic net income per limited partner unit	$	0.66		$	0.80		$	1.21		$	1.70

Weighted average number of limited partner units outstanding used for basic net income per unit calculation		66,549			66,851			66,543			66,812


Diluted net income per limited partner unit	$	0.66		$	0.80		$	1.21		$	1.70

Weighted average number of limited partner units outstanding used for diluted net income per unit calculation		66,549			66,851			66,547			66,812

See notes to consolidated financial statements.

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(In thousands)


	December 31, 2007			June 30, 2008
				(Unaudited)
ASSETS
Current assets:
Accounts receivable (less allowance for doubtful accounts of $10 and $34 at December 31, 2007 and June 30, 2008, respectively)	$	62,834		$	69,133
Other accounts receivable		10,696			9,630
Affiliate accounts receivable		208			54
Inventory		120,462			75,672
Other current assets		10,882			20,322

Total current assets		205,082			174,811
Property, plant and equipment		2,435,890			2,570,649
Less: accumulated depreciation		615,329			645,871

Net property, plant and equipment		1,820,561			1,924,778
Equity investments		24,324			23,606
Long-term receivables		7,506			7,315
Goodwill		23,945			26,809
Other intangibles (less accumulated amortization of $6,743 and $7,516 at December 31, 2007 and June 30, 2008, respectively)		7,086			6,313
Debt placement costs (less accumulated amortization of $2,170 and $2,507 at December 31, 2007 and June 30, 2008, respectively)		6,368			6,031
Other noncurrent assets		6,322			3,220

Total assets	$	2,101,194		$	2,172,883

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	39,622		$	43,471
Affiliate accounts payable		12,947			1,732
Affiliate payroll and benefits		23,364			19,516
Accrued interest payable		7,197			6,985
Accrued taxes other than income		21,039			20,221
Environmental liabilities		36,127			24,468
Deferred revenue		20,797			23,952
Accrued product purchases		43,230			66,107
Other current liabilities		16,322			18,831

Total current liabilities		220,645			225,283
Long-term debt		914,536			951,917
Long-term affiliate payable		1,878			479
Long-term affiliate pension and benefits		22,370			25,923
Supply agreement deposit		18,500			—
Noncurrent portion of product supply liability		24,348			—
Other deferred liabilities		6,081			6,301
Environmental liabilities		21,672			20,117
Commitments and contingencies
Partners’ capital:
Partners’ capital		882,642			953,767
Accumulated other comprehensive loss		(11,478	)		(10,904	)

Total partners’ capital		871,164			942,863

Total liabilities and partners’ capital	$	2,101,194		$	2,172,883

See notes to consolidated financial statements.

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, in thousands)


	Six Months Ended June 30,
	2007			2008
Operating Activities:
Net income	$	111,154		$	187,696
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		31,135			34,610
Debt placement fee amortization		1,799			337
Debt prepayment premium		1,984			—
Loss on sale and retirement of assets		4,333			1,729
Equity earnings		(1,869	)		(1,782	)
Distributions from equity investments		2,325			2,500
Equity method incentive compensation expense		1,261			2,438
Amortization of prior service cost and net actuarial loss		998			656
Gain on assignment of supply agreement		—			(26,492	)
Changes in components of operating assets and liabilities:
Accounts receivable and other accounts receivable		521			(5,233	)
Affiliate accounts receivable		175			154
Inventory		(3,770	)		44,790
Accounts payable		(18,628	)		(3,423	)
Affiliate accounts payable		(295	)		(2,679	)
Affiliate payroll and benefits		(3,609	)		(3,848	)
Accrued interest payable		(1,431	)		(212	)
Accrued taxes other than income		985			(818	)
Accrued product purchases		(34,271	)		22,877
Restricted cash		5,283			—
Supply agreement deposit		2,500			(18,500	)
Current and noncurrent environmental liabilities		3,210			(13,214	)
Other current and noncurrent assets and liabilities		917			(3,880	)

Net cash provided by operating activities		104,707			217,706

Investing Activities:
Property, plant and equipment:
Additions to property, plant and equipment		(89,108	)		(132,016	)
Proceeds from sale of assets		950			1,600
Changes in accounts payable		(10,416	)		7,272
Acquisition of business		—			(12,010	)

Net cash used by investing activities		(98,574	)		(135,154	)

Financing Activities:
Distributions paid		(114,412	)		(129,588	)
Net borrowings under revolver		101,500			36,300
Borrowings under notes		248,900			—
Payments on notes		(272,555	)		—
Debt placement costs		(2,546	)		—
Payment of debt prepayment premium		(1,984	)		—
Net receipt from financial derivatives		4,556			4,030
Capital contributions by affiliate		37,294			2,045
Change in outstanding checks		—			4,661

Net cash provided (used) by financing activities		753			(82,552	)

Change in cash and cash equivalents		6,886			—
Cash and cash equivalents at beginning of period		6,390			—

Cash and cash equivalents at end of period	$	13,276		$	—


Supplemental non-cash financing activity:
Issuance of common units in settlement of long-term incentive plan awards	$	7,406		$	8,536

See notes to consolidated financial statements.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Basis of Presentation

Organization

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, Magellan Midstream Holdings, L.P.’s general partner, to provide all general and administrative (“G&A”) services and operating functions required for our operations. Our organizational structure at June 30, 2008, 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

Basis of Presentation

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 January 2008, we acquired a petroleum products terminal in Bettendorf, Iowa for $12.0 million. The results of this facility have been included in our petroleum products pipeline system segment from the acquisition date.

In the opinion of management, our accompanying consolidated financial statements, which are unaudited except for the consolidated balance sheet as of December 31, 2007, which is derived from audited financial statements, include all normal and recurring adjustments necessary to present fairly our financial position as of June 30, 2008, and the results of operations for the three and six months ended June 30, 2007 and 2008 and cash flows for the six months ended June 30, 2007 and 2008. The results of operations for the three and six months ended June 30, 2008 are not necessarily indicative of the results to be expected for the full year ending December 31, 2008.

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, 2007.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. Allocation of Net Income

For purposes of calculating earnings per unit, the allocation of net income between our general partner and limited partners was as follows (in thousands):


	Three Months Ended June 30,						Six Months Ended June 30,
	2007			2008			2007			2008
Allocation of net income to general partner:
Net income	$	61,452		$	94,374		$	111,154		$	187,696
Direct charges to the general partner:
Reimbursable G&A costs (a)		1,604			408			1,880			816
Previously indemnified environmental charges (b)		622			(11,291	)		2,872			(9,762	)

Total direct charges (credits) to general partner		2,226			(10,883	)		4,752			(8,946	)

Income before direct charges (credits) to general partner		63,678			83,491			115,906			178,750
General partner’s share of income (c)		31.23	%		35.64	%		30.43	%		36.58	%

General partner’s allocated share of net income before direct charges (credits)		19,888			29,755			35,265			65,394
Direct charges (credits) to general partner		2,226			(10,883	)		4,752			(8,946	)

Net income allocated to general partner	$	17,662		$	40,638		$	30,513		$	74,340


Net income	$	61,452		$	94,374		$	111,154		$	187,696
Less: net income allocated to general partner		17,662			40,638			30,513			74,340

Net income allocated to limited partners	$	43,790		$	53,736		$	80,641		$	113,356

(a)

Reimbursable G&A costs for the three and six months ended June 30, 2007 include a $1.3 million non-cash expense related to a payment made by MGG MH to one of our executive officers in connection with the sale by MGG MH of limited partner interests in MGG. This item did not impact cash available for distributions.

(b)

During the current quarter, we reached an agreement with the Environmental Protection Agency (“EPA”) and the U. S. Department of Justice (“DOJ”) to settle penalties proposed by the EPA associated with petroleum discharges from our pipeline. As a result of the settlement agreement, we reduced our environmental liability for this matter from $17.4 million to $5.3 million, resulting in a reduction to our operating expenses of $12.1 million. Of this reduction amount, $11.9 million was included as part of the indemnification settlement we reached with a former affiliate (see Note 10—Commitments and Contingencies for further discussion of this matter) and, accordingly, was allocated to our general partner. As a result, limited partner net income and earnings per limited partner unit were impacted by only $0.2 million of the $12.1 million reduction in operating expense.

(c)

For periods when the distributions we pay exceed our net income, our general partner’s percentage share of income is its proportion of cash distributions paid for the period. For periods when our net income exceeds the cash distributions we pay, our general partner’s percentage share of income is its proportion of theoretical distributions that equal net income (before direct charges to general partner). For the second quarter of 2007 and 2008, a per unit theoretical cash distribution of $0.658 and $0.805, respectively, would have resulted in total distributions equal to net income before direct charges to our general partner for each period. Our general partner’s share of net income for the six months ended June 30, 2007 is based on its share of actual distributions paid for the first quarter and theoretical distributions for the second quarter. Our general partner’s share of net income for the six months ended June 30, 2008 is based on its share of theoretical distributions for the first and second quarters of the year.

The reimbursable G&A costs above represent G&A expenses charged against our income during the periods presented that were reimbursed to us by our general partner under the terms of the omnibus agreement or by separate arrangement. Because the limited partners did not share in these costs, we allocated these G&A expense amounts directly to our general partner. We record these reimbursements by our general partner as capital contributions.

Prior to 2007, 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 (see Note 10—Commitments and Contingencies). 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)

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 owners and distributions to owners. The term other comprehensive income 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 our derivative instruments, see Note 9 – Derivative Financial Instruments.


	Three Months Ended June 30,					Six Months Ended June 30,
	2007		2008			2007		2008
Net income	$	61,452	$	94,374		$	111,154	$	187,696
Change in fair value of cash flow hedges		2,075		6,706			5,018		—
Amortization of net loss (gain) on cash flow hedges		92		(41	)		145		(82	)
Amortization of prior service cost and net actuarial loss		614		279			998		656

Other comprehensive income		2,781		6,944			6,161		574

Comprehensive income	$	64,233	$	101,318		$	117,315	$	188,270

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 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 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.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


	Three Months Ended June 30, 2007
	(in thousands)
	Petroleum Products Pipeline System			Petroleum Products Terminals		Ammonia Pipeline System			Intersegment Eliminations			Total
Transportation and terminals revenues	$	114,385		$	32,014	$	4,498		$	(827	)	$	150,070
Product sales revenues		174,471			3,431		—			—			177,902
Affiliate management fee revenue		183			—		—			—			183

Total revenues		289,039			35,445		4,498			(827	)		328,155
Operating expenses		42,314			13,145		5,981			(1,413	)		60,027
Product purchases		154,933			1,786		—			(131	)		156,588
Equity earnings		(1,106	)		—		—			—			(1,106	)

Operating margin (loss)		92,898			20,514		(1,483	)		717			112,646
Depreciation and amortization		9,795			4,989		194			717			15,695
Affiliate G&A expenses		12,703			4,412		626			—			17,741

Operating profit (loss)	$	70,400		$	11,113	$	(2,303	)	$	—		$	79,210


	Three Months Ended June 30, 2008
	(in thousands)
	Petroleum Products Pipeline System			Petroleum Products Terminals		Ammonia Pipeline System		Intersegment Eliminations			Total
Transportation and terminals revenues	$	121,169		$	35,970	$	5,986	$	(758	)	$	162,367
Product sales revenues		102,585			7,779		—		—			110,364
Affiliate management fee revenue		183			—		—		—			183

Total revenues		223,937			43,749		5,986		(758	)		272,914
Operating expenses		39,977			15,685		2,812		(1,509	)		56,965
Product purchases		73,577			1,845		—		(130	)		75,292
Equity earnings		(1,377	)		—		—		—			(1,377	)

Operating margin		111,760			26,219		3,174		881			142,034
Depreciation and amortization		10,553			5,798		202		881			17,434
Affiliate G&A expenses		12,976			4,459		1,019		—			18,454

Operating profit	$	88,231		$	15,962	$	1,953	$	—		$	106,146

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


	Six Months Ended June 30, 2007
	(in thousands)
	Petroleum Products Pipeline System			Petroleum Products Terminals		Ammonia Pipeline System			Intersegment Eliminations			Total
Transportation and terminals revenues	$	221,696		$	63,763	$	9,413		$	(1,651	)	$	293,221
Product sales revenues		318,736			7,829		—			—			326,565
Affiliate management fee revenue		356			—		—			—			356

Total revenues		540,788			71,592		9,413			(1,651	)		620,142
Operating expenses		85,256			27,106		11,520			(2,880	)		121,002
Product purchases		286,359			4,468		—			(259	)		290,568
Equity earnings		(1,869	)		—		—			—			(1,869	)

Operating margin (loss)		171,042			40,018		(2,107	)		1,488			210,441
Depreciation and amortization		19,425			9,832		390			1,488			31,135
Affiliate G&A expenses		25,233			8,939		1,254			—			35,426

Operating profit (loss)	$	126,384		$	21,247	$	(3,751	)	$	—		$	143,880


	Six Months Ended June 30, 2008
	(in thousands)
	Petroleum Products Pipeline System			Petroleum Products Terminals		Ammonia Pipeline System			Intersegment Eliminations			Total
Transportation and terminals revenues	$	227,492		$	69,571	$	11,406		$	(1,510	)	$	306,959
Product sales revenues		295,482			16,600		—			—			312,082
Affiliate management fee revenue		366			—		—			—			366

Total revenues		523,340			86,171		11,406			(1,510	)		619,407
Operating expenses		82,237			28,214		5,066			(2,960	)		112,557
Product purchases		248,198			4,922		—			(260	)		252,860
Gain on assignment of supply agreement		(26,492	)		—		—			—			(26,492	)
Equity earnings		(1,782	)		—		—			—			(1,782	)

Operating margin		221,179			53,035		6,340			1,710			282,264
Depreciation and amortization		20,934			11,562		404			1,710			34,610
Affiliate G&A expenses		25,717			8,574		1,943			—			36,234

Operating profit	$	174,528		$	32,899	$	3,993		$	—		$	211,420

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

5. Related Party Disclosures

Affiliate Entity Transactions

We have a 50% ownership interest in a crude oil pipeline company and are paid a management fee for its operation. During both the three months ended June 30, 2007 and 2008, we received operating fees from this pipeline company of $0.2 million, which we reported as affiliate management fee revenue. Affiliate management fee revenue for both the six months ended June 30, 2007 and 2008 was $0.4 million.

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


	Three Months Ended June 30,		Six Months Ended June 30,
	2007	2008	2007	2008
MGG GP—allocated operating expenses	19,672	21,632	38,875	42,552
MGG GP—allocated G&A expenses	12,026	12,220	22,377	24,093

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, 2007 and June 30, 2008 were $23.4 million and $19.5 million, respectively, and the long-term affiliate pension and benefits accruals associated with this agreement at December 31, 2007 and June 30, 2008 were $22.4 million and $25.9 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 when MGG makes contributions to MGG GP’s pension funds.

MGG has agreed to reimburse us for G&A expenses (excluding equity-based compensation) in excess of a G&A cap. We do not expect to receive reimbursements under this agreement beyond 2008. The amount of G&A costs required to be reimbursed by MGG to us was $0.3 million and $0.6 million for the three and six months ended June 30, 2007, respectively, and $0.4 million and $0.8 million for the three and six months ended June 30, 2008, respectively. Reimbursable G&A costs for the three and six months ended June 30, 2007 also included a $1.3 million non-cash expense related to a payment by MGG MH to one of our executive officers in connection with the sale by MGG MH of limited partner interests in MGG.

Other Related Party Transactions

MGG, which owns our general partner, is partially owned by MGG MH, which is partially owned by an affiliate of Carlyle/Riverstone Global Energy and Power Fund II, L.P. (“CRF”). During the period of January 1 through January 30, 2007, one or more of the members of our general partner’s eight-member board of directors was a representative of CRF. CRF is part of an investment group that has purchased Knight, Inc. (formerly known as Kinder Morgan, Inc.). To alleviate competitive concerns the Federal Trade Commission (“FTC”) raised regarding this transaction, CRF agreed with the FTC to remove their representatives from our general partner’s board of directors, and all of the representatives of CRF voluntarily resigned from the board of directors of our general partner in January 2007.

During the period January 1 through January 30, 2007, CRF had total combined general and limited partner interests in SemGroup, L.P. (“SemGroup”) of approximately 30%. During the aforementioned time period, one of the members of the seven-member board of directors of SemGroup’s general partner was a representative of CRF, with three votes on that board. Through our affiliates, we were a party to a number of arms-length transactions with SemGroup and its affiliates, which we had historically disclosed as related party transactions. For accounting purposes, we have not classified SemGroup as a related party since the voluntary resignation of the CRF representatives from our general partner’s board of directors as of January 30, 2007. A summary of our transactions with SemGroup during the period of January 1 through January 30, 2007 is provided in the following table (in millions):

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


	Period From January 1, 2007 Through January 30, 2007
Product sales revenues	$	20.5
Product purchases		14.5
Terminalling and other services revenues		0.3
Storage tank lease revenues		0.4
Storage tank lease expense		0.1

In addition to the above, we provided common carrier transportation services to SemGroup.

One of our general partner’s independent board members, John P. DesBarres, currently serves as a board member for American Electric Power Company, Inc. (“AEP”) of Columbus, Ohio. During the three and six months ended June 30, 2007, our operating expenses included $0.7 million and $1.3 million, respectively, of power costs incurred with Public Service Company of Oklahoma (“PSO”), which is a subsidiary of AEP. During the three and six months ended June 30, 2008, our operating expenses included $0.6 million and $1.1 million, respectively, of power costs incurred with PSO. We had a $0.2 million receivable from PSO at June 30, 2008 resulting from an annual stand-by agreement for fuel oil. We had no other amounts payable to or receivable from PSO or AEP at either December 31, 2007 or June 30, 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 June 30, 2008, certain of our executive officers collectively owned approximately 5% of MGG MH, which owned approximately 14% of MGG, the owner of our general partner. Therefore, certain of our executive officers also benefit from distributions 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 $0.6875 per unit, our general partner would receive annual distributions of approximately $87.6 million on its combined general partner interest and incentive distribution rights.

6. Inventory

Inventory at December 31, 2007 and June 30, 2008 was as follows (in thousands):


	December 31, 2007		June 30, 2008
Refined petroleum products	$	65,215	$	—
Transmix		32,824		40,497
Natural gas liquids		16,233		29,686
Additives		5,812		5,489
Other		378		—

Total inventory	$	120,462	$	75,672

The decrease in inventory between December 31, 2007 and June 30, 2008 was primarily attributable to the sale of refined petroleum products inventory in connection with the assignment of our product supply agreement to a third-party entity effective March 1, 2008 (see Note 14—Assignment of Supply Agreement).

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. Employee Benefit Plans

MGG GP sponsors two pension plans for union employees, a pension plan for non-union employees and a postretirement benefit plan for selected employees. The following tables present our consolidated net periodic benefit costs related to these plans during the three and six months ended June 30, 2007 and 2008 (in thousands):


	Three Months Ended June 30, 2007					Six Months Ended June 30, 2007
	Pension Benefits			Other Post-Retirement Benefits		Pension Benefits			Other Post-Retirement Benefits
Components of Net Periodic Benefit Costs:
Service cost	$	1,423		$	143	$	2,897		$	267
Interest cost		656			288		1,290			513
Expected return on plan assets		(519	)		—		(1,092	)		—
Amortization of prior service cost		170			43		339			88
Amortization of actuarial loss		168			233		227			344

Net periodic benefit cost	$	1,898		$	707	$	3,661		$	1,212


	Three Months Ended June 30, 2008					Six Months Ended June 30, 2008
	Pension Benefits			Other Post-Retirement Benefits		Pension Benefits			Other Post-Retirement Benefits
Components of Net Periodic Benefit Costs:
Service cost	$	1,323		$	77	$	2,736		$	218
Interest cost		695			237		1,349			515
Expected return on plan assets		(732	)		—		(1,351	)		—
Amortization of prior service cost		170			44		339			88
Amortization of actuarial loss		59			6		75			154

Net periodic benefit cost	$	1,515		$	364	$	3,148		$	975

Contributions estimated to be paid in 2008 are $6.0 million and $0.2 million for the pension and other postretirement benefit plans, respectively.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. Debt

Our debt at December 31, 2007 and June 30, 2008 was as follows (in thousands):


	December 31, 2007		June 30, 2008
Revolving credit facility	$	163,500	$	199,800
6.45% Notes due 2014		249,634		249,657
5.65% Notes due 2016		252,494		253,546
6.40% Notes due 2037		248,908		248,914

Total debt	$	914,536	$	951,917

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 rating. As of June 30, 2008, $199.8 million was outstanding under this facility, and $3.3 million was obligated for letters of credit. Amounts obligated for letters of credit are not reflected as debt on our consolidated balance sheets. The weighted-average interest rate on borrowings outstanding under the facility at June 30, 2007 and 2008 was 5.8% and 2.9%, respectively. The borrowings outstanding under this facility were repaid with the net proceeds from our debt offering of 10-year senior notes completed in July 2008 (see Note 16—Subsequent Events).

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. Including the impact of amortizing the gains realized on the hedges associated with these notes (see Note 9–Derivative Financial Instruments), the effective interest rate of these notes is 6.3%.

5.65% Notes due 2016. In October 2004, we issued $250.0 million of 5.65% senior 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. We used an interest rate swap to effectively convert $100.0 million of these notes to floating-rate debt until May 2008 (see Note 9—Derivative Financial Instruments). Including the impact of that swap, and the amortization of losses realized on pre-issuance hedges associated with these notes, the weighted average interest rate of these notes at June 30, 2007 was 6.0%. We received a payment of $3.8 million when we terminated the swap-to-floating derivative instrument in May 2008. Including the amortization of that payment and the losses realized on pre-issuance hedges associated with these notes, the weighted average interest rate at June 30, 2008 was 5.7%. The outstanding principal amount of the notes was increased by $2.7 million at December 31, 2007 for the fair value of the associated swap-to-floating derivative instrument and by $3.8 million at June 30, 2008 for the unamortized portion of the payment received upon termination of that swap.

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. Including the impact of amortizing the gains realized on the interest hedges associated with these notes (see Note 9—Derivative Financial Instruments), the effective interest rate of these notes is 6.3%.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. Derivative Financial Instruments

We use interest rate derivatives to help manage interest rate risk. As of June 30, 2008, we had no interest rate swap agreements outstanding. See Note 16 – Subsequent Events for additional information related to interest rate swap agreements entered into subsequent to June 30, 2008.

In October 2004, we entered into an interest rate swap agreement to hedge against changes in the fair value of a portion of the $250.0 million of senior notes due 2016, which were issued in October 2004. We accounted for this agreement as a fair value hedge. The notional amount of this agreement was $100.0 million and effectively converted $100.0 million of our 5.65% fixed-rate senior notes issued in October 2004 to floating-rate debt. In May 2008, we terminated this interest rate swap agreement and received $3.8 million, which was recorded as an adjustment to long-term debt and is being amortized over the remaining life of the 5.65% fixed-rate senior notes due 2016.

In January 2008, we entered into a total of $200.0 million of forward starting interest rate swap agreements to hedge against the variability of future interest payments on debt that we anticipated issuing no later than June 2008. Proceeds of the anticipated debt issuance were expected to be used to refinance borrowings on our revolving credit facility. In April 2008, we terminated these interest rate swap agreements and received $0.2 million, which was recorded to other income.

The following is a summary of the current impact of our historical derivative activity as of June 30, 2008 (in thousands):


	Effective Portion of Gains and Losses
				Amount Reclassified to Earnings from Accumulated Other Comprehensive Income (“AOCI”)
Hedge	Unamortized Amount Recognized in AOCI			Three Months Ended June 30, 2008			Six Months Ended June 30, 2008
Cash flow hedges (date executed):
Interest rate swaps 6.40% Notes (April 2007)	$	5,044		$	(44	)	$	(88	)
Interest rate swaps 5.65% Notes (October 2004)		(4,338	)		131			262
Interest rate swaps and treasury lock 6.45% Notes (May 2004)		3,029			(128	)		(256	)

Total cash flow hedges	$	3,735		$	(41	)	$	(82	)

There was no ineffectiveness recognized on the financial instruments disclosed in the above table during the three or six months ended June 30, 2008.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10. Commitments and Contingencies

Environmental Liabilities. Liabilities recognized for estimated environmental costs were $57.8 million and $44.6 million at December 31, 2007 and June 30, 2008, 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.

Our environmental liabilities include, among other items, accruals for the items discussed below:

Petroleum Products EPA Issue. In July 2001, the EPA, pursuant to Section 308 of the Clean Water Act (the “Act”), served an information request to a former affiliate with regard to petroleum discharges from its pipeline operations. That inquiry primarily focused on the petroleum products pipeline system that we subsequently acquired. The response to the EPA’s information request was submitted during November 2001. In March 2004, we received an additional information request from the EPA and notice from the DOJ that the EPA had requested the DOJ to initiate a lawsuit alleging violations of Section 311(b) of the Act in regards to 32 releases. The DOJ stated that the maximum statutory penalty for the releases was in excess of $22.0 million, which assumed that all of the releases were violations of the Act and that the EPA would impose the maximum penalty. The EPA further indicated that some of those releases may have also violated the Spill Prevention Control and Countermeasure requirements of Section 311(j) of the Act and that additional penalties could be assessed. The DOJ and EPA added to their original demand a release that occurred in the second quarter of 2005 from our petroleum products pipeline near our Kansas City, Kansas terminal and a release that occurred in the first quarter of 2006 from our petroleum products pipeline near Independence, Kansas.

We reached an agreement with the EPA and DOJ to settle these matters in June 2008. Under the terms of the settlement agreement, we will pay a penalty of $5.3 million and will perform certain operational enhancements resulting in a reduction of our environmental liability for these matters from $17.4 million to $5.3 million and a reduction of our operating expenses of $12.1 million. Of this reduction, $11.9 million was included as part of the indemnification settlement we reached with a former affiliate (see Indemnification Settlement description below) and, accordingly, was allocated to our general partner.

Ammonia EPA Issue. In February 2007, we received notice from the DOJ that the EPA had requested the DOJ to initiate a lawsuit alleging violations of Sections 301 and 311 of the Act with respect to two releases of anhydrous ammonia from the ammonia pipeline owned by us and, at the time of the releases, operated by a third party. 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. We believe that we do not have an obligation to indemnify or defend the third-party operator for the DOJ criminal fine settlement. 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; however, we are unable to determine what our ultimate liability could be for these matters. Adjustments to our recorded liability, which could occur in the near term, could be material to our results of operations and cash flows.

PCB Impacts. We have completed our assessment of polychlorinated biphenyls (“PCB”) impacts at two of our petroleum products terminals and have concluded that the costs of any corrective actions associated with PCB contamination will not be material to our results of operations and cash flows.

Indemnification Settlement. Prior to May 2004, a former affiliate had agreed to indemnify us against, among other things, certain environmental losses associated with assets contributed to us at the time of our initial public offering or which we subsequently acquired from this former affiliate. In May 2004, our general partner entered into an agreement under which our former affiliate agreed to pay us $117.5 million to release it from these indemnifications. We received the final installment payment associated with this agreement in 2007. At December 31, 2007 and June 30, 2008, known liabilities that would have been covered by this indemnity agreement were $42.9 million and $29.4 million, respectively. Through June 30, 2008, we have spent $50.8 million of the $117.5 million indemnification settlement amount for indemnified matters, including $21.9 million of capital costs. The cash we have received from the indemnity settlement is not reserved and has been used for our various other cash needs, including expansion capital spending.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Environmental Receivables. Receivables from insurance carriers and other entities related to environmental matters were $6.9 million and $5.5 million at December 31, 2007 and June 30, 2008, respectively.

Unrecognized Product Gains. Our petroleum products terminals operations generate product overages and shortages. 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 $11.4 million as of June 30, 2008. 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

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 compensation committee of our general partner’s board of directors (the “Compensation Committee”) administers the LTIP and has approved the unit awards discussed below.

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. The award grants do not have an early vesting feature except under certain circumstances following a change in control of our general partner.

The table below summarizes the unit awards granted by the Compensation Committee that have not vested as of June 30, 2008. There was no impact to our cash flows associated with these award grants for the periods presented in this report.


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)		Period Over Which the Unrecognized Expense Will Be Recognized	Intrinsic Value of Unvested Awards at June 30, 2008 (Millions)
February 2006	168,105	12,607	139,948		295,446	12/31/08	$	1.4	Next 6 months	$	10.5
Various 2006	9,201	3,132	5,462		11,531	12/31/08		0.1	Next 6 months		0.4
March 2007	2,640	—	—		2,640	12/31/08		0.1	Next 6 months		0.1
Various 2007:
– Tranche 1	53,230	2,396	50,834		101,668	12/31/09		1.7	Next 18 months		3.6
– Tranche 2	53,230	2,396	(28,721	)	22,113	12/31/09		0.6	Next 18 months		0.8
– Tranche 3	53,230	—	—		—	12/31/09		—	—		—
January 2008	184,340	8,295	—		176,045	12/31/10		4.9	Next 30 months		6.3
Various 2008	2,890	—	—		2,890	12/31/10		0.1	Next 30 months		0.1

Total	526,866	28,826	167,523		612,333		$	8.9		$	21.8

2008 Activity

We settled our 2005 award grants in January 2008 by issuing 196,856 limited partner units and distributing those units to the participants. We paid associated minimum tax withholdings and employer taxes totaling $5.1 million in January 2008.

Payout for the unit awards approved during February 2006 are based eighty percent on the attainment of performance metrics and are being accounted for as equity and twenty percent on personal performance in addition to the company’s performance metrics and are being accounted for as liabilities.

The unit awards approved during 2007, except the March 2007 unit awards, are broken into three equal tranches, with each tranche vesting on December 31, 2009. We began accruing for the first tranche of the 2007 awards in the first quarter of 2007 and began accruing for the second tranche in the first quarter of 2008, when the Compensation Committee established the performance metrics associated with each respective tranche. We will begin accruing costs for the third tranche when the Compensation Committee establishes the associated performance metrics for that tranche, which we expect to happen in the first quarter of 2009. Eighty percent of these unit awards are based on the attainment of performance metrics and are being accounted for as equity and twenty percent of these unit awards are based on personal performance in addition to the company’s performance metrics and are being accounted for as liabilities.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The unit awards approved in January 2008 will vest on December 31, 2010. Eighty percent of these unit awards are based on the attainment of performance metrics and are being accounted for as equity and twenty percent of these unit awards are based on personal performance in addition to the company’s performance metrics and are being accounted for as liabilities. The other various unit awards approved in 2008 will also vest on December 31, 2010. There are no performance metrics associated with these awards and they are being accounted for as equity.

Weighted Average Fair Value

The weighted average fair value of the unit awards is as follows (per unit):


	Grant Date Fair Value of Equity Awards		June 30, 2008 Fair Value of Liability Awards
2006 Awards	$	25.23	$	34.21
2007 Awards	$	33.62	$	31.32
2008 Awards	$	33.28	$	28.28

Compensation Expense Summary

Our equity-based incentive compensation expense for the three and six months ended June 30, 2007 and 2008 is as follows (in thousands):


	Three Months Ended June 30, 2007								Six Months Ended June 30, 2007
	Equity Method		Liability Method		Employer Taxes Paid		Total		Equity Method		Liability Method		Employer Taxes Paid		Total
2004 awards	$	—	$	—	$	—	$	—	$	—	$	—	$	519	$	519
2005 awards		—		1,197		—		1,197		—		3,487		—		3,487
2006 awards		513		230		—		743		980		505		—		1,485
2007 awards		211		59		—		270		281		88		—		369

Total	$	724	$	1,486	$	—	$	2,210	$	1,261	$	4,080	$	519	$	5,860


	Three Months Ended June 30, 2008									Six Months Ended June 30, 2008
	Equity Method		Liability Method			Employer Taxes Paid		Total		Equity Method		Liability Method		Employer Taxes Paid		Total
2005 awards	$	—	$	—		$	—	$	—	$	—	$	26	$	580	$	606
2006 awards		645		(8	)		—		637		1,120		167		—		1,287
2007 awards		259		20			—		279		635		100		—		735
2008 awards		395		79			—		474		683		143		—		826

Total	$	1,299	$	91		$	—	$	1,390	$	2,438	$	436	$	580	$	3,454

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12. Distributions

We paid the following distributions during 2007 and 2008 (in thousands, except per unit amounts):


Date Cash Distribution Paid	Per Unit Cash Distribution Amount		Common Units		General Partner		Total Cash Distribution
02/14/07	$	0.60250	$	40,094	$	16,197	$	56,291
05/15/07		0.61625		41,009		17,112		58,121

Through 6/30/07		1.21875		81,103		33,309		114,412
08/14/07		0.63000		41,924		18,027		59,951
11/14/07		0.64375		42,839		18,942		61,781

Total	$	2.49250	$	165,866	$	70,278	$	236,144


02/14/08	$	0.65750	$	43,884	$	19,909	$	63,793
05/15/08		0.67250		44,885		20,910		65,795

Through 6/30/08		1.33000		88,769		40,819		129,588
08/14/08^(a)		0.68750		45,886		21,911		67,797

Total	$	2.01750	$	134,655	$	62,730	$	197,385

(a)	Our general partner declared this cash distribution in July 2008 to be paid on August 14, 2008 to unitholders of record at the close of business on August 6, 2008.

13. Net Income Per Unit

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


	Three Months Ended June 30, 2007					Six Months Ended June 30, 2007
	Income (Numerator)		Units (Denominator)	Per Unit Amount		Income (Numerator)		Units (Denominator)	Per Unit Amount
Basic net income per limited partner unit	$	43,790	66,549	$	0.66	$	80,641	66,543	$	1.21
Effect of dilutive restricted unit grants		—	—		—		—	4		—

Diluted net income per limited partner unit	$	43,790	66,549	$	0.66	$	80,641	66,547	$	1.21


	Three Months Ended June 30, 2008					Six Months Ended June 30, 2008
	Income (Numerator)		Units (Denominator)	Per Unit Amount		Income (Numerator)		Units (Denominator)	Per Unit Amount
Basic net income per limited partner unit	$	53,736	66,851	$	0.80	$	113,356	66,812	$	1.70
Effect of dilutive restricted unit grants		—	—		—		—	—		—

Diluted net income per limited partner unit	$	53,736	66,851	$	0.80	$	113,356	66,812	$	1.70

Units reported as dilutive securities are related to phantom unit grants (see Note 11 – Long-Term Incentive Plan).

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

14. 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 that time, 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, therefore, 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 the first quarter 2008, we obtained a full release from our supply customer; therefore, we have no future obligation to perform under this supply agreement, even in the event the third-party assignee is unable to perform its obligations under the agreement. We will continue to earn transportation revenues for the product we ship related to this supply agreement but will no longer hold related inventories or recognize associated product sales and purchases. As part of this assignment, we agreed with the assignee that if the pricing under the supply agreement does not exceed our full tariff charge, then we will share in 50% of any shortfall versus our full tariff, and similarly, we will be entitled to 50% of any excess above a certain threshold that includes our tariff charge. All adjustments resulting from this agreement will be reflected in transportation and terminals revenues. During the second quarter of 2008, our 50% share of the shortfall under this agreement was $0.3 million.

Excluding transportation revenues for products shipped under this product supply agreement, we recognized operating profit of $6.1 million and $7.1 million during the three and six months ended June 30, 2007, respectively, related to the supply agreement. We recognized $2.9 million of operating profit associated with the agreement during first quarter 2008 and no operating profit in second quarter 2008. We recognized a gain of $26.5 million during first quarter 2008 associated with assignment of this agreement.

15. Recent Accounting Standard

In March 2008, the Financial Accounting Standards Board (“FASB”) ratified 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 and/or excess of earnings over distributions for each period are required to be 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 current accounting practice is to allocate net income to the general partner based on the general partner’s share of total or theoretical distributions, as appropriate, including incentive distribution rights. The effect of adopting this EITF will be: (i) for periods when net income exceeds distributions, our reported earnings per limited partner unit will be higher than under our current accounting practice and (ii) for periods when distributions exceed net income, our reported earnings per limited partner unit will be lower than under our current 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 example, had we applied EITF 07-4 to the 2008 reporting periods, basic and diluted earnings per limited partner unit would have increased from $0.80 to $0.92 and from $1.70 to $2.02 for the three and six months ended June 30, 2008, respectively. This EITF is effective beginning January 1, 2009, including all interim periods after that date. Early application is not permitted. This EITF is required to be applied retrospectively; therefore, we will restate prior period earnings per limited partner unit in all published financial reports after January 1, 2009, as applicable.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

16. Subsequent Events

In July 2008, we issued $250.0 million of 6.40% notes due 2018 in an underwritten public offering. Net proceeds from the offering, after underwriter discounts of $1.6 million and estimated offering costs of $0.5 million, were $247.9 million. The net proceeds were used to repay the $212.0 million of borrowings outstanding under our revolving credit facility at that time, with the balance to be used for general partnership purposes. In connection with this offering, we entered into $100.0 million of interest rate swap agreements to hedge against changes in the fair value of a portion of these notes. These agreements effectively change the interest rate on $100.0 million of these notes from 6.40% to a floating rate of six-month LIBOR plus 1.83%. The swap agreements expire on July 15, 2018, the maturity date of the 6.40% notes.

SemGroup, L.P. and several of its subsidiaries (“SemGroup”) filed for chapter 11 bankruptcy protection during July 2008. Amounts owed to us by SemGroup at the time of their bankruptcy filing were insignificant.

We are parties to several commercial arrangements with SemGroup for the purchase and sale of petroleum products and natural gas liquids (“NGLs”), transportation of petroleum products and NGLs, lease storage and capacity leases for petroleum products and NGLs and leasing of terminal and tank facilities to or from SemGroup. Under bankruptcy laws, SemGroup has the ability to cancel all of the existing contracts it has with us. If they do so, we believe we will be able to replace those contracts with other counterparties on terms similar to those in our contracts with SemGroup. On July 31, 2008, we exercised our right to cancel forward petroleum product sales contracts with SemGroup pursuant to which we had agreed to sell to SemGroup petroleum products at various dates between August 2008 and April 2009. We believe we will be able to replace these contracts with new forward sales contracts with other counterparties or with New York Mercantile Exchange contracts that hedge against changes in product prices.

We do not expect a material adverse effect on our consolidated results of operations, cash flows or financial position from the SemGroup bankruptcy. However, bankruptcy proceedings are inherently unpredictable and decisions of the bankruptcy court that we cannot foresee at this time could result in a material adverse effect on our consolidated results of operations, cash flows or financial position.

In July 2008, our general partner declared a quarterly distribution of $0.6875 per unit to be paid on August 14, 2008 to unitholders of record at the close of business on August 6, 2008. Total distributions to be paid under this declaration are approximately $67.8 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 June 30, 2008, our three operating segments include:

•

petroleum products pipeline system, which is primarily comprised of our 8,500-mile petroleum products pipeline system, including 47 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, 2007.

Recent Developments

Distribution. During July 2008, the board of directors of our general partner declared a quarterly cash distribution of $0.6875 per unit for the period of April 1 through June 30, 2008, representing the twenty-ninth consecutive distribution increase since our initial public offering in February 2001. This quarterly distribution will be paid on August 14, 2008 to unitholders of record on August 6, 2008.

Debt issuance and repayment of credit facility borrowings. In July 2008, we issued $250.0 million of 6.40% notes due 2018 in an underwritten public offering. Net proceeds from the offering, after underwriting discounts and estimated offering costs, were $247.9 million. The net proceeds were primarily used to repay the $212.0 million of borrowings outstanding under our revolving credit facility at the time, with the balance to be used for general partnership purposes. In connection with this offering, we entered into interest rate swap agreements to hedge against changes in the fair value of $100.0 million of the notes. These agreements effectively change the interest rate on $100.0 million of those notes from 6.40% to a floating rate of six-month LIBOR plus 1.83%. The swap agreements expire on July 15, 2018, the maturity date of the 6.40% notes.

Customer bankruptcy. SemGroup, L.P. and several of its subsidiaries (“SemGroup”) filed for chapter 11 bankruptcy protection during July 2008. Amounts owed to us by SemGroup at the time of their bankruptcy filing were insignificant.

We are parties to several commercial arrangements with SemGroup for the purchase and sale of petroleum products and natural gas liquids (“NGLs”), transportation of petroleum products and NGLs, lease storage and capacity leases for petroleum products and NGLs and leasing of terminal and tank facilities to or from SemGroup. Under bankruptcy laws, SemGroup has the ability to cancel all of the existing contracts it has with us. If they do so, we believe we will be able to replace those contracts with other counterparties on terms similar to those in our contracts with SemGroup. On July 31, 2008, we exercised our right to cancel forward petroleum product sales contracts with SemGroup pursuant to which we had agreed to sell to SemGroup petroleum products at various dates between August 2008 and April 2009. We believe we will be able to replace these contracts with new forward sales contracts with other counterparties or with New York Mercantile Exchange (“NYMEX”) contracts that hedge against changes in product prices. To the extent we use NYMEX contracts, we could experience additional risks related to price basis differentials and margin calls.

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 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 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 tables below. Operating profit includes expense items, such as depreciation and amortization and affiliate general and administrative (“G&A”) costs, that management does not consider when evaluating the core profitability of our operations.

Three Months Ended June 30, 2007 Compared to Three Months Ended June 30, 2008


	Three Months Ended June 30,						Variance Favorable (Unfavorable)
	2007			2008			$ Change			% Change
Financial Highlights ($ in millions, except operating statistics)

Revenues:
Transportation and terminals revenues:
Petroleum products pipeline system	$	114.4		$	121.2		$	6.8		6
Petroleum products terminals		32.0			36.0			4.0		13
Ammonia pipeline system		4.5			6.0			1.5		33
Intersegment eliminations		(0.8	)		(0.8	)		—		—

Total transportation and terminals revenues		150.1			162.4			12.3		8
Product sales		177.9			110.3			(67.6	)	(38	)
Affiliate management fees		0.2			0.2			—		—

Total revenues		328.2			272.9			(55.3	)	(17	)
Operating expenses:
Petroleum products pipeline system		42.3			39.9			2.4		6
Petroleum products terminals		13.1			15.7			(2.6	)	(20	)
Ammonia pipeline system		6.0			2.8			3.2		53
Intersegment eliminations		(1.4	)		(1.4	)		—		—

Total operating expenses		60.0			57.0			3.0		5
Product purchases		156.6			75.3			81.3		52
Equity earnings		(1.1	)		(1.4	)		0.3		27

Operating margin		112.7			142.0			29.3		26
Depreciation and amortization expense		15.7			17.5			(1.8	)	(11	)
Affiliate G&A expense		17.8			18.4			(0.6	)	(3	)

Operating profit	$	79.2		$	106.1		$	26.9		34


Operating Statistics
Petroleum products pipeline system:
Transportation revenue per barrel shipped	$	1.146		$	1.169
Volume shipped (million barrels)		76.9			77.3
Petroleum products terminals:
Marine terminal average storage utilized (million barrels per month)		21.3			22.8
Inland terminal throughput (million barrels)		29.3			28.3
Ammonia pipeline system:
Volume shipped (thousand tons)		186			227

Transportation and terminals revenues increased by $12.3 million resulting from higher revenues for each of our business segments as shown below:

•

an increase in petroleum products pipeline system revenues of $6.8 million primarily attributable to higher average tariff rates as well as increased fees for leased storage, capacity leases and ethanol blending services. The 2008 period also benefited from slightly higher transportation volumes as increased shipments of liquefied petroleum gases (“LPGs”) offset lower gasoline volumes reflecting the impact on product demand from higher product prices;

•

an increase in petroleum products terminals revenues of $4.0 million due to higher revenues at both our marine and inland terminals. Marine revenues increased primarily due to operating results from additional storage tanks at our Galena Park, Texas facility that were placed into service throughout 2007 and second quarter 2008 and higher excess throughput fees. Inland revenues benefitted from higher additive and ethanol blending fees that offset lower throughput volumes; and

•

an increase in ammonia pipeline system revenues of $1.5 million due to higher average tariffs and additional shipments because of favorable farming conditions.

Operating expenses decreased by $3.0 million as lower expenses at our petroleum products pipeline system and ammonia pipeline system were partially offset by higher costs for our petroleum products terminals as described below:

•

a decrease in petroleum products pipeline system expenses of $2.4 million primarily due to the favorable settlement of a civil penalty related to historical product releases, which resulted in us reducing our liability accrual by $12.1 million during second quarter 2008 (see Environmental for additional discussion of this settlement), partially offset by less favorable product overages and higher maintenance spending in the current period;

•

an increase in petroleum products terminals expenses of $2.6 million primarily related to higher personnel costs, property taxes and maintenance spending; and

•

a decrease in ammonia pipeline system expenses of $3.2 million primarily due to lower environmental and maintenance costs. The 2007 period was negatively impacted by environmental charges related to a 2004 pipeline release and higher system integrity costs associated with high consequence area testing procedures. These favorable items were partially offset by transition costs in 2008 related to our assumption of operating responsibility for this pipeline during third quarter 2008.

Product sales revenues in the current period primarily resulted from our petroleum products blending operation, terminal product gains and transmix fractionation. Revenues from product sales were $110.3 million for the three months ended June 30, 2008 while product purchases were $75.3 million, resulting in gross margin from these transactions of $35.0 million. The gross margin resulting from product sales and purchases for the 2008 period increased $13.7 million compared to gross margin for the 2007 period of $21.3 million, resulting from product sales for the three months ended June 30, 2007 of $177.9 million and product purchases of $156.6 million. The increase in 2008 margins was primarily attributable to higher product prices and the sale of additional product overages and unprocessed transmix by our petroleum products terminal and petroleum products pipeline segments, respectively, during the current period. Product sales and product purchases were lower during the current period due to the assignment of a supply agreement at the end of first quarter 2008.

Operating margin increased $29.3 million primarily due to higher gross margin from product sales as well as higher revenues from each of our business segments and lower expenses, including the favorable settlement of a previously accrued environmental liability.

Depreciation and amortization increased by $1.8 million principally related to expansion capital projects placed into service over the past year.

Affiliate G&A expense increased $0.6 million between periods primarily due to higher personnel, legal and expansion project prospecting costs during 2008, partially offset by lower equity-based incentive compensation expense as a result of a lower value for awards accounted for as liabilities. The 2007 period included a $1.3 million non-cash expense associated with a payment by MGG Midstream Holdings, L.P. (“MGG MH”) to one of our executive officers in connection with MGG MH’s 2007 sale of limited partner interests in Magellan Midstream Holdings, L.P. (“MGG”). MGG MH owns the general partner of MGG, and MGG owns our general partner.

Interest expense, net of interest capitalized and interest income, was $11.4 million for the three months ended June 30, 2008 compared to $13.1 million for the three months ended June 30, 2007. Our average debt outstanding, excluding fair value adjustments for interest rate hedges, increased to $945.1 million during second quarter 2008 from $910.7 million during second quarter 2007 due to borrowings for expansion capital expenditures. However, the weighted-average interest rate on our borrowings, after giving effect to the impact of associated fair value hedges, decreased to 5.4% for the 2008 period from 6.6% for the 2007 period primarily due to the refinancing of our pipeline notes during second quarter 2007 at a lower interest rate and because of lower LIBOR rates on our revolving credit facility during 2008.

Net income was $94.4 million for the three months ended June 30, 2008, representing record quarterly net income, compared to $61.5 million for the three months ended June 30, 2007, an increase of $32.9 million, or 53%; however, earnings per limited partner unit increased only 21%, to $0.80 from $0.66, primarily because $11.9 million of the $12.1 million reduction in an environmental liability accrual, which reduced operating expenses in the current quarter, was allocated to our general partner and therefore had no impact on earnings per limited partner unit.

Six Months Ended June 30, 2007 Compared to Six Months Ended June 30, 2008


	Six Months Ended June 30,						Variance Favorable (Unfavorable)
	2007			2008			$ Change			% Change
Financial Highlights ($ in millions, except operating statistics)

Revenues:
Transportation and terminals revenues:
Petroleum products pipeline system	$	221.7		$	227.5		$	5.8		3
Petroleum products terminals		63.8			69.6			5.8		9
Ammonia pipeline system		9.4			11.4			2.0		21
Intersegment eliminations		(1.7	)		(1.5	)		0.2		12

Total transportation and terminals revenues		293.2			307.0			13.8		5
Product sales		326.6			312.0			(14.6	)	(4	)
Affiliate management fees		0.3			0.4			0.1		33

Total revenues		620.1			619.4			(0.7	)	—
Operating expenses:
Petroleum products pipeline system		85.3			82.2			3.1		4
Petroleum products terminals		27.1			28.2			(1.1	)	(4	)
Ammonia pipeline system		11.5			5.1			6.4		56
Intersegment eliminations		(2.9	)		(2.9	)		—		—

Total operating expenses		121.0			112.6			8.4		7
Product purchases		290.6			252.9			37.7		13
Gain on assignment of supply agreement		—			(26.5	)		26.5		—
Equity earnings		(1.9	)		(1.8	)		(0.1	)	(5	)

Operating margin		210.4			282.2			71.8		34
Depreciation and amortization expense		31.1			34.6			(3.5	)	(11	)
Affiliate G&A expense		35.4			36.2			(0.8	)	(2	)

Operating profit	$	143.9		$	211.4		$	67.5		47


Operating Statistics
Petroleum products pipeline system:
Transportation revenue per barrel shipped	$	1.149		$	1.161
Volume shipped (million barrels)		148.2			146.2
Petroleum products terminals:
Marine terminal average storage utilized (million barrels per month)		21.5			22.8
Inland terminal throughput (million barrels)		57.5			55.4
Ammonia pipeline system:
Volume shipped (thousand tons)		400			447

Transportation and terminals revenues increased by $13.8 million resulting from higher revenues for each of our business segments as shown below:

•

an increase in petroleum products pipeline system revenues of $5.8 million primarily attributable to higher average tariff rates as well as increased fees for leased storage, capacity leases and ethanol blending services. These positive items were partially offset by lower volumes during the six months ended June 30, 2008 as a result of lower gasoline shipments reflecting the impact on demand from higher product prices, partially offset by increased shipments of LPGs due to supply disruptions in the 2007 period;

•

an increase in petroleum products terminals revenues of $5.8 million due to higher revenues at both our marine and inland terminals. Marine revenues increased primarily due to operating results from additional storage tanks at our Galena Park, Texas facility that were placed into service throughout 2007 and 2008, as well as higher excess throughput fees. Inland revenues benefitted from higher additive and ethanol blending fees that offset lower throughput volumes; and

•

an increase in ammonia pipeline system revenues of $2.0 million due to higher average tariffs and additional shipments because of favorable farming conditions.

Operating expenses decreased by $8.4 million as lower expenses at our petroleum products pipeline system and ammonia pipeline system were partially offset by higher costs for our petroleum products terminals as described below:

•

a decrease in petroleum products pipeline system expenses of $3.1 million primarily due to the favorable settlement of a civil penalty related to historical product releases, which resulted in us reducing our liability accrual by $12.1 million during second quarter 2008 (see Environmental below for additional discussion of this settlement), partially offset by less favorable product overages and higher maintenance spending in the current period;

•

an increase in petroleum products terminals expenses of $1.1 million primarily related to higher personnel costs, property taxes and maintenance spending, partially offset by gains recognized from insurance proceeds received in 2008 associated with hurricane damages sustained during 2005 and higher 2007 expenses due to product downgrade charges resulting from the accidental blending of a small amount of product; and

•

a decrease in ammonia pipeline system expenses of $6.4 million primarily due to lower environmental and maintenance costs. The 2007 period was negatively impacted by environmental charges related to a 2004 pipeline release and higher system integrity costs associated with high consequence area testing procedures. These favorable items were partially offset by transition costs in 2008 related to our assumption of operating responsibility for this pipeline during third quarter 2008.

Product sales revenues in the current period primarily resulted from our petroleum products blending operation, terminal product gains and transmix fractionation. Revenues from product sales were $312.0 million for the six months ended June 30, 2008 while product purchases were $252.9 million, resulting in gross margin from these transactions of $59.1 million. The gross margin resulting from product sales and purchases for the 2008 period increased $23.1 million compared to gross margin for the 2007 period of $36.0 million, resulting from product sales for the six months ended June 30, 2007 of $326.6 million and product purchases of $290.6 million. The increase in 2008 margins was primarily attributable to higher product prices and the sale of additional product overages and unprocessed transmix by our petroleum products terminal and petroleum products pipeline segments, respectively, during 2008. Product sales and product purchases were lower during the current period due to the assignment of a supply agreement during first quarter 2008.

The 2008 period benefited from a $26.5 million gain on the assignment of a third-party supply agreement during March 2008.

Operating margin increased $71.8 million primarily due to the gain on assignment of our third-party supply agreement, higher gross margin from product sales, higher revenues from each of our business segments and lower expenses, including the favorable settlement of a previously accrued environmental liability.

Depreciation and amortization increased $3.5 million principally related to expansion capital projects placed into service over the past year.

Affiliate G&A expense increased $0.8 million between periods primarily due to higher personnel, legal and expansion project prospecting costs during 2008, partially offset by lower equity-based incentive compensation expense as a result of a lower value for awards accounted for as liabilities. The 2007 period included a $1.3 million non-cash expense associated with a payment by MGG MH to one of our executive officers in connection with MGG MH’s 2007 sale of limited partner interests in MGG.

Interest expense, net of interest capitalized and interest income, was $22.7 million for the six months ended June 30, 2008 compared to $26.7 million for the six months ended June 30, 2007. Our average debt outstanding, excluding fair value adjustments for interest rate hedges, increased to $951.4 million during the 2008 period from $884.2 million during the 2007 period due to borrowings for expansion capital expenditures. However, the weighted-average interest rate on our borrowings, after giving effect to the impact of associated fair value hedges, decreased to 5.4% in 2008 from 6.8% in 2007 primarily due to the refinancing of our pipeline notes during second quarter 2007 at a lower interest rate and because of lower LIBOR rates on our revolving credit facility during 2008.

We incurred debt refinancing expenses of $3.5 million during second quarter 2007 with no similar expense in the 2008 period. These expenses were associated with the early retirement of our pipeline notes during second quarter 2007. Debt placement fee amortization also decreased during the 2008 period due to the refinanced pipeline notes, which resulted in the related debt placement fees being amortized over a significantly longer period of time.

Net income was $187.7 million for the six months ended June 30, 2008 compared to $111.2 million for the six months ended June 30, 2007, an increase of $76.5 million, or 69%; however, earnings per limited partner unit increased only 40%, to $1.70 from $1.21, primarily because $11.9 million of the $12.1 million reduction in an environmental liability accrual, which reduced operating expenses in the current year, was allocated to our general partner and therefore had no impact on earnings per limited partner unit.

Liquidity and Capital Resources

Cash Flows and Capital Expenditures

Net cash provided by operating activities was $217.7 million and $104.7 million for the six months ended June 30, 2008 and 2007, respectively. The $113.0 million increase from 2007 to 2008 was primarily attributable to:

•

$50.0 million increase in net income, excluding the $26.5 million non-cash gain on assignment of the supply agreement;

•

$22.9 million increase in accrued product purchases in 2008 versus a $34.3 million decrease in accrued product purchases in 2007 due primarily to the timing of invoices received from our vendors and suppliers; and

•

$44.8 million decrease in inventories in 2008 versus a $3.8 million increase in inventories in 2007. The decrease in inventories during 2008 is principally due to the sale of petroleum products inventory we maintained prior to the assignment of our product supply agreement to a third party in March 2008.

These increases were partially offset by:

•

$18.5 million decrease in the supply agreement deposit in 2008 as a result of the assignment of our product supply agreement to a third party in March 2008; and

•

$13.2 million decrease in environmental liabilities in 2008 versus a $3.2 million increase in environmental liabilities in 2007. The decrease in environmental liabilities during 2008 is principally due to the favorable settlement of our petroleum products EPA issue (see Environmental – Petroleum products EPA issue below for more discussion of this issue).

Net cash used by investing activities for the six months ended June 30, 2008 and 2007 was $135.2 million and $98.6 million, respectively. During 2008, we spent $132.0 million for capital expenditures, which included $18.2 million for maintenance capital and $113.8 million for expansion capital. Additionally, we acquired a petroleum products terminal in Bettendorf, Iowa for $12.0 million in first quarter 2008. During 2007, we spent $89.1 million for capital expenditures, which included $16.8 million for maintenance capital and $72.3 million for expansion capital.

Net cash provided (used) by financing activities for the six months ended June 30, 2008 and 2007 was $(82.6) million and $0.8 million, respectively. During 2008, we paid distributions of $129.6 million to our unitholders and general partner, while net borrowings on our revolving credit facility, primarily to finance capital expansion projects and acquisitions, were $36.3 million. Cash distributions paid during the 2007 period were $114.4 million. Net borrowings on our revolving credit facility of $101.5 million and proceeds of $248.9 million from the issuance of notes in 2007 were used primarily to repay the remaining $272.6 million balance on our pipeline notes and for expansion capital expenditures. Capital contributions from our general partner were $2.0 million and $37.3 million during 2008 and 2007, respectively. Capital contributions for 2007 included the final installment payment of $35.0 million from a former affiliate related to an indemnification settlement.

During second quarter 2008, we paid $65.8 million in cash distributions to our unitholders and general partner. Based on the declared quarterly distribution of $0.6875 per unit associated with the second quarter of 2008, we will pay $67.8 million in distributions during third quarter 2008. If we continue to pay cash distributions at this level and the number of outstanding units remains the same, we would pay total cash distributions of $271.2 million on an annual basis. Of this amount, $87.6 million, or 32%, would be paid to our general partner on its approximate 2% ownership interest and incentive distribution rights.

Capital Requirements

Our businesses require continual investment to upgrade or enhance existing operations and to ensure compliance with safety and environmental regulations. Capital spending for our businesses consists primarily of:

•

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

•

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 second quarter 2008, our maintenance capital spending was $10.5 million, including $1.5 million of spending that would have been covered by indemnifications settled in May 2004 and $1.7 million for which we expect reimbursement from third parties. For the six months ended June 30, 2008, we have spent maintenance capital of $18.2 million, including $1.8 million of spending that would have been covered by the May 2004 indemnification settlement and $1.7 million for which we expect reimbursement. We have received the entire $117.5 million under our indemnification settlement agreement. Please see Environmental below for additional description of this agreement.

For 2008, we expect to incur maintenance capital expenditures for our existing businesses of approximately $45.0 million, including $10.0 million of maintenance capital that has already been reimbursed to us through our indemnification settlement or expected to be received from third-party reimbursements.

In addition to maintenance capital expenditures, we also incur expansion capital expenditures at our existing facilities. During second quarter 2008, we spent approximately $66.7 million for organic growth projects. For the six months ended June 30, 2008, we have spent $113.8 million for organic growth projects and $12.0 million to acquire a petroleum products terminal already connected to our petroleum products pipeline system. Based on the progress of expansion projects already underway, we expect to spend approximately $300.0 million of growth capital during 2008, with an additional $170.0 million in 2009 and $80.0 million in 2010 to complete these projects. While the future estimates do not include potential acquisitions, they do include $10.0 million we spent in August 2008 to acquire a petroleum products terminal already connected to our pipeline system in Wrenshall, Minnesota.

Liquidity

As of June 30, 2008, total debt reported on our consolidated balance sheet was $951.9 million. The difference between this amount and the $949.8 million face value of our outstanding debt results from adjustments related to fair value hedges and unamortized discounts on debt issuances.

Revolving credit facility. Our current revolving credit facility has a total borrowing capacity of $550.0 million and a maturity date of September 2012. Borrowings under the facility are unsecured and incur interest at LIBOR plus a spread that ranges from 0.3% to 0.8% based on our credit ratings and on amounts outstanding under the facility. Additionally, a commitment fee is assessed at a rate from 0.05% to 0.125%, depending on our credit rating. As of June 30, 2008, $199.8 million was outstanding under this facility, and $3.3 million of the facility was obligated for letters of credit. The obligations for letters of credit are not reflected as debt on our consolidated balance sheets. As of June 30, 2008, the weighted-average interest rate on borrowings outstanding under this facility was 2.9%. Please see Recent Developments above for discussion of our July 2008 refinancing of outstanding revolving credit borrowings with 10-year notes.

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 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. We used an interest rate swap to effectively convert $100.0 million of these notes to floating-rate debt until May 2008, when we terminated the swap and received a payment of $3.8 million. Including the impact of the amortization of that payment and losses realized on pre-issuance hedges associated with these notes, the effective interest rate on these notes is 5.7%.

6.40% notes due 2037. In April 2007, we sold $250.0 million of 6.40% notes due 2037 in an underwritten public offering at 99.6% of par to refinance outstanding pipeline notes. 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 utilize interest rate derivatives to help us manage interest rate risk. We had no interest rate derivative transactions outstanding as of June 30, 2008. Please see Recent Developments above for discussion of our issuance of public notes, in connection with which we entered into new interest rate derivative agreements.

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. Under our accounting policies, 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.

Indemnification settlement. Prior to May 2004, a former affiliate had agreed to indemnify us against, among other things, certain environmental losses associated with assets contributed to us at the time of our initial public offering or which we subsequently acquired from this former affiliate. In May 2004, our general partner entered into an agreement under which our former affiliate agreed to pay us $117.5 million to release it from these indemnifications. We received the final installment payment associated with this agreement in 2007. At December 31, 2007 and June 30, 2008, known liabilities that would have been covered by this indemnity agreement were $42.9 million and $29.4 million, respectively. Through June 30, 2008, we have spent $50.8 million of the $117.5 million indemnification settlement amount for indemnified matters, including $21.9 million of capital costs. The cash we have received from the indemnity settlement is not reserved and has been used for our various other cash needs, including expansion capital spending.

Petroleum products EPA issue. In July 2001, the Environmental Protection Agency (“EPA”), pursuant to Section 308 of the Clean Water Act (the “Act”), served an information request to a former affiliate with regard to petroleum discharges from its pipeline operations. That inquiry primarily focused on the petroleum products pipeline system that we subsequently acquired. The response to the EPA’s information request was submitted during November 2001. In March 2004, we received an additional information request from the EPA and notice from the U.S. Department of Justice (“DOJ”) that the EPA had requested the DOJ to initiate a lawsuit alleging violations of Section 311(b) of the Act in regards to 32 releases. The DOJ stated that the maximum statutory penalty for the releases was in excess of $22.0 million, which assumed that all releases were violations of the Act and that the EPA would impose the maximum penalty. The EPA further indicated that some of those releases may have also violated the Spill Prevention Control and Countermeasure requirements of Section 311(j) of the Act and that additional penalties could be assessed. The DOJ and EPA added to their original demand a release that occurred in the second quarter of 2005 from our petroleum products pipeline near our Kansas City, Kansas terminal and a release that occurred in the first quarter of 2006 from our petroleum products pipeline near Independence, Kansas.

We reached an agreement with the EPA and DOJ to settle these matters in June 2008. Under the terms of the settlement agreement, we will pay a penalty of $5.3 million and will perform certain operational enhancements, resulting in a reduction of our environmental liability for these matters from $17.4 million to $5.3 million and a reduction to our operating expenses of $12.1 million. Of this reduction, $11.9 million was included as part of the indemnification settlement we reached with a former affiliate (see Indemnification settlement description above).

Ammonia EPA issue. In February 2007, we received notice from the DOJ that the EPA had requested the DOJ to initiate a lawsuit alleging violations of Sections 301 and 311 of the Act with respect to two releases of anhydrous ammonia from the ammonia pipeline owned by us and, at the time of the releases, operated by a third party. 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. We believe that we do not have an obligation to indemnify or defend the third-party operator for the DOJ criminal fine settlement. 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; however, we are unable to determine what our ultimate liability could be for these matters. Adjustments to our recorded liability, which could occur in the near term, could be material to our results of operations and cash flows.

PCB impacts. We have completed our assessment of polychlorinated biphenyls (“PCB”) impacts at two of our petroleum products terminals and have concluded that the costs of any corrective actions associated with PCB contamination will not be material to our results of operations, financial position or cash flows.

Other Items

Pipeline tariff increase. The Federal Energy Regulatory Commission 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. The current approved methodology is the annual change in the producer price index for finished goods (“PPI-FG”) plus 1.3%. Based on an actual change in PPI-FG of approximately 3.9% during 2007, we increased virtually all of our published tariffs by the allowed adjustment of approximately 5.2% effective July 1, 2008. Through June 2008, the change in PPI-FG for 2008 is approximately 7%. If the growth in this index remains at similar levels throughout 2008, we could increase our tariffs during mid-2009 by approximately 8%, which could have a material impact on our results of operations.

Impact of commodity prices. The current high pricing environment for petroleum prices has resulted in reduced volumes of refined petroleum products, such as gasoline and diesel fuel, we transport on our petroleum products pipeline system and distribute through our inland terminals so far in 2008. A prolonged period of high refined product prices could lead to a further reduction in demand and result in lower shipments on our pipeline system and reduced demand for our terminal services. However, our commodity-related activities, such as our petroleum products blending operation, terminal product gains and transmix fractionation, have benefited from the increasing commodity prices as the gross margin we realize from these activities can be substantially higher in periods when refined petroleum prices are increasing. Through the six months ended June 30, 2008, the benefit of high prices to our commodity-related activities has exceeded the unfavorable impact to our transportation and terminals volumes, resulting in a larger portion of our financial results attributable to commodity-related activities, which management expects to continue throughout 2008.

Ammonia operating agreement. Effective July 1, 2008, we resumed operating responsibility for our ammonia pipeline system, which previously had been operated by a third-party pipeline company.

Ammonia contracts. We finalized new five-year transportation agreements with our three ammonia pipeline system customers that extend from July 1, 2008 through June 30, 2013.

Port Arthur, Texas pipeline project. During May 2008, we announced plans to invest $240 million to build energy infrastructure in Texas, providing us with a direct pipeline connection to the refinery hub of Port Arthur. The project primarily includes construction of an 80-mile refined petroleum products pipeline from Port Arthur to our terminal in East Houston, Texas, which we currently expect to be operational by 2011, and construction of 1.4 million barrels of storage primarily at our East Houston terminal, which we currently expect to be operational by 2010. These construction projects are supported by a 15-year agreement with Motiva Enterprises LLC, related to Motiva’s expansion of its refinery in Port Arthur. We believe this agreement will significantly contribute to our results of operations and cash flows once construction is complete and placed into service.

Unrecognized product gains. Our petroleum products terminals operations generate product overages and shortages. 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 $11.4 million as of June 30, 2008. 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. Since December 2005, the general partner of MGG has provided the employees necessary to conduct our business operations and we reimburse it for these costs. In addition, MGG has agreed to reimburse us for G&A expenses, excluding equity-based compensation, in excess of a defined G&A cap. For the three and six months ended June 30, 2008, we were allocated operating expenses from MGG’s general partner of $21.6 million and $42.6 million, respectively, and G&A expenses of $12.2 million and $24.1 million, respectively. For the three months and six months ended June 30, 2007, we were allocated operating expenses from MGG’s general partner of $19.7 million and $38.9 million, respectively, and G&A expenses of $12.0 million and $22.4 million, respectively. MGG reimbursed us G&A costs in excess of the defined G&A cap of $0.4 million and $0.8 million for the three and six months ended June 30, 2008, respectively, and $0.3 million and $0.6 million for the three and six months ended

June 30, 2007, respectively. Our G&A expenses for both 2007 periods included a $1.3 million non-cash expense related to a payment by MGG MH to one of our executive officers in connection with MGG MH’s 2007 sale of limited partner interests in MGG. We do not expect to receive reimbursement for excess G&A expenses beyond 2008.

We own a 50% interest in a crude oil pipeline company. We earn a fee to operate this pipeline which was $0.2 million for both the three months ended June 30, 2008 and 2007 and $0.4 million and $0.3 million for the six months ended June 30, 2008 and 2007, respectively. We report these fees as affiliate management fee revenue on our consolidated statements of income.

Because our distributions have exceeded target levels as specified in our partnership agreement, MGG indirectly receives approximately 50% of any incremental cash distributed per limited partner unit. As of June 30, 2008, certain of the executive officers of our general partner collectively own approximately 5% of MGG MH, which currently owns 14% of MGG, and therefore also indirectly benefit from these distributions. Assuming we have sufficient available cash to continue to pay distributions on our outstanding units for four quarters at our current quarterly distribution level of $0.6875 per unit, MGG would receive annual distributions of approximately $87.6 million on its combined 2% general partner interest and incentive distribution rights.

New Accounting Pronouncements

In June 2008, the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position (“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 nonforfeitable rights to distributions or distribution equivalents, whether paid or unpaid, are participating securities as defined in Statement of Financial Accounting Standard (“SFAS”) No. 128, Earnings Per Share, and are to be included in the computation of earnings per unit pursuant to the two-class method. This FSP is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years with prior period earnings per unit data retrospectively adjusted. Early application of this FSP is not permitted. Adoption of this FSP will 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. This FSP is effective for financial statements issued for fiscal years beginning after December 15, 2008 and interim periods within those fiscal years. Early adoption is prohibited. Adoption of this FSP will not have a material impact on our financial position, results of operations or cash flows.

In March 2008, the FASB ratified 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 and/or excess of earnings over distributions for each period are required to be 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 current accounting practice is to allocate net income to the general partner based on the general partner’s share of total or theoretical distributions, as appropriate, including incentive distribution rights. The effect of adopting this EITF will be: (i) for periods when net income exceeds distributions, our reported earnings per limited partner unit will be higher than under our current accounting practice and (ii) for periods when distributions exceed net income, our reported earnings per limited partner unit will be lower than under our current 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 example, had we applied EITF 07-4 to the 2008 reporting periods, basic and diluted earnings per limited partner unit would have increased from $0.80 to $0.92 and from $1.70 to $2.02 for the three and six months ended June 30, 2008, respectively. This EITF is effective beginning January 1, 2009, including all interim periods after that date. Early application is not permitted. This EITF is required to be applied retrospectively; therefore, we will restate prior period earnings per limited partner unit in all published financial reports after January 1, 2009, as applicable.

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. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. We do not expect that our adoption of this statement will have a material impact on our results of operations, financial position or cash flows.

In February 2008, the FASB issued FSP No. 157-1, Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13. FSP No. 157-1 amends SFAS No. 157, Fair Value Measurements, to exclude SFAS No. 13, Accounting for Leases, and other accounting pronouncements that address fair value measurements for purposes of lease classification or measurement under Statement 13. However, this scope exception does not apply to assets acquired and liabilities assumed in a business combination that are required to be measured at fair value under SFAS No. 141, Business Combinations, or SFAS No. 141 (revised 2007), Business Combinations, regardless of whether those assets and liabilities are related to leases. This FSP is effective with the initial adoption of SFAS No. 157, which we adopted on January 1, 2007. The adoption of this FSP did not have a material effect on our results of operations, financial position 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.

As of June 30, 2008, our variable rate debt consisted of $199.8 million outstanding on our variable-rate revolving credit facility. If LIBOR were to change by 0.125%, our annual interest expense related to our variable-rate revolving credit facility would change by $0.2 million. In July 2008, we issued $250.0 million of 6.40% notes due 2018. We used a portion of the proceeds from this offering to repay the $212.0 million of borrowings outstanding under our revolving credit facility. In connection with this offering, we entered into a total of $100.0 million of interest rate swap agreements to hedge against changes in the fair value of $100.0 million of the notes issued in the offering. These swap agreements effectively change the interest rate on $100.0 million of those notes from 6.40% to a floating rate of six-month LIBOR plus 1.83%. The swap agreements expire on July 15, 2018, the maturity date of the 6.40% notes.

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 June 30, 2008, we had commitments under forward purchase contracts for product purchases that will be accounted for as normal purchases totaling approximately $91.5 million. We had commitments under forward sales contracts for product sales that would have been accounted for as normal sales totaling approximately $183.9 million; however, as of July 31, 2008, we cancelled $171.9 million of these agreements.

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 are subject to numerous assumptions, uncertainties and risks that may cause future results to 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:

•

price fluctuations for natural gas liquids and refined petroleum products;

•

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

•

weather patterns materially different than historical trends;

•

development of alternative energy sources;

•

increased use of biofuels such as ethanol and biodiesel;

•

changes in demand for storage in our petroleum products terminals;

•

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

•

our ability to manage interest rate and commodity price exposures;

•

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

•

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

•

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

•

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

•

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

•

an increase in the competition our operations encounter;

•

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

•

the treatment of us as a corporation for federal 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 general economic conditions in the United States;

•

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;

•

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

•

the condition of the capital markets in the United States;

•

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 pay the amounts owed to us;

•

the ability of SemGroup, L.P., and its subsidiaries, to perform its contractual obligations to us, or our ability to replace such contracts with third parties or otherwise;

•

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

•

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

•

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

In July 2001, the Environmental Protection Agency (“EPA”), pursuant to Section 308 of the Clean Water Act (the “Act”), served an information request to a former affiliate with regard to petroleum discharges from its pipeline operations. That inquiry primarily focused on the petroleum products pipeline system that we subsequently acquired. The response to the EPA’s information request was submitted during November 2001. In March 2004, we received an additional information request from the EPA and notice from the U.S. Department of Justice (“DOJ”) that the EPA had requested the DOJ to initiate a lawsuit alleging violations of Section 311(b) of the Act in regards to 32 releases. The DOJ stated that the maximum statutory penalty for the releases was in excess of $22.0 million, which assumed that all releases were violations of the Act and that the EPA would impose the maximum penalty. The EPA further indicated that some of those releases may have also violated the Spill Prevention Control and Countermeasure requirements of Section 311(j) of the Act and that additional penalties could be assessed. The DOJ and EPA added to their original demand a release that occurred in the second quarter of 2005 from our petroleum products pipeline near our Kansas City, Kansas terminal and a release that occurred in the first quarter of 2006 from our petroleum products pipeline near Independence, Kansas.

We reached an agreement with the EPA and DOJ to settle these matters in June 2008. Under the terms of the settlement agreement, we will pay a penalty of $5.3 million and will perform certain operational enhancements, resulting in a reduction of our environmental liability for these matters from $17.4 million to $5.3 million and a reduction to our operating expenses of $12.1 million. Of this reduction, $11.9 million was included as part of the indemnification settlement we reached with a former affiliate and, accordingly, was allocated to our general partner.

In February 2007, we received notice from the DOJ that the EPA had requested the DOJ to initiate a lawsuit alleging violations of Sections 301 and 311 of the Act with respect to two releases of anhydrous ammonia from the ammonia pipeline owned by us and, at the time of the releases, operated by a third party. 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. We believe that we do not have an obligation to indemnify or defend the third-party operator for the DOJ criminal fine settlement. 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; however, we are unable to determine what our ultimate liability could be for these matters. 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 with a preliminary assessed civil penalty of $784,000 for alleged violations associated with a May 23, 2005 pipeline release that occurred in the Fairfax Industrial District of Kansas City, Kansas. The alleged violations principally involve allegations of failing to follow our System Integrity Plan. We plan to submit a written response within 30 days of receipt of the NOPV formally requesting a hearing.

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 has preliminarily assessed a civil penalty of $183,500. We have submitted a response to the NOPV, participated in a hearing at our request with the OPS and submitted a post-hearing brief.

In March 2004, we received a Corrective Action Order from the OPS as a result of the OPS’ May 2003 inspection of a former affiliates’ Integrity Management Program applicable to our assets. The Corrective Action Order focused on timing of repairs and temporary pressure reductions upon discovery of anomalies. The OPS preliminarily assessed us with a civil penalty of $105,000. Supplemental information was presented to the OPS in September 2004. We are awaiting the OPS’ formal response on this matter.

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

ITEM 1A.

RISK FACTORS

In addition to the 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, 2007, which could materially affect our business, financial condition or future results. The risks described below and 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 or operating results.

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

Risks Related to Our Business

We hedge receipt or delivery of refined products by utilizing physical purchase and sale agreements, futures contracts traded on the New York Mercantile Exchange (“NYMEX”) or Intercontinental Exchange (“ICE”), options contracts or over-the-counter transactions. These hedging arrangements may not eliminate all price risks, could result in fluctuations in quarterly or annual profits and could result in material cash obligations.

We hedge our exposure to price fluctuations with respect to refined products generated from or used in our operations by utilizing physical purchase and sale agreements, futures contracts traded on the NYMEX or ICE, options contracts or over-the-counter transactions. To the extent these hedges do not qualify for hedge accounting treatment under Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (as amended) or they result in material amounts of ineffectiveness, we could experience material fluctuations in our quarterly or annual results of operations. In addition, to the extent these hedges are entered into on a public exchange, we may be required to post margin which could result in material cash obligations. Finally, 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 a hedge that does not eliminate all price risks.

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

The annual meeting of our limited partners was held on April 23, 2008. At this meeting, two individuals were elected as Class III directors of our general partner’s board of directors. A tabulation of the voting on this issue follows:


Name	For	Withheld	Abstain	Broker Non-Votes
James R. Montague	60,783,447	467,393	—	—
Don R. Wellendorf	59,310,153	1,940,687	—	—

ITEM 5.

OTHER INFORMATION

None.

ITEM 6.

EXHIBITS


EXHIBIT NUMBER		DESCRIPTION
3.1*		Amendment No. 4 adopted April 15, 2008 to be effective as of January 1, 2007 to the Fourth Amended and Restated Agreement of Limited Partnership of Magellan Midstream Partners, L.P. (filed as Exhibit 3.1 to Form 8-K filed April 21, 2008).

4.1*		Amendment No. 4 adopted April 15, 2008 to be effective as of January 1, 2007 to the Fourth Amended and Restated Agreement of Limited Partnership of Magellan Midstream Partners, L.P. (filed as Exhibit 3.1 to Form 8-K filed April 21, 2008).

10.1*		Texas Pipeline Project Throughput and Deficiency Agreement dated as of May 9, 2008 among Motiva Enterprises LLC and Magellan Pipeline Company, L.P., Magellan Terminals Holdings, L.P. and Magellan Pipelines Holdings, L.P. (filed as Exhibit 10.1 to Form 8-K filed May 15, 2008).

12.1		Ratio of earnings to fixed charges.

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

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

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

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

99.1		Magellan GP, LLC balance sheets as of December 31, 2007 and June 30, 2008 and notes thereto.

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

SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized in Tulsa, Oklahoma on August 5, 2008.


MAGELLAN MIDSTREAM PARTNERS, L.P.

By:		/s/ Magellan GP, LLC
		its General Partner

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

INDEX TO EXHIBITS


EXHIBIT NUMBER		DESCRIPTION
3.1*		Amendment No. 4 adopted April 15, 2008 to be effective as of January 1, 2007 to the Fourth Amended and Restated Agreement of Limited Partnership of Magellan Midstream Partners, L.P. (filed as Exhibit 3.1 to Form 8-K filed April 21, 2008).

4.1*		Amendment No. 4 adopted April 15, 2008 to be effective as of January 1, 2007 to the Fourth Amended and Restated Agreement of Limited Partnership of Magellan Midstream Partners, L.P. (filed as Exhibit 3.1 to Form 8-K filed April 21, 2008).

10.1*		Texas Pipeline Project Throughput and Deficiency Agreement dated as of May 9, 2008 among Motiva Enterprises LLC and Magellan Pipeline Company, L.P., Magellan Terminals Holdings, L.P. and Magellan Pipelines Holdings, L.P. (filed as Exhibit 10.1 to Form 8-K filed May 15, 2008).

12.1		Ratio of earnings to fixed charges.

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

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

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

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

99.1		Magellan GP, LLC balance sheets as of December 31, 2007 and June 30, 2008 and notes thereto.

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