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 September 30, 2010

OR

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

For the transition period from              to             

Commission File No.: 1-16335

Magellan Midstream Partners, L.P.

(Exact name of registrant as specified in its charter)

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

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

(Address of principal executive offices and zip code)

(918) 574-7000

(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  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 November 1, 2010, there were 112,481,349 outstanding limited partner units of Magellan Midstream Partners, L.P. that trade on the New York Stock Exchange under the ticker symbol “MMP.”

TABLE OF CONTENTS

PART I

FINANCIAL INFORMATION

ITEM 1.		CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED STATEMENTS OF INCOME			2
CONSOLIDATED BALANCE SHEETS			3
CONSOLIDATED STATEMENTS OF CASH FLOWS			4
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME			5
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS:
	1.	Organization and Basis of Presentation	6
	2.	Owners’ Equity	7
	3.	Acquisitions	7
	4.	Product Sales Revenues	9
	5.	Segment Disclosures	9
	6.	Inventory	12
	7.	Employee Benefit Plans	12
	8.	Debt	13
	9.	Derivative Financial Instruments	14
	10.	Commitments and Contingencies	18
	11.	Long Term Incentive Plan	18
	12.	Distributions	19
	13.	Fair Value	20
	14.	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			23
Liquidity and Capital Resources			28
Off-Balance Sheet Arrangements			30
Environmental			30
Other Items			30
New Accounting Pronouncements			32
ITEM 3.		QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	33
ITEM 4.		CONTROLS AND PROCEDURES	34
Forward-Looking Statements			35
PART II
OTHER INFORMATION
ITEM 1.		LEGAL PROCEEDINGS	37
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.		RESERVED	37
ITEM 5.		OTHER INFORMATION	38
ITEM 6.		EXHIBITS	38

1

PART I

FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except per unit amounts)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2010			2009			2010
Transportation and terminals revenues	$	173,504		$	206,727		$	495,227		$	573,069
Product sales revenues		66,076			199,284			165,119			585,318
Affiliate management fee revenue		190			190			570			569
Total revenues		239,770			406,201			660,916			1,158,956
Costs and expenses:
Operating		73,863			87,584			195,178			219,980
Product purchases		47,902			186,993			141,522			503,516
Depreciation and amortization		24,613			27,403			70,928			79,460
General and administrative		20,002			23,624			61,386			67,044
Total costs and expenses		166,380			325,604			469,014			870,000
Equity earnings		1,368			1,654			2,826			4,323
Operating profit		74,758			82,251			194,728			293,279
Interest expense		20,837			25,316			52,198			69,611
Interest income		(225	)		(74	)		(652	)		(85	)
Interest capitalized		(874	)		(884	)		(2,752	)		(2,535	)
Debt placement fee amortization expense		331			358			775			1,015
Other (income) expense		11			750			(636	)		750
Income before provision for income taxes		54,678			56,785			145,795			224,523
Provision for income taxes		463			148			1,272			900
Net income	$	54,215		$	56,637		$	144,523		$	223,623
Allocation of net income (loss):
Non-controlling owners’ interest	$	36,054		$	(154	)	$	99,729		$	(222	)
Limited partners’ interest		18,161			56,791			44,794			223,845
Net income	$	54,215		$	56,637		$	144,523		$	223,623
Basic and diluted net income per limited partner unit	$	0.43		$	0.51		$	1.11		$	2.06
Weighted average number of limited partner units outstanding used for basic and diluted net income per unit calculation		41,831			111,522			40,377			108,437

See notes to consolidated financial statements.

2

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(In thousands)

	December 31, 2009			September 30, 2010
				(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	4,168		$	77,017
Trade accounts receivable (less allowance for doubtful accounts of $139 and $106 at December 31, 2009 and September 30, 2010, respectively)		72,978			87,828
Other accounts receivable		8,216			3,919
Inventory		193,001			203,275
Energy commodity derivatives contracts		—			21
Energy commodity derivatives deposits		17,943			7,499
Reimbursable costs		13,280			11,472
Other current assets		14,382			9,986
Total current assets		323,968			401,017
Property, plant and equipment		3,398,606			3,868,484
Less: accumulated depreciation		617,989			690,083
Net property, plant and equipment		2,780,617			3,178,401
Equity investments		22,054			23,921
Long-term receivables		618			1,300
Goodwill		14,766			14,766
Other intangibles (less accumulated amortization of $9,974 and $11,506 at December 31, 2009 and September 30, 2010, respectively)		5,896			13,483
Debt placement costs (less accumulated amortization of $4,038 and $5,053 at December 31, 2009 and September 30, 2010, respectively)		10,894			12,251
Other noncurrent assets		4,335			5,786
Total assets	$	3,163,148		$	3,650,925
LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable	$	37,063		$	56,184
Accrued payroll and benefits		30,300			28,314
Accrued interest payable		32,877			31,160
Accrued taxes other than income		21,261			25,887
Environmental liabilities		11,943			12,438
Deferred revenue		27,776			31,959
Accrued product purchases		36,797			29,052
Energy commodity derivatives contracts		9,257			—
Other current liabilities		22,123			21,974
Total current liabilities		229,397			236,968
Long-term debt		1,680,004			1,892,349
Long-term pension and benefits		22,582			27,453
Other noncurrent liabilities		12,317			12,263
Environmental liabilities		22,494			20,698
Commitments and contingencies
Owners’ equity:
Partners’ capital:
Limited partner unitholders (106,588 units and 112,481 units outstanding at December 31, 2009 and September 30, 2010, respectively)		1,204,355			1,457,747
Accumulated other comprehensive loss		(8,001	)		(9,712	)
Total partners’ capital		1,196,354			1,448,035
Non-controlling owners’ interest in consolidated subsidiaries		—			13,159
Total owners’ equity		1,196,354			1,461,194
Total liabilities and owners’ equity	$	3,163,148		$	3,650,925

See notes to consolidated financial statements.

3

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, in thousands)

	Nine Months Ended September 30,
	2009			2010
Operating Activities:
Net income	$	144,523		$	223,623
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense		70,928			79,460
Debt placement fee amortization expense		775			1,015
Loss on sale and retirement of assets		3,981			106
Equity earnings		(2,826	)		(4,323	)
Distributions from equity investment		2,826			3,240
Equity-based incentive compensation expense		7,361			11,482
Amortization of prior service cost and net actuarial loss		942			80
Changes in operating assets and liabilities:
Trade accounts receivable and other accounts receivable		(17,234	)		(10,553	)
Inventory		(56,336	)		(10,274	)
Energy commodity derivatives contracts, net of derivatives deposits		589			2,633
Reimbursable costs		(6,641	)		1,808
Accounts payable		4,343			15,233
Accrued payroll and benefits		1,136			(1,986	)
Accrued interest payable		16,334			(1,717	)
Accrued taxes other than income		3,409			4,312
Accrued product purchases		(2,813	)		(7,745	)
Current and noncurrent environmental liabilities		(868	)		(1,676	)
Other current and noncurrent assets and liabilities		8,717			11,171
Net cash provided by operating activities		179,146			315,889
Investing Activities:
Property, plant and equipment:
Additions to property, plant and equipment		(157,321	)		(160,691	)
Proceeds from sale and disposition of assets		333			5,297
Changes in accounts payable related to capital expenditures		(651	)		3,888
Acquisition of businesses		(358,442	)		(290,991	)
Other acquisition		—			(29,300	)
Distributions in excess of equity investment earnings		342			—
Net cash used by investing activities		(515,739	)		(471,797	)
Financing Activities:
Distributions paid		(210,081	)		(235,019	)
Repayments under revolver, net		(37,000	)		(101,600	)
Borrowings under long-term notes, net		568,699			298,899
Debt placement costs		(4,411	)		(2,372	)
Net receipt from financial derivatives		—			16,238
Increase (decrease) in outstanding checks		2,151			(5,116	)
Settlement of tax withholdings on long-term incentive compensation		(3,450	)		(3,371	)
Issuance of common units, net		—			258,400
Capital contributed by non-controlling owners		—			3,082
Costs associated with the simplification of capital structure		(13,553	)		—
Other		—			(384	)
Net cash provided by financing activities		302,355			228,757
Change in cash and cash equivalents		(34,238	)		72,849
Cash and cash equivalents at beginning of period		37,912			4,168
Cash and cash equivalents at end of period	$	3,674		$	77,017
Supplemental non-cash financing activity:
Issuance of limited partner units in settlement of long-term incentive plan awards	$	1,943		$	2,034
Non-cash capital contributed by non-controlling owners	$	—		$	10,299

See notes to consolidated financial statements.

4

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited, in thousands)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2010			2009			2010
Net income	$	54,215		$	56,637		$	144,523		$	223,623
Other comprehensive income:
Net gain (loss) on commodity hedges		639			(179	)		639			(468	)
Reclassification of net gain on interest rate cash flow hedges to interest expense		(41	)		(41	)		(123	)		(123	)
Reclassification of net loss (gain) on commodity hedges to product sales revenues		(255	)		(1,068	)		(255	)		967
Amortization of prior service cost and actuarial loss		270			101			942			80
Adjustment to recognize the funded status of postretirement plans		522			(2,167	)		522			(2,167	)
Total other comprehensive income (loss)		1,135			(3,354	)		1,725			(1,711	)
Comprehensive income		55,350			53,283			146,248			221,912
Comprehensive income (loss) attributable to non-controlling owners’ interest in consolidated subsidiaries		37,167			(154	)		101,420			(222	)
Comprehensive income attributable to partners’ capital	$	18,183		$	53,437		$	44,828		$	222,134

See notes to consolidated financial statements.

5

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 its subsidiaries. We are a Delaware limited partnership and our limited partner units are traded on the New York Stock Exchange under the ticker symbol “MMP.” Magellan GP, LLC (“MMP GP”), a wholly-owned Delaware limited liability company, serves as our general partner.

We operate and report in three business segments: the petroleum pipeline system, the petroleum 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.

Basis of Presentation

On September 28, 2009, pursuant to a Simplification Agreement (the “Simplification Agreement”), approximately 39.6 million of our limited partner units were issued to unitholders of Magellan Midstream Holdings, L.P. (“Holdings”), Magellan Midstream Holdings GP, LLC (Holdings’ general partner) and MMP GP were contributed to us by Holdings and Holdings was dissolved (collectively, the “simplification”). A full description of the Simplification Agreement was provided in our Annual Report on Form 10-K for the year ended December 31, 2009. As a result of the simplification, both Holdings’ general partner and MMP GP became our wholly-owned subsidiaries. Therefore, we no longer pay incentive distribution rights and we acquired all of the non-controlling owners’ interests that existed at the time of the simplification.

In May 2010, Magellan Crude Oil, LLC (“MCO”), a Delaware limited liability company, was formed for the purpose of constructing and operating crude oil storage in the Cushing, Oklahoma crude oil hub for lease to third parties. MCO has executed long-term agreements to lease 4.25 million barrels of crude oil storage to third parties and is in the process of constructing the crude oil storage tanks necessary to service these agreements. We will invest up to $70.0 million in MCO. Approximately 35% of the common equity of MCO is owned by a private investment group and approximately 65% is owned by us. In addition, we own all of MCO’s 8.5% cumulative preferred equity. At the time of MCO’s formation, we determined that it was not a variable interest entity and subsequently we concluded that it should be consolidated into our results based on our voting and operational control of that entity. Since we consolidate MCO, non-controlling owners’ interest in consolidated subsidiaries on our consolidated balance sheet reflects the contributions to MCO by the private investment group less its allocated share of MCO’s net losses for the year. MCO’s cash on hand at September 30, 2010 was $15.8 million, which will be used for tank construction and is unavailable to us for our partnership matters. The results of MCO have been included in our petroleum terminals segment from the date of its formation. Through September 30, 2010, we have contributed cash of $25.7 million to MCO, of which $6.8 million was recorded as cumulative preferred equity and $18.9 million as common equity. The private investment group’s investment in MCO through September 30, 2010 was $13.4 million, which included cash contributions of $3.1 million and $10.3 million of non-cash contributions, which consisted of $9.1 million of terminalling agreements and $1.2 million of property, plant and equipment.

In July 2010, Texas Frontera, LLC, a Delaware limited liability company, was formed for the purpose of constructing and leasing petroleum products storage tanks at Galena Park, Texas. This company is owned 50% by a third-party and 50% by us. We use the equity method of accounting for this investment and have contributed cash of $0.8 million as of September 30, 2010. We expect to make a total investment of approximately $15.0 million in Texas Frontera, LLC over the next twelve months.

In the opinion of management, our accompanying consolidated financial statements, which are unaudited except for the consolidated balance sheet as of December 31, 2009, which is derived from audited financial statements, include all normal and recurring adjustments necessary to present fairly our financial position as of September 30, 2010, and the results of operations for the three and nine months ended September 30, 2009 and 2010 and cash flows for the nine months ended September 30, 2009 and 2010. The results of operations for the three and nine months ended September 30, 2010 are not necessarily indicative of the results to be expected for the full year ending December 31, 2010.

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, 2009.

6

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. Owners’ Equity

Equity Offering

In July 2010, we completed a public offering of 5,750,000 of our common units at $46.65 per unit and received net proceeds of approximately $258.4 million after underwriting discounts of $9.5 million and offering expenses of $0.3 million. We used the combined net proceeds from this offering and our debt offering in August 2010 (see Note 8 – Debt) to pay the $291.0 million purchase price for the business we acquired from BP Pipelines (North America), Inc. (“BP”) plus approximately $56 million for associated crude oil working inventories that we acquired in October 2010 and to repay the outstanding balance of our revolving credit facility, which at that time was $175.5 million. The remaining amount of the net proceeds from these offerings was used for general partnership purposes.

Owners’ Equity

The changes in owners’ equity for the nine months ended September 30, 2010 are provided in the table below (in thousands):

	Limited Partners’ Capital			Limited Partners’ Accumulated Other Comprehensive Loss			Non-controlling Owners’  Interest			Total  Owners’ Equity
Balance, January 1, 2010	$	1,204,355		$	(8,001	)	$	—		$	1,196,354
Comprehensive income:
Net income (loss)		223,845			—			(222	)		223,623
Net loss on commodity hedges		—			(468	)		—			(468	)
Reclassification of net gain on interest rate cash flow hedges to interest expense		—			(123	)		—			(123	)
Reclassification of net gain on commodity hedges to product sales revenues		—			967			—			967
Amortization of prior service cost and net actuarial loss		—			80			—			80
Adjustment to recognize the funded status of postretirement plans		—			(2,167	)		—			(2,167	)
Total comprehensive income (loss)		223,845			(1,711	)		(222	)		221,912
Distributions		(235,019	)		—			—			(235,019	)
Issuance of 5,750 common units		258,400			—			—			258,400
Equity method portion of equity-based incentive compensation expense		7,887			—			—			7,887
Issuance of 143 common units in settlement of long-term incentive plan awards		2,034			—			—			2,034
Settlement of tax withholdings on long-term incentive compensation		(3,371	)		—			—			(3,371	)
Capital contributed by non-controlling owners		—			—			13,381			13,381
Other		(384	)		—			—			(384	)
Balance, September 30, 2010	$	1,457,747		$	(9,712	)	$	13,159		$	1,461,194

3. Acquisitions

Acquisition of Assets

In April 2010, we acquired various petroleum products storage tanks already connected to our petroleum pipeline system at Des Moines, Iowa, El Dorado, Kansas and Glenpool and Tulsa, Oklahoma for $29.3 million. These purchases were accounted for as the acquisition of assets. The operating results of these assets have been included in our petroleum pipeline system segment from the acquisition date.

Acquisition of Business

On September 1, 2010, using proceeds from a combination of debt and equity offerings, we acquired an aggregate of 7.8 million barrels of crude oil storage and more than 100 miles of active petroleum pipelines in the Houston, Texas area from BP for $291.0 million.

7

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Also, related to this transaction, during October 2010, we acquired certain crude oil working inventory at a fair value of approximately $56 million. These assets will improve our connectivity with existing markets as well as expand our crude oil logistics infrastructure. A majority of the crude oil storage included in this acquisition will be leased to BP for an intermediate period.

The acquisition from BP was accounted for as a business combination under the acquisition method of accounting in accordance with Accounting Standards Codification (“ASC”) 805, Business Combinations. The assets acquired and liabilities assumed were recorded at their estimated fair values as of the acquisition date. The purchase price and initial assessment of the fair value of the assets acquired (liabilities assumed) were as follows (in thousands):

Purchase price	$	290,991
Fair value of assets acquired (liabilities assumed):
Property, plant and equipment	$	290,628	*
Other current assets		2,877	*
Environmental liabilities assumed		(375	)*
Other current liabilities assumed		(2,139	)*
Total	$	290,991	*
*These values (and estimated goodwill, if any) will be adjusted upon completion of the appraisal process.

Revenues and net operating income from the acquisition from BP included in our operating results were as follows (in thousands):

	Three and Nine Months Ended September 30, 2010
	Petroleum Pipeline  System Segment		Petroleum Terminals Segment		Total
Revenues	$	3,779	$	1,669	$	5,448
Net operating income	$	4,679	$	1,258	$	5,937

Acquisition-related expenses of $0.2 million were included with our general and administrative (“G&A”) costs through September 30, 2010.

Pro Forma Information

The following summarized pro forma consolidated income statement information assumes that the acquisition from BP discussed above occurred as of January 1, 2009. These pro forma results are for comparative purposes only and may not be indicative of the results that would have occurred had this acquisition been completed on January 1, 2009 or the results that will be attained in the future. The amounts presented below are in thousands:

	Three Months Ended September 30, 2009						Nine Months Ended September 30, 2009
	As Reported		Pro Forma Adjustments		Pro Forma		As Reported		Pro Forma Adjustments		Pro Forma
Revenues	$	239,770	$	12,944	$	252,714	$	660,916	$	37,676	$	698,592
Net income	$	54,215	$	2,131	$	56,346	$	144,523	$	10,620	$	155,143
	Three Months Ended September 30, 2010						Nine Months Ended September 30, 2010
	As Reported		Pro Forma Adjustments		Pro Forma		As Reported		Pro Forma Adjustments		Pro Forma
Revenues	$	406,201	$	9,027	$	415,228	$	1,158,956	$	36,483	$	1,195,439
Net income	$	56,637	$	3,418	$	60,055	$	223,623	$	12,764	$	236,387

The pro forma adjustments include historical results of the acquired assets and our calculation of G&A, depreciation expense and interest expense on borrowings necessary to complete the acquisition.

8

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. Product Sales Revenues

The amounts reported as product sales revenues on our consolidated statements of income include revenues from the physical sale of petroleum products and from mark-to-market adjustments from New York Mercantile Exchange (“NYMEX”) contracts. We use NYMEX contracts as economic hedges against changes in the price of petroleum products we expect to sell from our business activities where we acquire or produce petroleum products. Some of the NYMEX contracts we have entered into have qualified for hedge accounting treatment under ASC 815-30, Derivatives and Hedging, while others have not. As a result, the amounts reported as product sales revenues can include amounts from the following:

• The physical sale of petroleum products;

• Mark-to-market adjustments of NYMEX contracts that did not qualify for hedge accounting;

• The effective portion of the gains or losses of NYMEX contracts that matured during the period, which were accounted for as hedges; and

• Any ineffective portion of NYMEX contracts accounted for as hedges.

For the three and nine months ended September 30, 2009 and 2010, product sales revenues included the following (in thousands):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2009		2010			2009			2010
Physical sale of petroleum products	$	60,211	$	206,682		$	182,650		$	577,919
NYMEX contract adjustments:
Change in value of NYMEX contracts that did not qualify for hedge accounting treatment associated with our petroleum products blending and fractionation activities		2,803		(4,347	)		(20,593	)		3,566
The effective portion of gains (losses) of matured NYMEX contracts that qualified for hedge accounting treatment associated with our petroleum products blending and fractionation activities		255		1,068			255			(967	)
Change in value of NYMEX contracts that did not qualify for hedge accounting treatment associated with the Houston-to-El Paso pipeline section linefill and working inventory		2,807		(4,924	)		2,807			3,995
Change in value of NYMEX contracts that did not qualify for hedge accounting treatment associated with our crude oil activities		—		805			—			805
Total NYMEX contract adjustments		5,865		(7,398	)		(17,531	)		7,399
Total product sales revenues	$	66,076	$	199,284		$	165,119		$	585,318

5. 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.

Management believes that investors benefit from having access to the same financial measures that they use. Operating margin, which is presented in the following tables, is an important measure used by management to evaluate the economic performance of our core operations. Operating margin is not a generally accepted accounting principles (“GAAP”) measure but the components of operating margin are computed by using amounts that are determined in accordance with GAAP. A reconciliation of operating margin to operating profit, which is its nearest comparable GAAP financial measure, is included in the tables. Operating profit includes expense items, such as depreciation and amortization expense and G&A costs, that management does not consider when evaluating the core profitability of our operations.

9

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Beginning in 2010, our East Houston, Texas terminal was transferred from our petroleum terminals segment to our petroleum pipeline system segment. The East Houston terminal is an origin for our pipeline system and has been increasingly utilized as a pipeline terminal. For instance, we are currently building a connection between the East Houston terminal and our Houston-to-El Paso pipeline section to serve as an origin for that pipeline. Further, we have constructed a pipeline connection from our East Houston terminal to a third-party pipeline near Houston to allow us to transport petroleum products from the Port Arthur, Texas refinery region into our pipeline markets. We are commercially managing the East Houston terminal in coordination with our pipeline to provide efficient marketing to our customers. Since the beginning of 2010, this facility has been realigned under petroleum pipeline management and its operating results have been reported both internally and externally as part of that segment. The historical financial results for our segments have been adjusted to conform to the current period’s presentation. The historical adjustments to revenues and expenses were not material and consolidated operating profit did not change as a result of this reclassification. The net book value of the asset transferred was approximately $79.0 million.

	Three Months Ended September 30, 2009
	(in thousands)
	Petroleum Pipeline System			Petroleum Terminals		Ammonia Pipeline System			Intersegment Eliminations			Total
Transportation and terminals revenues	$	128,979		$	41,008	$	4,017		$	(500	)	$	173,504
Product sales revenues		62,447			3,629		—			—			66,076
Affiliate management fee revenue		190			—		—			—			190
Total revenues		191,616			44,637		4,017			(500	)		239,770
Operating expenses		51,084			16,324		7,392			(937	)		73,863
Product purchases		47,050			1,349		—			(497	)		47,902
Equity earnings		(1,368	)		—		—			—			(1,368	)
Operating margin (loss)		94,850			26,964		(3,375	)		934			119,373
Depreciation and amortization expense		15,667			7,678		334			934			24,613
G&A expenses		14,441			4,998		563			—			20,002
Operating profit (loss)	$	64,742		$	14,288	$	(4,272	)	$	—		$	74,758

	Three Months Ended September 30, 2010
	(in thousands)
	Petroleum Pipeline System			Petroleum Terminals		Ammonia Pipeline System			Intersegment Eliminations			Total
Transportation and terminals revenues	$	156,652		$	49,905	$	671		$	(501	)	$	206,727
Product sales revenues		195,177			4,233		—			(126	)		199,284
Affiliate management fee revenue		190			—		—			—			190
Total revenues		352,019			54,138		671			(627	)		406,201
Operating expenses		56,941			23,044		8,242			(643	)		87,584
Product purchases		186,023			1,597		—			(627	)		186,993
Equity earnings		(1,654	)		—		—			—			(1,654	)
Operating margin (loss)		110,709			29,497		(7,571	)		643			133,278
Depreciation and amortization expense		17,840			8,562		358			643			27,403
G&A expenses		16,965			6,033		626			—			23,624
Operating profit (loss)	$	75,904		$	14,902	$	(8,555	)	$	—		$	82,251

10

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	Nine Months Ended September 30, 2009
	(in thousands)
	Petroleum Pipeline System			Petroleum Terminals		Ammonia Pipeline System			Intersegment Eliminations			Total
Transportation and terminals revenues	$	365,886		$	118,382	$	12,494		$	(1,535	)	$	495,227
Product sales revenues		154,571			10,548		—			—			165,119
Affiliate management fee revenue		570			—		—			—			570
Total revenues		521,027			128,930		12,494			(1,535	)		660,916
Operating expenses		137,641			46,685		13,732			(2,880	)		195,178
Product purchases		138,552			4,455		—			(1,485	)		141,522
Equity earnings		(2,826	)		—		—			—			(2,826	)
Operating margin (loss)		247,660			77,790		(1,238	)		2,830			327,042
Depreciation and amortization expense		45,004			21,987		1,107			2,830			70,928
G&A expenses		44,232			15,392		1,762			—			61,386
Operating profit (loss)	$	158,424		$	40,411	$	(4,107	)	$	—		$	194,728
	Nine Months Ended September 30, 2010
	(in thousands)
	Petroleum Pipeline System			Petroleum Terminals		Ammonia Pipeline System			Intersegment Eliminations			Total
Transportation and terminals revenues	$	421,028		$	144,010	$	9,547		$	(1,516	)	$	573,069
Product sales revenues		570,366			15,106		—			(154	)		585,318
Affiliate management fee revenue		569			—		—			—			569
Total revenues		991,963			159,116		9,547			(1,670	)		1,158,956
Operating expenses		149,211			57,679		15,458			(2,368	)		219,980
Product purchases		499,066			6,120		—			(1,670	)		503,516
Equity earnings		(4,323	)		—		—			—			(4,323	)
Operating margin (loss)		348,009			95,317		(5,911	)		2,368			439,783
Depreciation and amortization expense		51,200			24,809		1,083			2,368			79,460
G&A expenses		48,307			16,911		1,826			—			67,044
Operating profit (loss)	$	248,502		$	53,597	$	(8,820	)	$	—		$	293,279
Segment assets	$	2,544,579		$	1,006,491	$	43,962		$	—		$	3,595,032
Corporate assets													55,893
Total assets												$	3,650,925

The increase in segment assets from previously reported periods resulted primarily from the acquisitions described in Note 3—Acquisitions.

11

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. Inventory

Inventory at December 31, 2009 and September 30, 2010 was as follows (in thousands):

	December 31, 2009		September 30, 2010
Refined petroleum products	$	152,776	$	102,269
Natural gas liquids		17,263		61,314
Transmix		17,230		33,417
Additives and other		5,732		6,275
Total inventory	$	193,001	$	203,275

The decrease in refined petroleum products from December 31, 2009 to September 30, 2010 was primarily attributable to the sale of a portion of the linefill associated with our Houston-to-El Paso pipeline section and product sales related to our petroleum pipeline operations. The increase in natural gas liquids was due to the purchase of butane during second and third quarter 2010 in anticipation of the petroleum products blending season, which begins each September.

7. Employee Benefit Plans

We sponsor two union pension plans for certain employees and a pension plan primarily for salaried employees, a postretirement benefit plan for selected employees and a defined contribution plan. The following tables present our consolidated net periodic benefit costs related to these plans during the three and nine months ended September 30, 2009 and 2010 (in thousands):

	Three Months  Ended September 30, 2009						Nine Months  Ended September 30, 2009
	Pension Benefits			Other  Post- Retirement Benefits			Pension Benefits			Other  Post- Retirement Benefits
Components of Net Periodic Benefit Costs:
Service cost	$	1,646		$	73		$	4,937		$	305
Interest cost		802			118			2,407			675
Expected return on plan assets		(680	)		—			(2,042	)		—
Amortization of prior service cost (credit)		76			(213	)		230			(638	)
Amortization of actuarial loss (gain)		408			(1	)		1,223			127
Net periodic benefit cost (credit)	$	2,252		$	(23	)	$	6,755		$	469
	Three Months  Ended September 30, 2010						Nine Months  Ended September 30, 2010
	Pension Benefits			Other  Post- Retirement Benefits			Pension Benefits			Other  Post- Retirement Benefits
Components of Net Periodic Benefit Costs:
Service cost	$	1,687		$	63		$	5,040		$	239
Interest cost		840			338			2,506			744
Expected return on plan assets		(890	)		—			(2,664	)		—
Amortization of prior service cost (credit)		76			(213	)		230			(638	)
Amortization of actuarial loss		138			100			388			100
Net periodic benefit cost	$	1,851		$	288		$	5,500		$	445

Contributions estimated to be paid into the plans in 2010 are $5.7 million and $0.6 million for the pension and other postretirement benefit plans, respectively.

12

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. Debt

Consolidated debt at December 31, 2009 and September 30, 2010 was as follows (in thousands):

	December 31, 2009		September 30, 2010		Weighted-Average Interest Rate  at September 30, 2010 (1)
Revolving credit facility	$	101,600	$	—		—
6.45% Notes due 2014		249,732		249,772		6.3%
5.65% Notes due 2016		252,897		252,574		5.7%
6.40% Notes due 2018		260,340		259,428		5.9%
6.55% Notes due 2019		566,500		582,719		5.2%
4.25% Notes due 2021		—		298,911		4.3%
6.40% Notes due 2037		248,935		248,945		6.3%
Total debt	$	1,680,004	$	1,892,349

(1) Weighted-average interest rate includes the impact of interest rate swaps and the amortization/accretion of discounts and premiums and gains and losses realized on various cash flow and fair value hedges (see Note 9—Derivative Financial Instruments for detailed information regarding the reclassification of the gains or losses from these hedges as adjustments to interest expense).

Note discounts and premiums are being amortized or accreted to the applicable notes over the respective lives of the associated notes.

Current Period Debt Offering

In August 2010, we issued $300.0 million of 4.25% notes due 2021 in an underwritten public offering. The notes were issued for the discounted price of 99.6%, or $298.9 million. Net proceeds from this offering, after underwriting discounts of $2.0 million and offering costs of $0.4 million, were $296.5 million. The combined proceeds from this debt offering and our equity offering in July 2010 (see Note 2—Owners’ Equity) were used to pay for our acquisition of petroleum storage and pipeline assets from BP (see Note 3 – Acquisitions) and to repay the outstanding balance of the revolving credit facility at that time. The remaining amount of the net proceeds was used for general partnership purposes.

Other Debt

Revolving Credit Facility. The total borrowing capacity under the revolving credit facility, which matures in September 2012, is $550.0 million. Borrowings under the facility are unsecured and bear interest at LIBOR plus a spread ranging from 0.3% to 0.8% based on our credit ratings and amounts outstanding under the facility. Additionally, a commitment fee is assessed at a rate from 0.05% to 0.125%, depending on our credit ratings. Borrowings under this facility are used for general purposes, including capital expenditures. As of September 30, 2010, there were no borrowings outstanding under this facility and $4.4 million was obligated for letters of credit. Amounts obligated for letters of credit are not reflected as debt on our consolidated balance sheets.

6.45% Notes due 2014. In May 2004, we sold $250.0 million aggregate principal of 6.45% notes due 2014 in an underwritten public offering. The notes were issued for the discounted price of 99.8%, or $249.5 million.

5.65% Notes due 2016. In October 2004, we issued $250.0 million of 5.65% notes due 2016 in an underwritten public offering. The notes were issued for the discounted price of 99.9%, or $249.7 million. The outstanding principal amount of the notes was increased $3.1 million and $2.8 million at December 31, 2009 and September 30, 2010, respectively, for the unamortized portion of a gain realized upon termination of a related interest rate swap.

6.40% Notes due 2018. In July 2008, we issued $250.0 million of 6.40% notes due 2018 in an underwritten public offering. The outstanding principal amount of the notes was increased $10.4 million and $9.4 million at December 31, 2009 and September 30, 2010, respectively, for the unamortized portion of gains realized upon termination or discontinuation of hedge accounting treatment of associated interest rate swaps.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6.55% Notes due 2019. In June and August 2009, we issued $550.0 million of 6.55% notes due 2019 in underwritten public offerings. The notes were issued at a net premium of 103.4%, or $568.7 million. In connection with these offerings, we entered into interest rate swap agreements to effectively convert $250.0 million of these notes to floating-rate debt. In May and June 2010, we terminated these interest rate swap agreements. The outstanding principal amount of the notes was decreased by $1.6 million at December 31, 2009 for the fair value less accrued interest of the associated interest rate swap agreements. The outstanding principal amount was increased $15.7 million at September 30, 2010 for the unamortized portion of the gain realized upon termination of the related interest rate swaps.

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.

The revolving credit facility and notes described above are senior indebtedness.

9. Derivative Financial Instruments

Commodity Derivatives

Our petroleum products blending activities produce gasoline products and we can estimate the timing and quantities of sales of these products. We use a combination of forward sales contracts and NYMEX contracts to lock in most of the product margins realized from our blending activities. We account for the forward sales contracts we use in our blending activities as normal sales.

As of September 30, 2010, we had commitments under forward purchase contracts for product purchases of approximately 0.3 million barrels that are being accounted for as normal purchases totaling approximately $30.7 million, and we had commitments under forward sales contracts for product sales of approximately 0.9 million barrels that are being accounted for as normal sales totaling approximately $81.4 million.

We use NYMEX contracts as economic hedges against changes in the price of petroleum products we expect to sell in future periods. Some of the NYMEX contracts we have entered into have qualified for hedge accounting treatment under ASC 815-30, Derivatives and Hedging, while others have not. At September 30, 2010, we had open NYMEX contracts, representing 3.0 million barrels of petroleum products, used as economic hedges for petroleum products we expect to sell in the future in connection with the following business activities:

• Petroleum products blending and fractionation – at September 30, 2010, we had open NYMEX contracts maturing between October 2010 and December 2010 associated with these activities representing 1.1 million barrels of petroleum products, of which 0.8 million barrels were designated as cash flow hedges and 0.3 million barrels that did not qualify as hedges for accounting purposes;

• Linefill on our Houston-to-El Paso pipeline section – at September 30, 2010, we had open NYMEX contracts maturing between October 2010 and July 2011 associated with these activities representing 1.2 million barrels of petroleum products that did not qualify as hedges for accounting purposes; and

• Crude oil storage and pipeline:

• At September 30, 2010, we had open NYMEX contracts associated with our firm commitment to purchase crude oil working inventory we acquired from BP in October 2010. These contracts, representing 0.7 million barrels of crude oil, were designated as fair value hedges for accounting purposes and mature in November 2013.

• At September 30, 2010, we had open NYMEX contracts associated with our crude oil pipeline linefill we acquired from BP in September 2010. These contracts, representing less than 0.1 million barrels of crude oil, were designated as cash flow hedges for accounting purposes and mature in March 2011. The forecasted transaction that is being hedged is the sale of the crude oil pipeline linefill, which we expect will occur in March 2011.

At September 30, 2010, the fair value of our open NYMEX contracts was a net liability of $2.1 million, of which $21 thousand was recorded as energy commodity derivatives contracts and $2.1 million was recorded as other noncurrent liabilities on our

14

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

consolidated balance sheet. At September 30, 2010, we had made margin deposits of $7.5 million for these contracts, which were recorded as energy commodity derivatives deposits on our consolidated balance sheet. We have the right to offset the fair value of our open NYMEX contracts against our margin deposits under a master netting arrangement with our counterpart; however, we have elected to separately disclose these amounts on our consolidated balance sheet. The fair value of our NYMEX agreements are netted together in our consolidated balance sheets.

Interest Rate Derivatives

In June and August 2009, we entered into $150.0 million and $100.0 million, respectively, of interest rate swap agreements to hedge against changes in the fair value of a portion of the $550.0 million of 6.55% notes due 2019, and we accounted for these agreements as fair value hedges. These agreements effectively converted $250.0 million of our 6.55% fixed-rate notes to floating-rate debt. Under the terms of the agreements, we received the 6.55% fixed rate of the notes and paid six-month LIBOR in arrears plus 2.18% on $150.0 million of the swaps and 2.34% on the other $100.0 million. In May 2010, we terminated and settled the $150.0 million of swaps and received $9.6 million (excluding $1.8 million of accrued interest), which was recorded as an adjustment to long-term debt that is being amortized over the remaining life of the 6.55% notes. In June 2010, we terminated and settled the remaining $100.0 million of swaps for $6.6 million (excluding $1.5 million of accrued interest), which was recorded as an adjustment to long-term debt that is being amortized over the remaining life of the 6.55% notes. We had no interest rate swaps outstanding as of September 30, 2010.

The changes in derivative gains included in accumulated other comprehensive loss (“AOCL”) for the three and nine months ended September 30, 2009 and 2010 are as follows (in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
Derivative Gains Included in AOCL	2009			2010			2009			2010
Beginning balance	$	3,571		$	3,407		$	3,653		$	1,743
Net gain (loss) on commodity hedges		639			(179	)		639			(468	)
Reclassification of net gain on cash flow hedges to interest expense		(41	)		(41	)		(123	)		(123	)
Reclassification of net loss (gain) on commodity hedges to product sales revenues		(255	)		(1,068	)		(255	)		967
Ending balance	$	3,914		$	2,119		$	3,914		$	2,119

As of September 30, 2010, the net gain (loss) estimated to be classified to interest expense and product sales revenues over the next twelve months from AOCL is approximately $0.2 million and $(1.2) million, respectively.

The following is a summary of the current impact of our historical derivative activity on long-term debt resulting from the termination of or the discontinuance of hedge accounting treatment of fair value hedges as of December 31, 2009 and September 30, 2010, and for the three and nine months ended September 30, 2009 and 2010 (in thousands):

			Unamortized Amount Recorded in Long-term Debt				Amount Reclassified to Interest Expense from Long-term Debt
Hedge	Total Gain Realized		As of December 31, 2009		As of September 30, 2010		Three Months Ended September 30, 2009			Three Months Ended September 30, 2010			Nine Months Ended September 30, 2009			Nine Months Ended September 30, 2010
Fair value hedges (date executed):
Interest rate swaps 6.40% Notes (July 2008)	$	11,652	$	10,358	$	9,446	$	(304	)	$	(304	)	$	(912	)	$	(912	)
Interest rate swaps 5.65% Notes (October 2004)		3,830		3,093		2,752		(114	)		(114	)		(341	)		(341	)
Interest rate swaps 6.55% Notes (June and August 2009)		16,238		—		15,670		—			(451	)		—			(568	)
Total fair value hedges			$	13,451	$	27,868	$	(418	)	$	(869	)	$	(1,253	)	$	(1,821	)

15

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following is a summary of the effect of derivatives accounted for under ASC 815-25, Derivatives and Hedging—Fair Value Hedges, that were designated as hedging instruments on our consolidated statement of income for the three and nine months ended September 30, 2009 and 2010 (in thousands):

Derivative Instrument	Location of Gain Recognized on Derivative	Amount of Gain Recognized on Derivative				Amount of Interest Expense Recognized on Fixed-Rate Debt (Related Hedged Item)
		Three Months Ended				Three Months Ended
		September 30, 2009		September 30, 2010		September 30, 2009			September 30, 2010
Interest rate swap agreements	Interest expense	$	1,516	$	—	$	(6,997	)	$	—
Derivative Instrument	Location of Gain Recognized on Derivative	Amount of Gain Recognized on Derivative				Amount of Interest Expense Recognized on Fixed-Rate Debt (Related Hedged Item)
		Nine Months Ended				Nine Months Ended
		September 30, 2009		September 30, 2010		September 30, 2009			September 30, 2010
Interest rate swap agreements	Interest expense	$	1,564	$	4,604	$	(7,271	)	$	(17,277	)

During third quarter 2010, we had open NYMEX contracts on 0.7 million barrels of crude oil which were designated as fair value hedges. The unrealized losses of $2.1 million from the agreements during the quarter were fully offset by an adjustment to the working inventory and, therefore, there was no net impact on product sales revenues.

The following is a summary of the effect of derivatives accounted for under ASC 815-30, Derivatives and Hedging—Cash Flow Hedges, that were designated as hedging instruments on our consolidated statement of income for the three and nine months ended September 30, 2009 and 2010 (in thousands):

	Three Months Ended September 30, 2009 Effective Portion
	Amount of  Gain Recognized in AOCL on Derivative			Location of Gain Reclassified from AOCL into Income		Amount of Gain Reclassified from AOCL into Income
Derivative Instrument
Interest rate swap agreements	$	—			Interest expense	$	41
NYMEX commodity contracts		639			Product sales revenues		255
Total cash flow hedges	$	639				$	296
	Three Months Ended September 30, 2010 Effective Portion
	Amount of Loss Recognized in AOCL on Derivative			Location of Gain (Loss) Reclassified from AOCL into Income		Amount of Gain Reclassified from AOCL into Income
Derivative Instrument
Interest rate swap agreements	$	—			Interest expense	$	41
NYMEX commodity contracts		(179	)		Product sales revenues		1,068
Total cash flow hedges	$	(179	)			$	1,109
	Nine Months Ended September 30, 2009 Effective Portion
	Amount of Gain Recognized in AOCL on Derivative			Location of Gain Reclassified from AOCL into Income		Amount of Gain Reclassified from AOCL into Income
Derivative Instrument
Interest rate swap agreements	$	—			Interest expense	$	123
NYMEX commodity contracts		639			Product sales revenues		255
Total cash flow hedges	$	639				$	378

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	Nine Months Ended September 30, 2010 Effective Portion
	Amount of  Loss Recognized in AOCL on Derivative			Location of Gain (Loss) Reclassified from AOCL into Income		Amount of Gain (Loss) Reclassified from AOCL into Income
Derivative Instrument
Interest rate swap agreements	$	—			Interest expense	$	123
NYMEX commodity contracts		(468	)		Product sales revenues		(967	)
Total cash flow hedges	$	(468	)			$	(844	)

There was no ineffectiveness recognized for any of our cash flow or fair value hedges during the three or nine months ended September 30, 2009 or 2010.

The following is a summary of the effect of derivatives accounted for under ASC 815-10-35; Paragraph 2, Derivatives and Hedging—Overall—Subsequent Measurement, that were not designated as hedging instruments on our consolidated statement of income for the three and nine months ended September 30, 2009 and 2010 (in thousands):

		Amount of Gain (Loss) Recognized on Derivative
		Three Months  Ended September 30,						Nine Months Ended September 30,
Derivative Instrument	Location of Gain  (Loss) Recognized on Derivative	2009			2010			2009			2010
Interest rate swap agreements	Other income	$	(11	)	$	—		$	636		$	—
NYMEX commodity contracts	Product sales revenues		5,610			(8,466	)		(17,786	)		8,366
	Total	$	5,599		$	(8,466	)	$	(17,150	)	$	8,366

The following is a summary of the amounts included in our consolidated balance sheets of the fair value of derivatives accounted for under ASC 815, Derivatives and Hedging, that were designated as hedging instruments as of December 31, 2009 and September 30, 2010 (in thousands):

	December 31, 2009
	Asset Derivatives			Liability Derivatives
Derivative Instrument	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Interest rate swap agreements, current portion	Other current assets	$	4,446	Other current liabilities	$	—
Interest rate swap agreements, noncurrent portion	Other noncurrent assets		—	Other noncurrent liabilities		1,649
NYMEX commodity contracts	Energy commodity derivatives contracts		—	Energy commodity derivatives contracts		1,211
	Total	$	4,446	Total	$	2,860
	September 30, 2010
	Asset Derivatives			Liability Derivatives
Derivative Instrument	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
NYMEX commodity contracts	Energy commodity derivatives contracts	$	1,902	Energy commodity derivatives contracts	$	1,122
NYMEX commodity contracts	Other noncurrent assets		—	Other noncurrent liabilities		2,114
	Total	$	1,902	Total	$	3,236

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following is a summary of the amounts included in our consolidated balance sheets of the fair value of derivatives accounted for under ASC 815, Derivatives and Hedging, that were not designated as hedging instruments as of December 31, 2009 and September 30, 2010 (in thousands):

	December 31, 2009
	Asset Derivatives			Liability Derivatives
Derivative Instrument	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
NYMEX commodity contracts	Energy commodity derivatives contracts	$	—	Energy commodity derivatives contracts	$	8,046
NYMEX commodity contracts	Other noncurrent assets		—	Other noncurrent liabilities		1,146
	Total	$	—	Total	$	9,192
	September 30, 2010
	Asset Derivatives			Liability Derivatives
Derivative Instrument	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
NYMEX commodity contracts	Energy commodity derivatives contracts	$	2,484	Energy commodity derivatives contracts	$	3,243

10. Commitments and Contingencies

Environmental Liabilities. Liabilities recognized for estimated environmental costs were $34.4 million and $33.1 million at December 31, 2009 and September 30, 2010, 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 10 years. Environmental expenses recognized as a result of changes in our environmental liabilities are included in operating expenses on our consolidated statements of income. Environmental expense was $4.9 million and $7.1 million, respectively, for the three and nine months ended September 30, 2009 and $5.1 million and $10.2 million, respectively, for the three and nine months ended September 30, 2010.

Environmental Receivables. Receivables from insurance carriers related to environmental matters were $3.9 million at December 31, 2009, of which $3.3 million and $0.6 million were recorded to other accounts receivable and long-term receivables, respectively, on our consolidated balance sheets. Receivables from insurance carriers related to environmental matters at September 30, 2010 were $2.2 million, of which $0.9 million and $1.3 million were recorded to other accounts receivable and long-term receivables, respectively, on our consolidated balance sheets.

Unrecognized Product Gains. Our petroleum terminals operations generate product overages and shortages that result from metering inaccuracies and product evaporation, expansion, releases and contamination. Most of the contracts we have with our customers state that we bear the risk of loss (or gain) from these conditions. When our petroleum terminals experience net product shortages, we recognize expense for those losses in the periods in which they occur. When our petroleum 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 terminals operations had a market value of approximately $3.7 million as of September 30, 2010. 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.

11. Long-Term Incentive Plan

We have a long-term incentive plan (“LTIP”) for certain of our employees 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 of our limited partner units. The remaining units available under the LTIP at September 30, 2010 total 1.0 million. The compensation committee of our general partner’s board of directors administers the LTIP.

18

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Our equity-based incentive compensation expense for 2009 and 2010 was as follows (in thousands):

	Three Months Ended September 30, 2009						Nine Months Ended September 30, 2009
	Equity Method		Liability Method		Total		Equity Method		Liability Method		Total
2007 awards	$	741	$	303	$	1,044	$	2,236	$	770	$	3,006
2008 awards		341		170		511		1,938		649		2,587
2009 awards		350		170		520		1,050		416		1,466
Retention awards		106		—		106		302		—		302
Total	$	1,538	$	643	$	2,181	$	5,526	$	1,835	$	7,361
	Three Months Ended September 30, 2010						Nine Months Ended September 30, 2010
	Equity Method		Liability Method		Total		Equity Method		Liability Method		Total
2007 awards	$	—	$	—	$	—	$	—	$	6	$	6
2008 awards		1,930		1,057		2,987		4,855		2,326		7,181
2009 awards		350		358		708		1,050		818		1,868
2010 awards		473		187		660		1,382		445		1,827
Retention awards		218		—		218		600		—		600
Total	$	2,971	$	1,602	$	4,573	$	7,887	$	3,595	$	11,482

12. Distributions

Distributions we paid during 2009 and 2010 were as follows (in thousands, except per unit amounts):

Payment Date	Per Unit  Cash Distribution Amount		Limited Partner Units		General Partner (a)		Total Cash Distribution
02/13/09	$	0.7100	$	47,537	$	23,478	$	71,015
05/15/09		0.7100		47,537		23,478		71,015
08/14/09		0.7100		47,537		23,478		71,015
Through 9/30/09		2.1300		142,611		70,434		213,045
11/13/09		0.7100		75,677		—		75,677
Total	$	2.8400	$	218,288	$	70,434	$	288,722
02/12/10	$	0.7100	$	75,779	$	—	$	75,779
05/14/10		0.7200		76,847		—		76,847
08/13/10		0.7325		82,393		—		82,393
Through 9/30/10		2.1625		235,019		—		235,019
11/12/10 (b)		0.7450		83,798		—		83,798
Total	$	2.9075	$	318,817	$	—	$	318,817

(a) Includes amounts paid to MMP GP for its incentive distribution rights.

(b) Our general partner declared this cash distribution on October 20, 2010 to be paid on November 12, 2010 to unitholders of record at the close of business on November 5, 2010.

19

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Distributions paid during 2009 by Holdings to its limited partners prior to its dissolution at the completion of the simplification were as follows (in thousands, except per unit amounts):

Payment Date	Per Unit Cash Distribution Amount		Total Cash Distribution
02/13/09	$	0.56759	$	22,490
05/15/09		0.56759		22,490
08/14/09		0.56759		22,490
Through 9/30/09	$	1.70277	$	67,470

Total distributions paid were as follows (in thousands):

	Nine Months Ended September 30,
	2009		2010
Cash distributions we paid	$	213,045	$	235,019
Less distributions we paid to our general partner		70,434		—
Distributions we paid to outside owners		142,611		235,019
Cash distributions paid by Holdings to its outside owners		67,470		—
Total distributions	$	210,081	$	235,019

13. Fair Value

Fair Value of Financial Instruments

We used the following methods and assumptions in estimating our fair value disclosure for financial instruments:

• Cash and cash equivalents. The carrying amounts reported in our consolidated balance sheets approximate fair value due to the short-term maturity or variable rates of these instruments.

• Energy commodity derivatives deposits. This asset represents a short-term deposit we paid associated with our energy commodity derivatives contracts. The carrying amount reported in our consolidated balance sheets approximates fair value as the deposits paid change daily in relation to the associated contracts.

• Long-term receivables. Fair value was determined by estimating the present value of future cash flows using a risk-free rate of interest.

• Energy commodity derivatives contracts. These include NYMEX contracts related to petroleum products. These contracts are carried at fair value in our consolidated balance sheets and are valued based on quoted prices in active markets.

• Debt. The fair value of our publicly traded notes, excluding the value of interest rate swaps qualifying as fair value hedges, was based on the prices of those notes at December 31, 2009 and September 30, 2010. The carrying amount of borrowings under our revolving credit facility approximates fair value due to the variable rates of that instrument.

• Interest rate swaps. Fair value was determined based on an assumed exchange, at the end of each period, in an orderly transaction with the financial institution counterparties of the interest rate derivative agreements adjusted for the effect of credit risk (see Note 9 – Derivative Financial Instruments). The exchange value was calculated using present value techniques on estimated future cash flows based on forward interest rate curves.

20

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table reflects the carrying amounts and fair values of our financial instruments as of December 31, 2009 and September 30, 2010 (in thousands):

Assets (Liabilities)	December 31, 2009						September 30, 2010
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and cash equivalents	$	4,168		$	4,168		$	77,017		$	77,017
Energy commodity derivatives deposits		17,943			17,943			7,499			7,499
Long-term receivables		618			589			1,300			1,292
Energy commodity derivatives contracts (current)		(9,257	)		(9,257	)		21			21
Energy commodity derivatives contracts (noncurrent)		(1,146	)		(1,146	)		(2,114	)		(2,114	)
Debt		(1,680,004	)		(1,777,064	)		(1,892,349	)		(2,110,900	)
Interest rate swaps (current)		4,446			4,446			—			—
Interest rate swaps (noncurrent)		(1,649	)		(1,649	)		—			—

Fair Value Measurements

The following tables summarize the recurring fair value measurements of our NYMEX commodity contracts and interest rate swaps as of December 31, 2009 and September 30, 2010, based on the three levels established by ASC 820-10-50; Paragraph 2, Fair Value Measurements and Disclosures—Overall—Disclosure (in thousands):

Assets (Liabilities)				Fair Value Measurements as of December 31, 2009 using:
	Total			Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Energy commodity derivatives contracts (current)	$	(9,257	)	$	(9,257	)	$	—		$	—
Energy commodity derivatives contracts (noncurrent)		(1,146	)		(1,146	)		—			—
Interest rate swaps (current)		4,446			—			4,446			—
Interest rate swaps (noncurrent)		(1,649	)		—			(1,649	)		—
Assets (Liabilities)				Fair Value Measurements as of September 30, 2010 using:
	Total			Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Energy commodity derivatives contracts (current)	$	21		$	21		$	—		$	—
Energy commodity derivatives contracts (noncurrent)		(2,114	)		(2,114	)		—			—

14. Subsequent Events

Recognizable events

No recognizable events occurred during the period.

Non-recognizable events

On October 20, 2010, our general partner declared a quarterly distribution of $0.745 per unit to be paid on November 12, 2010 to unitholders of record at the close of business on November 5, 2010. The total cash distributions to be paid are $83.8 million (see Note 12—Distributions for details).

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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 petroleum products and crude oil. As of September 30, 2010, our three operating segments included:

• petroleum pipeline system, which is primarily comprised of our 9,600-mile petroleum pipeline system, including 52 terminals;

• petroleum terminals, which includes storage terminal facilities (consisting of six marine terminals located along coastal waterways and crude oil terminals in the Cushing, Oklahoma area) and 27 inland terminals; and

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

Beginning in 2010, our East Houston, Texas terminal was transferred from our petroleum terminals segment to our petroleum pipeline system segment due to its increasing usage as a pipeline terminal. Since the beginning of 2010, this facility has been under petroleum pipeline management and its operating results have been reported both internally and externally as part of that segment. As a result, historical financial results for our segments have been adjusted to conform to the current period’s presentation. This historical reclassification did not materially impact segment financial results and did not change consolidated financial results.

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, 2009.

Recent Developments

Cash Distribution. During On October 20, 2010, the board of directors of our general partner declared a quarterly cash distribution of $0.745 per unit for the period of July 1, 2010 through September 30, 2010. This quarterly cash distribution will be paid on November 12, 2010 to unitholders of record on November 5, 2010. Total distributions to be paid under this declaration are approximately $83.8 million.

Acquisition of Petroleum Storage and Pipelines. On September 1, 2010, we acquired petroleum storage and pipeline assets from BP Pipelines (North America), Inc. (“BP”) for $291.0 million. The storage assets consist of approximately 7.8 million barrels of crude oil storage in Cushing, Oklahoma. In addition, during October 2010, we acquired crude oil working inventories associated with the Cushing crude oil storage assets from BP that have a market value of approximately $56.0 million. The pipeline assets acquired from BP consist of nearly 40 miles of common carrier crude oil pipelines between Houston and Texas City, Texas and two 35-mile common carrier pipelines that transport refined petroleum products from the Texas City refining region to the Houston, Texas area, including connections to third-party pipelines for delivery to other end-use markets. The acquisition was financed with the proceeds of equity and debt offerings completed during the current quarter (see Equity and Debt Offerings, below).

This acquisition will leverage our expertise in transporting and storing petroleum products by expanding our crude oil logistics infrastructure and our energy footprint in the Cushing, Oklahoma and Houston, Texas markets. The acquired assets will facilitate our strategy to develop our existing East Houston terminal into a key distribution point for crude oil to Gulf Coast refineries by improving our connectivity within the Houston market and extending our reach to the Texas City refining region.

Equity and Debt Offerings. In July 2010, we completed a public offering of 5,750,000 of our common units at $46.65 per unit and received net proceeds of approximately $258.4 million after underwriting discounts of $9.5 million and estimated offering expenses of $0.3 million. In August 2010, we issued $300.0 million of 4.25% notes due 2021 in an underwritten public offering. The notes were issued for the discounted price of 99.6%, or $298.9 million, and net proceeds from this offering, after underwriter discounts of $2.0 million and offering costs of $0.4 million, were $296.5 million. The combined net proceeds from these offerings of $554.9 million were used to pay the $291.0 million purchase price of our acquisition of petroleum storage and pipeline assets from BP in September 2010. We also acquired associated crude oil working inventories that have a market value of approximately $56.0 million in October 2010. The remaining proceeds were used to repay the outstanding balance at that time of $175.5 million on our revolving credit facility and for general partnership purposes.

22

Magellan Crude Oil, LLC. In May 2010, Magellan Crude Oil, LLC (“MCO”), a Delaware limited liability company, was formed for the purpose of constructing and operating crude oil storage in the Cushing, Oklahoma crude oil hub for lease to third parties. MCO has executed long-term agreements to lease 4.25 million barrels of crude oil storage to third parties. MCO is in the process of constructing the crude oil storage tanks necessary to service these agreements. The crude oil storage that MCO is constructing is expected to be operational in phases beginning mid-2011, with the final tanks operational by the end of 2011.

Approximately 35% of the common equity of MCO is owned by a private investment group and approximately 65% is owned by us. In addition, we own all of MCO’s 8.5% cumulative preferred equity. We will invest up to $70.0 million in MCO to construct 4.25 million barrels of crude oil storage. Through September 30, 2010, we have contributed cash of $25.7 million to MCO, of which $6.8 million was recorded as cumulative preferred equity and $18.9 million was recorded as common equity. The private investment group’s investment in MCO through September 30, 2010 was $13.4 million. At the time of MCO’s formation, we determined that it was not a variable interest entity and subsequently we concluded that it should be consolidated into our results based on our voting and operational control of that entity. Since we consolidate MCO, non-controlling owners’ interest in consolidated subsidiaries on our consolidated balance sheet reflects the contributions to MCO by the private investment group less their allocated share of MCO’s net losses for the year. The results of MCO have been included in our petroleum terminals segment from the date of its formation.

Texas Frontera, LLC. In July 2010, Texas Frontera, LLC, a Delaware limited liability company, was formed for the purpose of constructing and leasing petroleum products storage tanks at Galena Park, Texas. This company is owned 50% by a third-party and 50% by us. We use the equity method of accounting for this investment and have contributed cash of $0.8 million as of September 30, 2010. We expect to make a total investment of approximately $15.0 million in Texas Frontera, LLC over the next twelve months.

Results of Operations

We believe that investors benefit from having access to the same financial measures utilized by management. Operating margin, which is presented in the following tables, is an important measure used by management to evaluate the economic performance of our core operations. 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 following tables. Operating profit includes expense items, such as depreciation and amortization expense and general and administrative (“G&A”) costs, which management does not consider when evaluating the core profitability of our operations. Additionally, product margin, which management primarily uses to evaluate the profitability of our commodity-related activities, is provided in these tables. Product margin is a non-GAAP measure; however, its components of product sales and product purchases are determined in accordance with GAAP.

23

Three Months Ended September 30, 2009 Compared to Three Months Ended September 30, 2010

	Three Months  Ended September 30,						Variance Favorable  (Unfavorable)
	2009			2010			$ Change			% Change
Financial Highlights ($ in millions, except operating statistics)
Transportation and terminals revenues:
Petroleum pipeline system	$	129.0		$	156.6		$	27.6			21
Petroleum terminals		41.0			49.9			8.9			22
Ammonia pipeline system		4.0			0.7			(3.3	)		(83	)
Intersegment eliminations		(0.5	)		(0.4	)		0.1			20
Total transportation and terminals revenues		173.5			206.8			33.3			19
Affiliate management fee revenue		0.2			0.2			—			—
Operating expenses:
Petroleum pipeline system		51.0			56.9			(5.9	)		(12	)
Petroleum terminals		16.3			23.1			(6.8	)		(42	)
Ammonia pipeline system		7.4			8.3			(0.9	)		(12	)
Intersegment eliminations		(0.8	)		(0.7	)		(0.1	)		(13	)
Total operating expenses		73.9			87.6			(13.7	)		(19	)
Product margin:
Product sales revenues		66.1			199.3			133.2			202
Product purchases		47.9			187.0			(139.1	)		(290	)
Product margin		18.2			12.3			(5.9	)		(32	)
Equity earnings		1.4			1.6			0.2			14
Operating margin		119.4			133.3			13.9			12
Depreciation and amortization expense		24.6			27.4			(2.8	)		(11	)
G&A expense		20.1			23.6			(3.5	)		(17	)
Operating profit		74.7			82.3			7.6			10
Interest expense (net of interest income and interest capitalized)		19.7			24.4			(4.7	)		(24	)
Debt placement fee amortization expense		0.4			0.3			0.1			25
Other (income) expense		(0.1	)		0.8			(0.9	)		n/a
Income before provision for income taxes		54.7			56.8			2.1			4
Provision for income taxes		0.5			0.2			0.3			60
Net income	$	54.2		$	56.6		$	2.4			4
Operating Statistics:
Petroleum pipeline system:
Transportation revenue per barrel shipped	$	1.248		$	1.155
Volume shipped (million barrels)		75.8			97.6
Petroleum terminals:
Storage terminal (formerly marine terminal) average utilization (million barrels per month)		23.6			25.6
Inland terminal throughput (million barrels)		28.3			30.2
Ammonia pipeline system:
Volume shipped (thousand tons)		125			20

24

Transportation and terminals revenues increased by $33.3 million, resulting from:

• an increase in petroleum pipeline system revenues of $27.6 million primarily attributable to higher transportation revenues, higher storage and pipeline capacity lease revenues and incremental fees for terminal throughput, additives and ethanol blending. Transportation revenues increased primarily as a result of 29% higher volumes driven by improved demand for gasoline and diesel fuel and because of acquisitions completed during the quarter. Transportation revenue per barrel shipped declined between periods because the tariffs related to our recently-acquired pipelines are significantly lower than our historical system due to the shorter-haul movements;

• an increase in petroleum terminals revenues of $8.9 million due to higher revenues at both our storage and inland terminals. Storage terminal revenues increased principally due to higher rates on existing storage contracts and the Cushing, Oklahoma terminal we acquired during the quarter. Inland revenues benefitted from higher fees for ethanol and additive blending and higher throughput volumes; and

• a decrease in ammonia pipeline system revenues of $3.3 million due to decreased shipments. The pipeline has been mostly unavailable since mid-May 2010 because of hydrostatic testing being conducted on the pipeline. This phase of the hydrostatic testing was substantially complete at the end of October 2010.

Operating expenses increased by $13.7 million, resulting from:

• an increase in petroleum pipeline system expenses of $5.9 million resulting primarily from higher property taxes, power costs due to higher pipeline volumes in the current quarter and expenses related to recent acquisitions;

• an increase in petroleum terminals expenses of $6.8 million primarily related to higher asset maintenance costs, environmental expense and personnel costs; and

• an increase in ammonia pipeline system expenses of $0.9 million resulting primarily from higher asset integrity costs due to the hydrostatic testing performed on our pipeline during the current quarter.

Product sales revenues primarily resulted from our petroleum products blending activities, product marketing and linefill management associated with our Houston-to-El Paso pipeline section, terminal product gains and transmix fractionation. We utilize New York Mercantile Exchange (“NYMEX”) contracts to hedge against changes in the future price of petroleum products related to these activities. The period change in the mark-to-market value of these contracts that do not qualify for hedge accounting treatment plus the effective portion of the change in value of matured NYMEX contracts that qualified for hedge accounting treatment are also included in product sales revenues. Product margin decreased $5.9 million between periods due primarily to the timing of the recognition of unrealized gains and losses from NYMEX contracts, partially offset by higher profits from our petroleum products blending and Houston-to-El Paso pipeline section linefill management activities.

Depreciation and amortization expense increased by $2.8 million primarily due to expansion capital projects placed into service and acquisitions during the past twelve months.

G&A expense increased by $3.5 million due primarily to higher equity-based compensation costs.

Interest expense, net of interest income and interest capitalized, increased $4.7 million. Our average debt outstanding, excluding fair value adjustments for interest rate hedges, increased to $1.8 billion for third quarter 2010 from $1.5 billion for third quarter 2009 principally due to borrowings for expansion capital expenditures and acquisitions. The weighted-average interest rate on our borrowings, after giving effect to the impact of associated fair value hedges, increased to 5.7% in third quarter 2010 from 5.5% in 2009.

Other income/expense was $0.9 million unfavorable. Third quarter 2010 included the write-off of debt placement fees related to an unused bridge loan.

25

Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2010

	Nine Months  Ended September 30,						Variance Favorable (Unfavorable)
	2009			2010			$ Change			% Change
Financial Highlights ($ in millions, except operating statistics)
Transportation and terminals revenues:
Petroleum pipeline system	$	365.9		$	421.0		$	55.1			15
Petroleum terminals		118.4			144.0			25.6			22
Ammonia pipeline system		12.5			9.6			(2.9	)		(23	)
Intersegment eliminations		(1.6	)		(1.5	)		0.1			6
Total transportation and terminals revenues		495.2			573.1			77.9			16
Affiliate management fee revenue		0.6			0.6			—			—
Operating expenses:
Petroleum pipeline system		137.7			149.2			(11.5	)		(8	)
Petroleum terminals		46.7			57.7			(11.0	)		(24	)
Ammonia pipeline system		13.7			15.5			(1.8	)		(13	)
Intersegment eliminations		(2.9	)		(2.4	)		(0.5	)		(17	)
Total operating expenses		195.2			220.0			(24.8	)		(13	)
Product margin:
Product sales revenues		165.1			585.3			420.2			255
Product purchases		141.5			503.5			(362.0	)		(256	)
Product margin		23.6			81.8			58.2			247
Equity earnings		2.8			4.3			1.5			54
Operating margin		327.0			439.8			112.8			34
Depreciation and amortization expense		70.9			79.5			(8.6	)		(12	)
G&A expense		61.4			67.0			(5.6	)		(9	)
Operating profit		194.7			293.3			98.6			51
Interest expense (net of interest income and interest capitalized)		48.8			67.0			(18.2	)		(37	)
Debt placement fee amortization expense		0.8			1.0			(0.2	)		(25	)
Other (income) expense		(0.7	)		0.8			(1.5	)		214
Income before provision for income taxes		145.8			224.5			78.7			54
Provision for income taxes		1.3			0.9			0.4			31
Net income	$	144.5		$	223.6		$	79.1			55
Operating Statistics:
Petroleum pipeline system:
Transportation revenue per barrel shipped	$	1.199		$	1.222
Volume shipped (million barrels)		221.4			245.9
Petroleum terminals:
Storage terminal (formerly marine terminal) average utilization (million barrels per month)		23.3			24.4
Inland terminal throughput (million barrels)		82.2			86.6
Ammonia pipeline system:
Volume shipped (thousand tons)		420			298

Transportation and terminals revenues increased by $77.9 million, resulting from:

• an increase in petroleum pipeline system revenues of $55.1 million primarily attributable to higher transportation revenues, higher pipeline capacity and storage lease revenues and incremental fees for terminal throughput, ethanol blending and additives. Transportation revenues increased primarily as a result of 11% higher volumes driven by improved demand for gasoline and diesel fuel and also from additional volumes from recent acquisitions;

26

• an increase in petroleum terminals revenues of $25.6 million due to higher revenues at both our storage and inland terminals. Storage terminal revenues increased principally due to higher rates on existing storage, leasing new storage tanks placed in service over the past year and the acquisition of the Cushing, Oklahoma terminal. Inland revenues benefitted from higher fees for ethanol and additive blending and higher throughput volumes; and

• a decrease in ammonia pipeline system revenues of $2.9 million due to lower shipments resulting from the hydrostatic testing performed on our pipeline during 2010.

Operating expenses increased by $24.8 million, resulting from:

• an increase in petroleum pipeline system expenses of $11.5 million resulting primarily from higher operating expenses related to our Houston-to-El Paso pipeline section (which we acquired in third quarter 2009);

• an increase in petroleum terminals expenses of $11.0 million primarily related to higher asset maintenance, environmental and personnel costs; and

• an increase in ammonia pipeline system expenses of $1.8 million due primarily to an increase in asset integrity costs from the hydrostatic testing performed on our pipeline during 2010.

Product sales revenues primarily resulted from our petroleum products blending activities, product marketing and linefill management associated with our Houston-to-El Paso pipeline section, terminal product gains and transmix fractionation. We utilize NYMEX contracts to hedge against changes in the future price of petroleum products related to these activities. The period change in the mark-to-market value of these contracts that do not qualify for hedge accounting treatment plus the effective portion of the change in value of matured NYMEX contracts that qualified for hedge accounting treatment are also included in product sales revenues. Product margin increased $58.2 million between periods due primarily to the recognition of unrealized gains and losses from our NYMEX contracts. Due to mark-to-market adjustments, much of the profit related to the commodity sales activity during the 2009 period was realized in late 2008. Product margin also increased due to profits from our linefill management activities associated with our Houston-to-El Paso pipeline section, as well as higher profits from our petroleum products blending and fractionation activities and the sale of additional terminal product overages at higher prices.

Depreciation and amortization expense increased by $8.6 million primarily due to expansion capital projects placed into service during the past twelve months and the acquisition of our Houston-to-El Paso pipeline section.

G&A expense increased by $5.6 million between periods primarily due to higher equity-based incentive compensation costs.

Interest expense, net of interest income and interest capitalized, increased $18.2 million. Our average debt outstanding, excluding fair value adjustments for interest rate hedges, increased to $1.7 billion for the nine months ending September 30, 2010 from $1.3 billion for the nine months ending September 30, 2009 principally due to borrowings for expansion capital expenditures and acquisitions. The weighted-average interest rate on our borrowings, after giving effect to the impact of associated fair value hedges, decreased to 5.3% in 2010 from 5.5% in 2009.

Other income was $1.5 million unfavorable. The 2009 period includes favorable gains recognized from certain interest rate swap agreements that were settled during 2009, while the 2010 period includes the write-off of debt placement fees related to an unused bridge loan.

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Liquidity and Capital Resources

Cash Flows and Capital Expenditures

Net cash provided by operating activities was $179.1 million and $315.9 million for the nine months ended September 30, 2009 and 2010, respectively. The $136.8 million increase from 2009 to 2010 was primarily attributable to:

• an increase in net income of $87.6 million, excluding the increase in non-cash depreciation and amortization expense;

• a $46.0 million increase resulting from a $10.3 million increase in inventory in 2010 versus a $56.3 million increase in inventory in 2009 primarily due to the purchase of our Houston-to-El Paso linefill inventory during 2009;

• a $10.9 million increase resulting from a $15.2 million increase in accounts payable in 2010 versus a $4.3 million increase in 2009 due primarily to the timing of invoices paid to vendors and suppliers; and

• an $8.4 million increase resulting from a $1.8 million decrease in reimbursable costs in 2010 versus a $6.6 million increase in 2009 primarily due to the timing of costs incurred related to insurance claims for which we expect to be reimbursed and payments received on those insurance claims.

These increases were partially offset by an $18.0 million decrease resulting from a $1.7 million decrease in accrued interest payable in 2010 versus a $16.3 million increase in accrued interest payable in 2009 due primarily to the timing of semi-annual interest payments.

Net cash used by investing activities for the nine months ended September 30, 2009 and 2010 was $515.7 million and $471.8 million, respectively. During 2010, we acquired certain storage and pipeline assets from BP for $291.0 million, which was reported as the acquisition of a business. Also during 2010, we acquired petroleum products storage tanks at various locations on our petroleum pipeline system for $29.3 million, and we spent $160.7 million for capital expenditures, which included $27.5 million for maintenance capital and $133.2 million for expansion capital. Also, during 2010, proceeds from the sale of assets were $5.3 million, including $3.0 million of proceeds from the settlement of our insurance claim related to a tank fire at one of our petroleum pipeline system terminals. During 2009, we completed the Houston-to-El Paso pipeline section acquisition for $252.3 million plus the fair value of the linefill of $86.1 million. We also acquired a petroleum products terminal in Oklahoma for $20.0 million. These acquisitions were reported collectively as acquisition of businesses. Additionally, we spent $157.3 million for capital expenditures, which included $34.0 million for maintenance capital and $123.3 million for expansion capital during 2009.

Net cash provided by financing activities for the nine months ended September 30, 2009 and 2010 was $302.4 million and $228.8 million, respectively. During 2010, we received net proceeds of $258.4 million from our public offering of common units and $298.9 million, net of discounts, from borrowings under notes. Combined, these net proceeds were used to acquire certain assets from BP and to repay the outstanding balance on our revolving credit facility of $175.5 million at that time, with the balance used for general partnership purposes. Additionally, we paid cash distributions of $235.0 million to our unitholders while net repayments on our revolving credit facility, including the $175.5 million repayment above, were $101.6 million. Also, during 2010, we received proceeds of $16.2 million from the termination and settlement of interest rate swap agreements. During 2009, borrowings under notes (including net premium) of $568.7 million were used to repay, in total, $454.3 million of borrowings on our revolving credit facility, with the balance used for general partnership purposes, including capital expenditures. Net repayments on the revolving credit facility during 2009, prior to the repayment of the $454.3 million, were $491.3 million. Additionally, we paid cash distributions of $210.1 million.

During third quarter 2010, we paid $82.4 million in cash distributions to our unitholders. Based on the declared quarterly distribution of $0.745 per unit associated with the third quarter of 2010, we will pay $83.8 million in distributions during fourth quarter 2010. If we continue to pay cash distributions at our current level and the number of outstanding units remains the same, we will pay total cash distributions of $335.2 million on an annual basis.

In January 2010, the cumulative amounts of the January 2007 award grants were settled by issuing 140,317 limited partner units and distributing those units to the participants. Associated tax withholdings of $3.4 million and employer taxes of $0.5 million were paid in January 2010.

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Capital Requirements

Our businesses require continual investment to upgrade or enhance existing operations and to ensure compliance with safety and environmental regulations. Capital spending 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.

For the nine months ended September 30, 2010, our maintenance capital spending was $27.5 million, including $0.6 million of spending reimbursable by insurance. For 2010, we expect to incur maintenance capital expenditures for our existing businesses of approximately $45.0 million.

In addition to maintenance capital expenditures, we also incur expansion capital expenditures at our existing facilities. During the first nine months of 2010, we spent $133.2 million for organic growth capital, $291.0 to acquire certain assets from BP and $29.3 million to acquire petroleum products storage at various locations on our petroleum pipeline system. Based on the progress of expansion projects already underway, we expect to spend approximately $565.0 million of expansion capital during 2010, including acquisitions, with an additional $125.0 million in future years to complete these projects.

Liquidity

Consolidated debt at December 31, 2009 and September 30, 2010 was as follows (in thousands):

	December 31, 2009		September 30, 2010		Weighted-Average Interest Rate at September 30, 2010 (1)
Revolving credit facility	$	101,600	$	—		—
6.45% Notes due 2014		249,732		249,772		6.3	%
5.65% Notes due 2016		252,897		252,574		5.7	%
6.40% Notes due 2018		260,340		259,428		5.9	%
6.55% Notes due 2019		566,500		582,719		5.2	%
4.25% Notes due 2021		—		298,911		4.3	%
6.40% Notes due 2037		248,935		248,945		6.3	%
Total debt	$	1,680,004	$	1,892,349

(1) Weighted-average interest rate includes the impact of interest rate swaps and the amortization/accretion of discounts and premiums and gains and losses realized on various cash flow and fair value hedges.

Note discounts and premiums are being amortized or accreted to the applicable notes over the respective lives of the associated notes.

Revolving Credit Facility. The total borrowing capacity under the revolving credit facility, which matures in September 2012, is $550.0 million. Borrowings under the facility are unsecured and bear interest at LIBOR plus a spread ranging from 0.3% to 0.8% based on our credit ratings and amounts outstanding under the facility. Additionally, a commitment fee is assessed at a rate from 0.05% to 0.125%, depending on our credit ratings. Borrowings under this facility are used for general purposes, including capital expenditures. As of September 30, 2010, no borrowings were outstanding under this facility; however, $4.4 million was obligated for letters of credit. Amounts obligated for letters of credit are not reflected as debt on our consolidated balance sheets.

6.45% Notes due 2014. In May 2004, we sold $250.0 million aggregate principal of 6.45% notes due 2014 in an underwritten public offering. The notes were issued for the discounted price of 99.8%, or $249.5 million.

5.65% Notes due 2016. In October 2004, we issued $250.0 million of 5.65% notes due 2016 in an underwritten public offering. The notes were issued for the discounted price of 99.9%, or $249.7 million. The outstanding principal amount of the notes was increased $3.1 million and $2.8 million at December 31, 2009 and September 30, 2010, respectively, for the unamortized portion of a gain realized upon termination of a related interest rate swap.

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6.40% Notes due 2018. In July 2008, we issued $250.0 million of 6.40% notes due 2018 in an underwritten public offering. The outstanding principal amount of the notes was increased $10.4 million and $9.4 million at December 31, 2009 and September 30, 2010, respectively, for the unamortized portion of gains realized upon termination or discontinuation of hedge accounting treatment of associated interest rate swaps.

6.55% Notes due 2019. In June and August 2009, we issued $550.0 million of 6.55% notes due 2019 in underwritten public offerings. The notes were issued at a net premium of 103.4%, or $568.7 million. In connection with these offerings, we entered into interest rate swap agreements to effectively convert $250.0 million of these notes to floating-rate debt. In May and June 2010, we terminated these interest rate swap agreements. The outstanding principal amount of the notes was decreased by $1.6 million at December 31, 2009 for the fair value less accrued interest of the associated interest rate swap agreements. The outstanding principal amount was increased $15.7 million at September 30, 2010 for the unamortized portion of the gain realized upon termination of the related interest rate swaps.

4.25% Notes due 2021. In August 2010, we issued $300.0 million of 4.25% notes due 2021 in an underwritten public offering. The notes were issued for the discounted price of 99.6%, or $298.9 million. Net proceeds from this offering, after underwriting discounts of $2.0 million and offering costs of $0.4 million, were $296.5 million.

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.

The revolving credit facility and notes described above are senior indebtedness.

Interest Rate Derivatives

In June and August 2009, we entered into $150.0 million and $100.0 million, respectively, of interest rate swap agreements to hedge against changes in the fair value of a portion of the $550.0 million of 6.55% notes due 2019, and we accounted for these agreements as fair value hedges. These agreements effectively converted $250.0 million of our 6.55% fixed-rate notes to floating-rate debt. Under the terms of the agreements, we received the 6.55% fixed rate of the notes and paid six-month LIBOR in arrears plus 2.18% for the $150.0 million swaps and 2.34% for the other $100.0 million. In May 2010, we terminated and settled the $150.0 million of swaps and received $9.6 million (excluding $1.8 million of accrued interest), which was recorded as an adjustment to long-term debt that is being amortized over the remaining life of the 6.55% notes. In June 2010, we terminated and settled the remaining $100.0 million of swaps for $6.6 million (excluding $1.5 million of accrued interest), which was recorded as an adjustment to long-term debt that is being amortized over the remaining life of the 6.55% notes. We had no interest rate swaps outstanding as of September 30, 2010.

Off-Balance Sheet Arrangements

None.

Environmental

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

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Other Items

NYMEX Contracts. We use NYMEX contracts as economic hedges against changes in the future price of petroleum products. Some of the NYMEX contracts we entered into qualified as hedges for accounting purposes under Accounting Standards Codification (“ASC”) 815-30, Derivatives and Hedging, while others have not. Currently, we have three specific groups of commodities that are being hedged with NYMEX contracts:

• Future sales of petroleum products generated from our blending and fractionation activities:

Ø The gains and losses resulting from the mark-to-market changes in value of NYMEX contracts that qualify for hedge accounting treatment are not included in product sales revenues in our consolidated statement of income until the hedged petroleum products were physically sold. During 2010, we recognized $1.0 million of losses associated with derivative agreements that qualified as hedges when the hedged products were sold and the contracts were settled.

Ø As of September 30, 2010, we had open NYMEX contracts for 0.3 million barrels of petroleum products that did not qualify for hedge accounting treatment. We recognize the period change in fair value of these agreements in our consolidated income statement. These contracts mature between October and December 2010. The cumulative amount of unrealized gains through September 30, 2010 associated with these agreements of $0.5 million has been recorded as an increase in product sales revenues on our consolidated statements of income and energy commodity derivatives contracts on our consolidated balance sheet, all of which was recognized during 2010. Additionally, we realized gains of $3.1 million on NYMEX contracts that did not qualify for hedge accounting treatment that settled during 2010.

• Future commodity sales of linefill and working inventory associated with our Houston-to-El Paso pipeline section:

Ø At September 30, 2010, we had open NYMEX contracts covering 1.2 million barrels to hedge against changes in the future price of petroleum products associated with the linefill barrels. Contracts covering 0.3 million barrels mature between October and December 2010 and contracts covering 0.9 million barrels mature in July 2011. Because these NYMEX contracts do not qualify for hedge accounting treatment, we recognize the period change in fair value of these agreements in our consolidated income statement. The cumulative amount of unrealized gains through September 30, 2010 associated with these agreements was $0.8 million, of which $1.7 million of gains were recognized during the first three quarters of 2010 and $0.9 million of losses were recognized in the last two quarters of 2009. Additionally, we recognized $2.3 million of gains associated with the linefill NYMEX contracts that were settled during 2010 and recorded as product sales revenues on our consolidated income statement.

• Future commodity sales of linefill and working inventory associated with our crude pipeline and crude storage activities:

Ø During third quarter 2010, we entered into NYMEX contracts hedging less than 0.1 million barrels of linefill in a crude pipeline connected to our Cushing, Oklahoma terminal. These contracts qualified for and were designated as cash flow hedges and mature in March 2011. The unrealized loss of $0.2 million from these agreements during the quarter was recorded to other comprehensive income and did not impact product sales revenues.

Ø During the third quarter 2010, we entered into NYMEX contracts to hedge future price changes on 0.7 million barrels of crude oil working inventory. These contracts qualified for and were designated as fair value hedges and mature in November 2013. The unrealized losses of $2.1 million from these agreements during the quarter were fully offset by an adjustment to the working inventory and, therefore, there was no net impact on product sales revenues.

Ø During third quarter 2010, prior to the execution of the cash flow and fair value hedges discussed above, we entered into certain short-term NYMEX contracts as economic hedges of both the linefill and crude oil working inventory discussed above. These short-term contracts were not designated as hedges for accounting purposes. These contracts were terminated during the quarter and we realized a gain of $0.8 million, which we recorded as product sales revenues.

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The following table provides a summary of the mark-to-market gains and losses associated with NYMEX contracts and the accounting period that the gains and losses were recognized in our consolidated statements of income for the nine months ended September 30, 2009 and 2010 (in millions):

2009
NYMEX losses recorded in 2009 that were associated with physical product sales during the nine months ended September 30, 2009	$	(9.0	)
NYMEX losses recorded in 2009 that were associated with future physical product sales		(8.5	)
Total NYMEX losses which impacted product sales revenues during the nine months ended September 30, 2009	$	(17.5	)
2010
NYMEX gains recorded in 2010 that were associated with physical product sales during the nine months ended September 30, 2010	$	5.2
NYMEX gains recorded in 2010 that were associated with future physical product sales		2.2
Total NYMEX gains which impacted product sales revenues during the nine months ended September 30, 2010	$	7.4

Ammonia Pipeline Testing. During 2010, we have been performing extensive hydrostatic testing of our ammonia pipeline system. Expenditures through September 30, 2010 for this integrity work were $5.9 million, which is $1.7 million higher than integrity costs incurred in 2009. We expect to incur $1.7 million in fourth quarter 2010 to complete this phase of testing. During certain periods of testing, the pipeline was unavailable for shipments, resulting in reduced shipment volumes. The ammonia pipeline is expected to return to service in fourth quarter 2010.

Pipeline Tariff Changes. The Federal Energy Regulatory Commission (“FERC”) regulates the rates charged on interstate common carrier pipeline operations primarily through an index methodology, which establishes the maximum amount by which tariffs can be adjusted. Approximately 40% of our tariffs are subject to this indexing methodology while the remaining 60% of the tariffs can be adjusted at our discretion based on competitive factors. The approved methodology used for 2009 was the annual change in the producer price index for finished goods (“PPI-FG”) plus 1.3%. The FERC is currently reviewing the indexing methodology to be used for the five-year period beginning in July 2011 and we expect the FERC to make a decision regarding the indexing methodology in the spring of 2011.

Unrecognized Product Gains. Our petroleum terminals operations generate product overages and shortages that result from metering inaccuracies and product evaporation, expansion, releases and contamination. Most of the contracts we have with our customers state that we bear the risk of loss (or gain) from these conditions. When our petroleum terminals experience net product shortages, we recognize expense for those losses in the periods in which they occur. When our petroleum 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 terminals operations had a market value of approximately $3.7 million as of September 30, 2010. 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.

New Accounting Pronouncements

On February 24, 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2010-09, Subsequent Events (Topic 855): Amendments to Certain Recognition and Disclosure Requirements. This ASU amended the guidance on subsequent events to remove the requirement for entities that file financial statements with the Securities and Exchange Commission (“SEC”) to disclose the date through which it has evaluated subsequent events. This ASU was effective on its issuance date. Our adoption of this ASU did not have an impact on our financial position, results of operations or cash flows.

On January 21, 2010, the FASB issued ASU No. 2010-06, Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements. This ASU requires disclosure of: (i) separate fair value measurements for each class of assets and liabilities, (ii) significant transfers between level 1 and level 2 in the fair value hierarchy and the reasons for such transfers, (iii) gains and losses for the period and purchases, sales, issuances and settlements for Level 3 fair value measurements, (iv) transfers into and out of Level 3 of the hierarchy and the reasons for such transfers and (v) the valuation techniques applied and inputs used in determining Level 2 and Level 3 measurements for each class of assets and liabilities. This ASU was generally effective for interim and annual reporting periods beginning after December 15, 2009; however, the requirements to disclose separately purchases, sales,

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issuances and settlements in the Level 3 reconciliation are effective for fiscal years beginning after December 15, 2010 (and for interim periods within such years). Early adoption is allowed. Our adoption of the applicable sections of this ASU did not have a material impact on our financial position, results of operations or cash flows.

In August 2009, the FASB issued ASU No. 2009-05, an update to ASC 820-10-35, Fair Value Measurements. This ASU provides guidance on measuring the fair value of liabilities. The guidance in this ASU was effective for the first reporting period, including interim periods, beginning after August 28, 2009. Our adoption of this ASU on September 1, 2009 did not have a material impact on our financial position, results of operations or cash flows.

In June 2009, the FASB issued Statement of Financial Accounting Standards (“SFAS”) No. 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles. The new codification supersedes all existing GAAP standards and became the single source of GAAP authoritative literature, effective for financial statements issued for interim and annual periods ending after September 15, 2009.

In May 2009, the FASB issued SFAS No. 165, Subsequent Events (as amended). This Statement requires the disclosure of subsequent events to be distinguished between recognized and non-recognized subsequent events. Further, entities are required to include a description of the period through which subsequent events were evaluated. (Note: ASU No. 2010-09 superseded the requirement to disclose the period through which subsequent events were evaluated for entities who file financial statements with the SEC). Our adoption of this Standard on June 30, 2009 did not have a material impact on our financial position, results of operations or cash flows.

In April 2009, the FASB issued FASB Staff Position (“FSP”) No. FAS 107-1 and Accounting Principles Board (“APB”) 28-1, Interim Disclosures About Fair Value of Financial Instruments. This FSP amended SFAS No. 107 (FASB ASC 825-10) and APB Opinion No. 28: (FASB ASC 270-10) by requiring quarterly as well as annual disclosures of the fair value of all financial instruments. The disclosures are to be in a form that makes it clear whether the fair value and carrying amounts represent assets or liabilities and how the carrying amounts relate to what is reported on the balance sheet. Our adoption of this FSP on June 30, 2009 did not have a material impact on our financial position, results of operations or cash flows.

In April 2009, the FASB issued FSP No. FAS 141(R)-1, Accounting for Assets Acquired and Liabilities Assumed in a Business Combination that Arise from Contingencies. This FSP amended and clarified FASB Statement No. 141 (revised 2007), Business Combinations, to address application issues on the initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. This FSP was effective for assets or liabilities arising from contingencies in business combinations that occurred following the start of the first fiscal year that begins on or after December 15, 2008. Our adoption of this FSP did not have a material impact on our financial position, results of operations or cash flows.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We may be exposed to market risk through changes in commodity prices and interest rates. We have established policies to monitor and control these market risks. We also enter into derivative agreements to help manage our exposure to commodity price and interest rate risks.

Commodity Price Risk

We use derivatives to help us manage product purchases and sales. Derivatives that qualify for and are designated as normal purchases and sales are accounted for using traditional accrual accounting. As of September 30, 2010, we had commitments under forward purchase contracts for product purchases of approximately 0.3 million barrels that are being accounted for as normal purchases totaling approximately $30.7 million, and we had commitments under forward sales contracts for product sales of approximately 0.9 million barrels that are being accounted for as normal sales totaling approximately $81.4 million.

At September 30, 2010, we had open NYMEX contracts used as economic hedges against changes in the price of petroleum products we expect to sell in the future. Some of the NYMEX contracts we have entered into have qualified for hedge accounting treatment under ASC 815-30, Derivatives and Hedging, while others have not.

At September 30, 2010, the fair value of open NYMEX contracts, representing 3.0 million barrels of petroleum products, was a net liability of $2.1 million, of which $21 thousand was recorded as energy commodity derivatives contracts and $2.1 million was recorded as other noncurrent liabilities on our consolidated balance sheet. These open NYMEX contracts mature between October 2010 and November 2013. At September 30, 2010, we had made margin deposits of $7.5 million for these contracts, which was recorded as energy commodity derivatives deposits on our consolidated balance sheet. We have the right to offset the fair value of our open NYMEX contracts against our margin deposits under a master netting arrangement with our counterpart; however, we have elected to separately disclose these amounts on our consolidated balance sheet.

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At September 30, 2010, we had open NYMEX contracts of 3.0 million barrels of petroleum products, of which 1.5 million barrels of petroleum products did not qualify for hedge accounting treatment. A $1.00 per barrel increase in the price of these NYMEX contracts for reformulated gasoline blendstock for oxygen blending (“RBOB”) gasoline or heating oil would result in a $1.5 million decrease in our product sales revenues and a $1.00 per barrel decrease in the price of these NYMEX contracts for RBOB or heating oil would result in a $1.5 million increase in our product sales revenues. However, the increases or decreases in product sales revenues we recognize from our open NYMEX contracts are substantially offset by higher or lower product sales revenues when the physical sale of the product occurs. These contracts may be for the purchase or sale of product in markets different from those in which we are attempting to hedge our exposure, resulting in hedges that do not eliminate all price risks.

Interest Rate Risk

As of September 30, 2010, we had no variable-rate borrowings outstanding.

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. There has been no change in our internal control over financial reporting (as defined in Rule 13a-15(f) of the Securities Exchange Act) during the quarter ended September 30, 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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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,” “should” and other similar expressions. Although we believe our forward-looking statements are based on reasonable assumptions, statements made regarding future results are not guarantees of future performance and subject to numerous assumptions, uncertainties and risks that are difficult to predict. Therefore, actual outcomes and results may be materially different from the results stated or implied in such forward-looking statements included in this report.

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

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

• price fluctuations for petroleum products, crude oil and natural gas liquids and expectations about future prices for these products;

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

• changes in the financial condition of our customers;

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

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

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

• changes in demand for storage in our petroleum terminals;

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

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

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

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

• weather patterns materially different than historical trends;

• an increase in the competition our operations encounter;

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

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

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

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

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

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

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

• the effect of changes in accounting policies;

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

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

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• 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.

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PART II

OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

ITEM 1A. RISK FACTORS

In addition to the information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2009, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K are not our only risks. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.

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

The storage and pipeline assets we acquired from BP Pipelines (North America), Inc. (“BP”) depend on facilities owned and operated by others and on a limited number of customers.

The crude oil pipeline system and the refined petroleum pipeline system that we acquired from BP both depend to a substantial degree on the operation of the Texas City, Texas refineries to which those systems are connected, resulting in significant exposure to the performance of the owners of those refineries. In addition, those systems rely on connections to numerous other pipelines owned and operated by others for supply and distribution of the crude oil and refined petroleum products transported on those systems. Outages at the Texas City, Texas refineries or reduced or interrupted throughput on these connecting pipelines because of weather-related or other natural causes, testing, line repair, damage, reduced operating pressures or other causes could reduce the shipments on the pipeline systems we have acquired, which could adversely affect our cash flows and our ability to pay distributions.

The crude oil storage assets that we acquired from BP in Cushing, Oklahoma have been leased solely by an affiliate of the seller of those assets, and we are subject to risks of loss from nonpayment by that customer. In addition, any decision by that customer not to renew its lease at the end of the original lease term could result in a reduction of the revenues we receive related to those assets, which could adversely affect our cash flows and our ability to pay distributions.

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. RESERVED

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ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

Exhibit 4.1*	Indenture dated as of August 11, 2010 between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as trustee (filed as Exhibit 4.1 to Form 8-K filed August 16, 2010).
Exhibit 4.2*	First Supplemental Indenture dated as of August 22, 2010 between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as trustee (filed as Exhibit 4.2 to Form 8-K filed August 16, 2010).
Exhibit 10.1*	Cushing and South Houston Asset Purchase Agreement by and between BP Pipelines (North America), Inc. and Magellan Pipeline Company, L.P. dated July 12, 2010 (filed as Exhibit 10.1 to Form 10-Q filed August 3, 2010).
Exhibit 10.2*	Commitment Letter dated as of July 12, 2010 among J.P. Morgan Securities, Inc., JPMorgan Chase Bank, N.A., Bank of America, N.A., Morgan Stanley Senior Funding, Inc. and Wells Fargo Bank, National Association and Magellan Midstream Partners, L.P. (filed as Exhibit 10.2 to Form 10-Q filed August 3, 2010).
Exhibit 10.3*	Indenture dated as of August 11, 2010 between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as trustee (filed as Exhibit 4.1 to Form 8-K filed August 16, 2010).
Exhibit 10.4*	First Supplemental Indenture dated as of August 22, 2010 between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as trustee (filed as Exhibit 4.2 to Form 8-K filed August 16, 2010).
Exhibit 10.5	Amendment No. 2 dated as of September 17, 2010 to $550,000,000 Second Amended and Restated Credit Agreement dated as of September 20, 2007 among Magellan Midstream Partners, L.P., as Borrower, the Lenders party thereto and Wachovia Bank, N.A., as Administrative Agent.
Exhibit 12	Ratio of Earnings to Fixed Charges.
Exhibit 31.1	Rule 13a-14(a)/15d-14(a) Certification of Don R. Wellendorf, principal executive officer.
Exhibit 31.2	Rule 13a-14(a)/15d-14(a) Certification of John D. Chandler, principal financial officer.
Exhibit 32.1	Section 1350 Certification of Don R. Wellendorf, Chief Executive Officer.
Exhibit 32.2	Section 1350 Certification of John D. Chandler, Chief Financial Officer.
Exhibit 101.INS	XBRL Instance Document.
Exhibit 101.SCH	XBRL Taxonomy Extension Schema.
Exhibit 101.CAL	XBRL Taxonomy Extension Calculation Linkbase.
Exhibit 101.LAB	XBRL Taxonomy Extension Label Linkbase.
Exhibit 101.PRE	XBRL Taxonomy Extension Presentation Linkbase.

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

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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 November 2, 2010.

MAGELLAN MIDSTREAM PARTNERS, L.P.
By:	Magellan GP, LLC,
	its General Partner
/s/ John D. Chandler
John D. Chandler
Chief Financial Officer
(Principal Accounting and Financial Officer)

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INDEX TO EXHIBITS

EXHIBIT NUMBER	DESCRIPTION
Exhibit 4.1*	Indenture dated as of August 11, 2010 between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as trustee (filed as Exhibit 4.1 to Form 8-K filed August 16, 2010).
Exhibit 4.2*	First Supplemental Indenture dated as of August 22, 2010 between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as trustee (filed as Exhibit 4.2 to Form 8-K filed August 16, 2010).
Exhibit 10.1*	Cushing and South Houston Asset Purchase Agreement by and between BP Pipelines (North America), Inc. and Magellan Pipeline Company, L.P. dated July 12, 2010 (filed as Exhibit 10.1 to Form 10-Q filed August 3, 2010).
Exhibit 10.2*	Commitment Letter dated as of July 12, 2010 among J.P. Morgan Securities, Inc., JPMorgan Chase Bank, N.A., Bank of America, N.A., Morgan Stanley Senior Funding, Inc. and Wells Fargo Bank, National Association and Magellan Midstream Partners, L.P. (filed as Exhibit 10.2 to Form 10-Q filed August 3, 2010).
Exhibit 10.3*	Indenture dated as of August 11, 2010 between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as trustee (filed as Exhibit 4.1 to Form 8-K filed August 16, 2010).
Exhibit 10.4*	First Supplemental Indenture dated as of August 22, 2010 between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as trustee (filed as Exhibit 4.2 to Form 8-K filed August 16, 2010).
Exhibit 10.5	Amendment No. 2 dated as of September 17, 2010 to $550,000,000 Second Amended and Restated Credit Agreement dated as of September 20, 2007 among Magellan Midstream Partners, L.P., as Borrower, the Lenders party thereto and Wachovia Bank, N.A., as Administrative Agent.
Exhibit 12	Ratio of Earnings to Fixed Charges.
Exhibit 31.1	Rule 13a-14(a)/15d-14(a) Certification of Don R. Wellendorf, principal executive officer.
Exhibit 31.2	Rule 13a-14(a)/15d-14(a) Certification of John D. Chandler, principal financial officer.
Exhibit 32.1	Section 1350 Certification of Don R. Wellendorf, Chief Executive Officer.
Exhibit 32.2	Section 1350 Certification of John D. Chandler, Chief Financial Officer.
Exhibit 101.INS	XBRL Instance Document.
Exhibit 101.SCH	XBRL Taxonomy Extension Schema.
Exhibit 101.CAL	XBRL Taxonomy Extension Calculation Linkbase.
Exhibit 101.LAB	XBRL Taxonomy Extension Label Linkbase.
Exhibit 101.PRE	XBRL Taxonomy Extension Presentation Linkbase.

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

40