Edgar Filing: MAGELLAN MIDSTREAM PARTNERS LP

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2010

¨	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 x Accelerated filer ¨ Non-accelerated filer ¨ Smaller reporting company ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12-b-2 of the Exchange

Act). Yes ¨ No x

As of August 2, 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.		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.	Product Sales Revenues	8
	4.	Segment Disclosures	8
	5.	Inventory	10
	6.	Employee Benefit Plans	11
	7.	Debt	12
	8.	Derivative Financial Instruments	13
	9.	Commitments and Contingencies	16
	10.	Long-Term Incentive Plan	17
	11.	Distributions	18
	12.	Fair Value Disclosures	19
	13.	Subsequent Events	20
ITEM 2.		MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Introduction			21
Recent Developments			21
Results of Operations			22
Liquidity and Capital Resources			26
Off-Balance Sheet Arrangements			29
Environmental			29
Other Items			29
New Accounting Pronouncements			31
ITEM 3.		QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	32
ITEM 4.		CONTROLS AND PROCEDURES	32
Forward-Looking Statements			33

PART II
OTHER INFORMATION

ITEM 1.		LEGAL PROCEEDINGS	35
ITEM 1A.		RISK FACTORS	35
ITEM 2.		UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	35
ITEM 3.		DEFAULTS UPON SENIOR SECURITIES	35
ITEM 4.		RESERVED	35
ITEM 5.		OTHER INFORMATION	35
ITEM 6.		EXHIBITS	36

PART I

FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except per unit amounts)

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2010			2009			2010
Transportation and terminals revenues	$	166,703		$	193,173		$	321,723		$	366,342
Product sales revenues		41,327			229,698			99,043			386,034
Affiliate management fee revenue		190			189			380			379

Total revenues		208,220			423,060			421,146			752,755
Costs and expenses:
Operating		60,848			70,287			121,315			132,396
Product purchases		40,990			183,639			93,620			316,523
Depreciation and amortization		23,163			25,715			46,315			52,057
General and administrative		20,248			20,178			41,384			43,420

Total costs and expenses		145,249			299,819			302,634			544,396
Equity earnings		939			1,480			1,458			2,669

Operating profit		63,910			124,721			119,970			211,028
Interest expense		15,809			22,521			31,361			44,295
Interest income		(206	)		(7	)		(427	)		(11	)
Interest capitalized		(942	)		(803	)		(1,878	)		(1,651	)
Debt placement fee amortization		224			329			444			657
Other income		(565	)		—			(647	)		—

Income before provision for income taxes		49,590			102,681			91,117			167,738
Provision for income taxes		452			229			809			752

Net income	$	49,138		$	102,452		$	90,308		$	166,986

Allocation of net income:
Non-controlling owners’ interest	$	34,527		$	(68	)	$	63,675		$	(68	)
Limited partners’ interest		14,611			102,520			26,633			167,054

Net income	$	49,138		$	102,452		$	90,308		$	166,986


Basic and diluted net income per limited partner unit	$	0.37		$	0.96		$	0.67		$	1.56


Weighted average number of limited partner units outstanding used for basic and diluted net income per unit calculation		39,639			106,896			39,638			106,869

See notes to consolidated financial statements.

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(In thousands)


	December 31, 2009			June 30, 2010
				(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	4,168		$	35,094
Trade accounts receivable (less allowance for doubtful accounts of $139 and $134 at December 31, 2009 and June 30, 2010, respectively)		72,978			64,472
Other accounts receivable		8,216			15,622
Inventory		193,001			208,800
Energy commodity derivatives contracts		—			6,022
Energy commodity derivatives deposits		17,943			—
Reimbursable costs		13,280			10,695
Other current assets		14,382			9,978

Total current assets		323,968			350,683
Property, plant and equipment		3,398,606			3,517,178
Less: accumulated depreciation		617,989			663,595

Net property, plant and equipment		2,780,617			2,853,583
Equity investments		22,054			22,853
Long-term receivables		618			1,018
Goodwill		14,766			14,766
Other intangibles (less accumulated amortization of $9,974 and $11,009 at December 31, 2009 and June 30, 2010, respectively)		5,896			13,981
Debt placement costs (less accumulated amortization of $4,038 and $4,695 at December 31, 2009 and June 30, 2010, respectively)		10,894			10,237
Other noncurrent assets		4,335			9,837

Total assets	$	3,163,148		$	3,276,958

LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable	$	37,063		$	46,332
Accrued payroll and benefits		30,300			22,402
Accrued interest payable		32,877			30,861
Accrued taxes other than income		21,261			19,913
Environmental liabilities		11,943			11,637
Deferred revenue		27,776			28,889
Accrued product purchases		36,797			39,596
Energy commodity derivatives contracts		9,257			—
Energy commodity derivatives deposits		—			2,000
Other current liabilities		22,123			15,796

Total current liabilities		229,397			217,426
Long-term debt		1,680,004			1,779,658
Long-term pension and benefits		22,582			24,902
Other noncurrent liabilities		12,317			9,340
Environmental liabilities		22,494			18,902
Commitments and contingencies
Owners’ equity:
Partners’ capital:
Limited partner unitholders (106,588 units and 106,731 units outstanding at December 31, 2009 and June 30, 2010, respectively)		1,204,355			1,222,006
Accumulated other comprehensive loss		(8,001	)		(6,358	)

Total partners’ capital		1,196,354			1,215,648
Non-controlling owners’ interest in consolidated subsidiaries		—			11,082

Total owners’ equity		1,196,354			1,226,730

Total liabilities and owners’ equity	$	3,163,148		$	3,276,958

See notes to consolidated financial statements.

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, in thousands)


	Six Months Ended June 30,
	2009			2010
Operating Activities:
Net income	$	90,308		$	166,986
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense		46,315			52,057
Debt placement fee amortization expense		444			657
Loss (gain) on sale and retirement of assets		2,725			(1,281	)
Equity earnings		(1,458	)		(2,669	)
Distributions from equity investment		1,458			1,870
Equity-based incentive compensation expense		5,180			6,909
Amortization of prior service cost (credit) and actuarial loss		672			(21	)
Changes in operating assets and liabilities:
Trade accounts receivable and other accounts receivable		(6,762	)		9,320
Inventory		(25,391	)		(15,799	)
Energy commodity derivatives contracts, net of derivatives deposits		(7,124	)		(2,525	)
Reimbursable costs		(5,216	)		2,585
Accounts payable		(3,224	)		5,381
Accrued payroll and benefits		(988	)		(7,898	)
Accrued interest payable		(518	)		(2,016	)
Accrued taxes other than income		(1,101	)		(1,348	)
Accrued product purchases		(2,479	)		2,799
Current and noncurrent environmental liabilities		(3,604	)		(3,898	)
Other current and noncurrent assets and liabilities		1,908			2,193

Net cash provided by operating activities		91,145			213,302
Investing Activities:
Property, plant and equipment:
Additions to property, plant and equipment		(96,378	)		(97,883	)
Proceeds from sale and disposition of assets		169			5,128
Changes in accounts payable related to capital expenditures		(3,694	)		3,888
Acquisition of assets		—			(29,300	)
Acquisition-related escrow deposits		(14,800	)		—
Distributions in excess of equity investment earnings		617			—

Net cash used by investing activities		(114,086	)		(118,167	)
Financing Activities:
Distributions paid		(140,054	)		(152,626	)
Net borrowings (payments) under revolver		(70,000	)		83,400
Borrowings under long-term notes, net		298,959			—
Debt placement costs		(2,106	)		—
Net receipt from financial derivatives		—			9,565
Increase (decrease) in outstanding checks		2,490			(1,672	)
Settlement of tax withholdings on long-term incentive compensation		(3,450	)		(3,371	)
Capital contributed by non-controlling owners		—			851
Costs associated with the simplification of capital structure		(6,658	)		—
Other		—			(356	)

Net cash provided (used) by financing activities		79,181			(64,209	)

Change in cash and cash equivalents		56,240			30,926
Cash and cash equivalents at beginning of period		37,912			4,168

Cash and cash equivalents at end of period	$	94,152		$	35,094

Supplemental non-cash financing activities:
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.

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited, in thousands)


	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2010			2009			2010
Net income	$	49,138		$	102,452		$	90,308		$	166,986
Other comprehensive income:
Net loss on commodity hedges		—			—			—			(289	)
Reclassification of net gain on interest rate cash flow hedges to interest expense		(41	)		(41	)		(82	)		(82	)
Reclassification of net loss on commodity hedges to product sales revenues		—			—			—			2,035
Amortization of prior service cost (credit) and actuarial loss		687			(36	)		672			(21	)

Total other comprehensive income (loss)		646			(77	)		590			1,643

Comprehensive income		49,784			102,375			90,898			168,629
Comprehensive income (loss) attributable to non-controlling owners’ interest in consolidated subsidiaries		35,160			(68	)		64,253			(68	)

Comprehensive income attributable to partners’ capital	$	14,624		$	102,443		$	26,645		$	168,697

See notes to consolidated financial statements.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.	Organization and Basis of Presentation

Organization

Unless indicated otherwise, the terms “our,” “we,” “us” and similar language refer to Magellan Midstream Partners, L.P. together with 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 products pipeline system, the petroleum products terminals and the ammonia pipeline system. Our reportable segments offer different products and services and are managed separately because each requires different marketing strategies and business knowledge.

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

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 all of the non-controlling owners’ interests that existed at the time of the simplification were acquired.

The historical financial statements included in this report were originally those of Holdings. Although Magellan Midstream Partners, L.P. was the surviving entity for legal purposes, Holdings was the surviving entity for accounting purposes; consequently, the name of these financial statements was changed from “Magellan Midstream Holdings, L.P.” to “Magellan Midstream Partners, L.P.” The reconciliation of net income as reported prior to the simplification to the net income reported in these financial statements is as follows (in thousands):


	Three Months Ended June 30, 2009			Six Months Ended June 30, 2009
Net income, as previously reported	$	53,144		$	98,375
Depreciation expense (a)		(3,270	)		(7,107	)
Other (b)		(736	)		(960	)

Net income	$	49,138		$	90,308

(a)

Holdings acquired 54.6% of general and limited partner interests in us on June 17, 2003. At that time, Holdings recorded our property, plant and equipment at 54.6% of fair values (reflecting Holdings’ ownership percentages in us at that time) and at 45.4% of historical carrying values. As a result of this “step-up” in basis, Holdings recorded higher depreciation expense.

(b)

Other adjustments included the amortization of the step-up to fair values made by Holdings on June 17, 2003 of other items and stand-alone general and administrative (“G&A”) expenses that Holdings incurred.

Basic and diluted earnings per unit as originally reported by Holdings for the three and six months ended June 30, 2009 were $0.23 and $0.42, respectively. The difference between the original amounts and the $0.37 and $0.67, respectively, currently reported for basic and diluted earnings per unit for the three and six months ended June 30, 2009, is due to the retrospective change of the weighted average number of limited partner units outstanding used for basic and diluted net income per unit calculation as a result of the simplification.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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. Upon formation of MCO, we contributed cash of $8.7 million, of which, $6.4 million was common equity and $2.3 million was preferred equity. An unaffiliated private investment group made a cash contribution to MCO of $0.9 million as well as non-cash contributions of $10.3 million, which included $9.1 million of terminalling agreements and $1.2 million of property, plant & equipment. The fair value of the terminalling agreement was determined based on its value to an independent market participant. Initially, MCO will construct 2.0 million barrels of crude oil storage that will be leased to third parties. We estimate that our total capital contributions to MCO for this initial construction project will be approximately $38.0 million. Approximately 35% of the common equity of MCO is owned by the private investment group and approximately 65% is owned by us. All of MCO’s 8.5% cumulative preferred equity is owned by us. We evaluated MCO and determined that it is not a variable interest entity; therefore, we determined that MCO 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 was increased $11.2 million as a result of the contributions by the private investment group. The results of MCO have been included in our petroleum products terminals segment from the date of formation.

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 June 30, 2010, and the results of operations for the three and six months ended June 30, 2009 and 2010 and cash flows for the six months ended June 30, 2009 and 2010. The results of operations for the three and six months ended June 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.

2.	Owners’ Equity

The changes in owners’ equity for the six months ended June 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)		167,054			—			(68	)		166,986
Net loss on commodity hedges		—			(289	)		—			(289	)
Reclassification of net gain on interest rate cash flow hedges to interest expense		—			(82	)		—			(82	)
Reclassification of net loss on commodity hedges to product sales revenues		—			2,035			—			2,035
Amortization of prior service credit and net actuarial loss		—			(21	)		—			(21	)

Total comprehensive income		167,054			1,643			(68	)		168,629
Distributions		(152,626	)		—			—			(152,626	)
Equity method portion of equity-based incentive compensation expense		4,916			—			—			4,916
Issuance of 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		—			—			11,150			11,150
Other		(356	)		—			—			(356	)

Balance, June 30, 2010	$	1,222,006		$	(6,358	)	$	11,082		$	1,226,730

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

3.	Product Sales Revenues

The amounts reported as product sales revenues on our consolidated statements of income include revenues from the 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 petroleum products blending and fractionation activities. We also use NYMEX contracts as economic hedges against changes in the value of petroleum products associated with linefill and working inventory associated with our Houston-to-El Paso pipeline section. During the first and second quarters of 2009 and the second quarter of 2010, none of the NYMEX contracts we entered into qualified for hedge accounting treatment under Accounting Standards Codification (“ASC”) 815-30, Derivatives and Hedging. However, for the period from July 2009 through March 2010, because of other agreements that we entered into, some of the NYMEX contracts associated with our petroleum products blending activities qualified for hedge accounting treatment and were recorded as cash flow hedges. As a result of the various types of NYMEX contracts we execute, 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 cash flow hedges; and

•

Any ineffective portion of NYMEX contracts accounted for as cash flow hedges.

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


	Three Months Ended					Six Months Ended
	June 30, 2009			June 30, 2010		June 30, 2009			June 30, 2010
Physical sale of petroleum products	$	61,175		$	205,932	$	122,429		$	371,237
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		(19,848	)		10,195		(23,386	)		7,913
The effective portion of losses of matured NYMEX contracts that qualified for hedge accounting treatment associated with our petroleum products blending and fractionation activities		—			—		—			(2,035	)
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		—			13,571		—			8,919

Total NYMEX contract adjustments		(19,848	)		23,766		(23,386	)		14,797


Total product sales revenues	$	41,327		$	229,698	$	99,043		$	386,034

The increase in physical sale of petroleum products between the three and six months ended June 30, 2009 and the three and six months ended June 30, 2010 was due to the physical sale of petroleum products related to management of the linefill and working inventory associated with the Houston-to-El Paso pipeline section we acquired in July 2009.

4.	Segment Disclosures

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

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

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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.

Beginning in 2010, our East Houston, Texas terminal was transferred from our petroleum products terminals segment to our petroleum products 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 facility to provide efficient marketing to our customers. Since the beginning of 2010, this facility has been realigned under petroleum products 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. 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 June 30, 2009
	(in thousands)
	Petroleum Products Pipeline System			Petroleum Products Terminals		Ammonia Pipeline System		Intersegment Eliminations			Total
Transportation and terminals revenues	$	122,006		$	39,968	$	5,248	$	(519	)	$	166,703
Product sales revenues		37,892			3,435		—		—			41,327
Affiliate management fee revenue		190			—		—		—			190

Total revenues		160,088			43,403		5,248		(519	)		208,220
Operating expenses		43,557			15,024		3,227		(960	)		60,848
Product purchases		39,914			1,570		—		(494	)		40,990
Equity earnings		(939	)		—		—		—			(939	)

Operating margin		77,556			26,809		2,021		935			107,321
Depreciation and amortization expense		14,559			7,248		421		935			23,163
G&A expenses		14,454			5,215		579		—			20,248

Operating profit	$	48,543		$	14,346	$	1,021	$	—		$	63,910


	Three Months Ended June 30, 2010
	(in thousands)
	Petroleum Products Pipeline System			Petroleum Products Terminals		Ammonia Pipeline System			Intersegment Eliminations			Total
Transportation and terminals revenues	$	141,461		$	48,446	$	3,783		$	(517	)	$	193,173
Product sales revenues		222,963			6,763		—			(28	)		229,698
Affiliate management fee revenue		189			—		—			—			189

Total revenues		364,613			55,209		3,783			(545	)		423,060
Operating expenses		49,450			18,262		3,235			(660	)		70,287
Product purchases		182,267			1,917		—			(545	)		183,639
Equity earnings		(1,480	)		—		—			—			(1,480	)

Operating margin		134,376			35,030		548			660			170,614
Depreciation and amortization expense		16,499			8,188		368			660			25,715
G&A expenses		14,490			5,104		584			—			20,178

Operating profit (loss)	$	103,387		$	21,738	$	(404	)	$	—		$	124,721

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


	Six Months Ended June 30, 2009
	(in thousands)
	Petroleum Products Pipeline System			Petroleum Products Terminals		Ammonia Pipeline System		Intersegment Eliminations			Total
Transportation and terminals revenues	$	236,907		$	77,374	$	8,477	$	(1,035	)	$	321,723
Product sales revenues		92,124			6,919		—		—			99,043
Affiliate management fee revenue		380			—		—		—			380

Total revenues		329,411			84,293		8,477		(1,035	)		421,146
Operating expenses		86,557			30,361		6,340		(1,943	)		121,315
Product purchases		91,502			3,106		—		(988	)		93,620
Equity earnings		(1,458	)		—		—		—			(1,458	)

Operating margin		152,810			50,826		2,137		1,896			207,669
Depreciation and amortization expense		29,337			14,309		773		1,896			46,315
G&A expenses		29,791			10,394		1,199		—			41,384

Operating profit	$	93,682		$	26,123	$	165	$	—		$	119,970


	Six Months Ended June 30, 2010
	(in thousands)
	Petroleum Products Pipeline System			Petroleum Products Terminals		Ammonia Pipeline System			Intersegment Eliminations			Total
Transportation and terminals revenues	$	264,376		$	94,105	$	8,876		$	(1,015	)	$	366,342
Product sales revenues		375,189			10,873		—			(28	)		386,034
Affiliate management fee revenue		379			—		—			—			379

Total revenues		639,944			104,978		8,876			(1,043	)		752,755
Operating expenses		92,270			34,635		7,216			(1,725	)		132,396
Product purchases		313,043			4,523		—			(1,043	)		316,523
Equity earnings		(2,669	)		—		—			—			(2,669	)

Operating margin		237,300			65,820		1,660			1,725			306,505
Depreciation and amortization expense		33,360			16,247		725			1,725			52,057
G&A expenses		31,342			10,878		1,200			—			43,420

Operating profit (loss)	$	172,598		$	38,695	$	(265	)	$	—		$	211,028

5.	Inventory

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


	December 31, 2009		June 30, 2010
Refined petroleum products	$	152,776	$	139,208
Natural gas liquids		17,263		32,338
Transmix		17,230		32,395
Additives		5,732		4,859

Total inventory	$	193,001	$	208,800

Refined petroleum products and transmix inventory for the second quarter of 2010 include lower-of-cost-or-market adjustments of $5.0 million and $0.2 million, respectively. These adjustments are related to our Houston-to-El Paso pipeline section.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

6.	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 the pension plans and other postretirement benefit plan during the three and six months ended June 30, 2009 and 2010 (in thousands):


	Three Months Ended June 30, 2009						Six Months Ended June 30, 2009
	Pension Benefits			Other Post- Retirement Benefits			Pension Benefits			Other Post- Retirement Benefits
Components of Net Periodic Benefit Costs:
Service cost	$	1,902		$	116		$	3,291		$	232
Interest cost		821			278			1,605			557
Expected return on plan assets		(676	)		—			(1,362	)		—
Amortization of prior service cost (credit)		77			(212	)		154			(425	)
Amortization of actuarial loss		758			64			815			128

Net periodic benefit cost	$	2,882		$	246		$	4,503		$	492


	Three Months Ended June 30, 2010						Six Months Ended June 30, 2010
	Pension Benefits			Other Post- Retirement Benefits			Pension Benefits			Other Post- Retirement Benefits
Components of Net Periodic Benefit Costs:
Service cost	$	1,416		$	88		$	3,353		$	176
Interest cost		800			203			1,666			406
Expected return on plan assets		(920	)		—			(1,774	)		—
Amortization of prior service cost (credit)		77			(212	)		154			(425	)
Amortization of actuarial loss		99			—			250			—

Net periodic benefit cost	$	1,472		$	79		$	3,649		$	157

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.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Debt

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


	December 31, 2009		June 30, 2010		Weighted-Average Interest Rate at June 30, 2010 (1)
Revolving credit facility	$	101,600	$	185,000	0.8%
6.45% Notes due 2014		249,732		249,758	6.3%
5.65% Notes due 2016		252,897		252,682	5.7%
6.40% Notes due 2018		260,340		259,732	5.9%
6.55% Notes due 2019		566,500		583,544	4.8%
6.40% Notes due 2037		248,935		248,942	6.3%

Total debt	$	1,680,004	$	1,779,658

(1)

Weighted-average interest rate includes the impact of interest rate swaps and the amortization of discounts and premiums and gains and losses realized on various cash flow and fair value hedges (see Note 8—Derivative Financial Instruments for detailed information regarding the amortization of these items).

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 June 30, 2010, $185.0 million was 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 $2.9 million at December 31, 2009 and June 30, 2010, respectively, for the unamortized portion of a gain realized upon termination of a related interest rate swap (see Note 8—Derivative Financial Instruments).

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 $9.8 million at December 31, 2009 and June 30, 2010, respectively, for the unamortized portion of gains realized upon termination or discontinuation of hedge accounting treatment of associated interest rate swaps (see Note 8—Derivative Financial Instruments).

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 (see Note 8—Derivative Financial Instruments). 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 $16.1 million at June 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.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

8.	Derivative Financial Instruments

Commodity Derivatives

Our petroleum products blending activities generate gasoline products and we can estimate the timing and quantities of sales of these products. We use 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 June 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 $21.5 million, and we had commitments under forward sales contracts for product sales of approximately 0.2 million barrels that are being accounted for as normal sales totaling approximately $20.6 million.

In third quarter 2009, we began using NYMEX contracts as economic hedges against the changes in value of the petroleum products purchased in connection with our linefill for our Houston-to-El Paso pipeline section. Through the second quarter of 2009, none of the NYMEX contracts we entered into qualified for hedge accounting treatment under ASC 815-30, Derivatives and Hedging. However, for the period from July 2009 through March 2010, because of other agreements that we entered into, some of the NYMEX contracts associated with our petroleum products blending activities qualified for hedge accounting treatment and were recorded as cash flow hedges. None of the NYMEX contracts we used as economic hedges of the linefill of our Houston-to-El Paso pipeline section qualified for hedge accounting treatment.

At June 30, 2010, the fair value of open NYMEX contracts, representing 2.2 million barrels of petroleum products, was a net asset of $12.1 million, of which $6.0 million was recorded as energy commodity derivatives contracts and $6.1 million was recorded as noncurrent assets on our consolidated balance sheet. These open NYMEX contracts mature between July 2010 and July 2011. At June 30, 2010, we had received $2.0 million in margin cash from these agreements, 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.

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 did not receive the proceeds from the termination of the $100.0 million of swaps until July 2010; therefore, the proceeds amount of $8.2 million was recorded as other accounts receivable on our consolidated balance sheet as of June 30, 2010. We had no interest rate swaps outstanding as of June 30, 2010.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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


	Three Months Ended June 30,						Six Months Ended June 30,
Derivative Gains Included in AOCL	2009			2010			2009			2010
Beginning balance	$	3,612		$	3,448		$	3,653		$	1,743
Net loss on commodity hedges		—			—			—			(289	)
Reclassification of net gain on cash flow hedges to interest expense		(41	)		(41	)		(82	)		(82	)
Reclassification of net loss on commodity hedges to product sales revenues		—			—			—			2,035

Ending balance	$	3,571		$	3,407		$	3,571		$	3,407

As of June 30, 2010, the net gain estimated to be classified to interest expense over the next twelve months from AOCL is approximately $0.2 million.

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 June 30, 2010, and for the three and six months ended June 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 June 30, 2010		Three Months Ended June 30, 2009			Three Months Ended June 30, 2010			Six Months Ended June 30, 2009			Six Months Ended June 30, 2010
Fair value hedges (date executed):
Interest rate swaps 6.40% Notes (July 2008)	$	11,652	$	10,358	$	9,750	$	(304	)	$	(304	)	$	(608	)	$	(608	)
Interest rate swaps 5.65% Notes (October 2004)		3,830		3,093		2,866		(113	)		(113	)		(227	)		(227	)
Interest rate swaps 6.55% Notes (June and August 2009)		16,238		—		16,121		—			(117	)		—			(117	)

Total fair value hedges			$	13,451	$	28,737	$	(417	)	$	(534	)	$	(835	)	$	(952	)

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 six months ended June 30, 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 June 30, 2010		Six Months Ended June 30, 2010		Three Months Ended June 30, 2010			Six Months Ended June 30, 2010
Interest rate swap agreements	Interest expense	$	1,588	$	4,604	$	(8,636	)	$	(17,277	)

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 815-30, Derivatives and Hedging—Cash Flow Hedges, that were designated as hedging instruments on our consolidated statement of income for the three and six months ended June 30, 2009 and 2010 (in thousands):


	Three Months Ended June 30, 2009 Effective Portion
Derivative Instrument	Amount of Gain Recognized in AOCL on Derivative			Location of Gain Reclassified from AOCL into Income	Amount of Gain Reclassified from AOCL into Income
Interest rate swap agreements	$	—		Interest expense	$	41

	Three Months Ended June 30, 2010 Effective Portion
Derivative Instrument	Amount of Gain Recognized in AOCL on Derivative			Location of Gain Reclassified from AOCL into Income	Amount of Gain Reclassified from AOCL into Income
Interest rate swap agreements	$	—		Interest expense	$	41

	Six Months Ended June 30, 2009 Effective Portion
Derivative Instrument	Amount of Gain Recognized in AOCL on Derivative			Location of Gain Reclassified from AOCL into Income	Amount of Gain Reclassified from AOCL into Income
Interest rate swap agreements	$	—		Interest expense	$	82

	Six Months Ended June 30, 2010 Effective Portion
Derivative Instrument	Amount of Gain (Loss) Recognized in AOCL on Derivative			Location of Gain (Loss) Reclassified from AOCL into Income	Amount of Gain (Loss) Reclassified from AOCL into Income
Interest rate swap agreements	$	—		Interest expense	$	82
NYMEX commodity contracts		(289	)	Product sales revenues		(2,035	)

Total cash flow hedges	$	(289	)	Total	$	(1,953	)

There was no ineffectiveness recognized for any of our cash flow or fair value hedges during the three or six months ended June 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 six months ended June 30, 2009 and 2010 (in thousands):


		Amount of Gain (Loss) Recognized on Derivative
		Three Months Ended June 30,					Six Months Ended June 30,
Derivative Instrument	Location of Gain (Loss) Recognized on Derivative	2009			2010		2009			2010
Interest rate swap agreements	Other income	$	565		$	—	$	647		$	—
NYMEX commodity contracts	Product sales revenues		(19,848	)		23,766		(23,385	)		16,832

	Total	$	(19,283	)	$	23,766	$	(22,738	)	$	16,832

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

We had no fair value or cash flow hedges in effect at June 30, 2010. The following is a summary of the amounts included in our consolidated balance sheet 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 (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

The following is a summary of the amounts included in our consolidated balance sheet 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 June 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


	June 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	$	6,022	Energy commodity derivatives contracts	$	—
NYMEX commodity contracts	Other noncurrent assets		6,043	Other noncurrent liabilities		—

	Total	$	12,065	Total	$	—

9.	Commitments and Contingencies

Environmental Liabilities. Liabilities recognized for estimated environmental costs were $34.4 million and $30.5 million at December 31, 2009 and June 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 $0.9 million and $2.2 million, respectively, for the three and six months ended June 30, 2009 and $2.7 million and $5.1 million, respectively, for the three and six months ended June 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 June 30, 2010 were $4.2 million, of which $3.2 million and $1.0 million were recorded to other accounts receivable and long-term receivables, respectively, on our consolidated balance sheets.

Unrecognized Product Gains. Our petroleum products terminals operations generate product overages and shortages that result from metering inaccuracies, product evaporation or expansion, product releases and product contamination. Most of the contracts we have with our customers state that we bear the risk of loss (or gain) from these conditions. When our petroleum products terminals experience net product shortages, we recognize expense for those losses in the periods in which they occur. When our petroleum products terminals experience net product overages, we have product on hand for which we have no cost basis. Therefore, these net

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

overages are not recognized in our financial statements until the associated barrels are either sold or used to offset product losses. The net unrecognized product overages for our petroleum products terminals operations had a market value of approximately $3.1 million as of June 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.

10.

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 June 30, 2010 total 1.0 million. The compensation committee of our general partner’s board of directors administers the LTIP.

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


	Three Months Ended June 30, 2009						Six Months Ended June 30, 2009
	Equity Method		Liability Method		Total		Equity Method		Liability Method		Total
2007 awards	$	561	$	272	$	833	$	1,495	$	467	$	1,962
2008 awards		341		187		528		1,597		479		2,076
2009 awards		351		151		502		700		246		946
Retention awards		100		—		100		196		—		196

Total	$	1,353	$	610	$	1,963	$	3,988	$	1,192	$	5,180


	Three Months Ended June 30, 2010						Six Months Ended June 30, 2010
	Equity Method		Liability Method		Total		Equity Method		Liability Method		Total
2007 awards	$	—	$	—	$	—	$	—	$	6	$	6
2008 awards		462		163		625		2,925		1,269		4,194
2009 awards		350		186		536		700		460		1,160
2010 awards		453		128		581		909		258		1,167
Retention awards		208		—		208		382		—		382

Total	$	1,473	$	477	$	1,950	$	4,916	$	1,993	$	6,909

In January 2010, the cumulative amounts of the January 2007 LTIP awards were settled by issuing 140,317 limited partner units and distributing those units to the LTIP participants. The minimum tax withholdings associated with this settlement and employer taxes totaling $3.9 million were paid in January 2010.

In February 2010, the compensation committee of our general partners’ board of directors approved 241,327 unit award grants pursuant to our LTIP. These award grants have a three-year vesting period that will end on December 31, 2012.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

11.

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

Through 6/30/09		1.4200		95,074		46,956		142,030
08/14/09		0.7100		47,537		23,478		71,015
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

Through 6/30/10		1.4300		152,626		—		152,626
08/13/10 (b)		0.7325		82,393		—		82,393

Total	$	2.1625	$	235,019	$	—	$	235,019

(a) Includes amounts paid to MMP GP for its incentive distribution rights. (b) Our general partner declared this cash distribution in July 2010 to be paid on August 13, 2010 to unitholders of record at the close of business on August 6, 2010.

Distributions paid during 2009 by Holdings to its limited partners prior to its dissolution 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

Through 6/30/09		1.13518		44,980
08/14/09		0.56759		22,490

Total	$	1.70277	$	67,470

Total distributions paid were as follows (in thousands):


	Six Months Ended June 30,
	2009			2010
Cash distributions we paid	$	142,030		$	152,626
Less distributions we paid to our general partner		(46,956	)		—

Distributions we paid to outside owners		95,074			152,626
Cash distributions paid by Holdings to its outside owners		44,980			—

Total distributions	$	140,054		$	152,626

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

12.

Fair Value Disclosures

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 the balance sheet approximate fair value due to the short-term maturity or variable rates of these instruments.

Energy commodity derivatives deposits. This asset (liability) represents a short-term deposit we paid (held) associated with our energy commodity derivatives contracts. The carrying amount reported in the balance sheet approximates fair value as the deposits paid (held) 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 the balance sheet 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 June 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 each period end, in an orderly transaction with the financial institution counterparties of the interest rate derivative agreements adjusted for the effect of credit risk (see Note 8 – Derivative Financial Instruments). The exchange value was calculated using present value techniques on estimated future cash flows based on forward interest rate curves.

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


Assets (Liabilities)	December 31, 2009						June 30, 2010
Assets (Liabilities)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and cash equivalents	$	4,168		$	4,168		$	35,094		$	35,094
Energy commodity derivatives deposits		17,943			17,943			(2,000	)		(2,000	)
Long-term receivables		618			589			1,018			959
Energy commodity derivatives contracts (current)		(9,257	)		(9,257	)		6,022			6,022
Energy commodity derivatives contracts (noncurrent)		(1,146	)		(1,146	)		6,043			6,043
Debt		(1,680,004	)		(1,777,064	)		(1,779,658	)		(1,905,275	)
Interest rate swaps (current)		4,446			4,446			—			—
Interest rate swaps (noncurrent)		(1,649	)		(1,649	)		—			—

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 June 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:
Assets (Liabilities)	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 June 30, 2010 using:
Assets (Liabilities)	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)	$	6,022	$	6,022	$	—	$	—
Energy commodity derivatives contracts (noncurrent)		6,043		6,043		—		—

13.

Subsequent Events

Recognizable events

No recognizable events occurred during the period.

Non-recognizable events

On July 12, 2010, we entered into a definitive agreement to acquire an aggregate of 7.8 million barrels of crude oil storage and more than 100 miles of active petroleum pipelines from BP Pipelines (North America), Inc. (“BP”) for $289.0 million. Additionally, upon closing of the transaction, we also will acquire certain crude oil tank working inventory at fair market value, which is currently estimated to be approximately $50.0 million. A majority of the crude oil storage included in this acquisition will be leased to a third party for an intermediate period. The acquisition is expected to close in third-quarter 2010, subject to regulatory approval and other customary closing conditions.

On July 12, 2010, we received a commitment letter for a 364-day unsecured revolving credit facility in the amount of $300.0 million. The lenders’ commitment to extend loans to us under this facility will expire on August 15, 2010, with any borrowings under the facility maturing after 364 days. We intend to fund the purchase price for the acquisition from BP Pipelines (North America), Inc., in part, with borrowings under this new facility, our existing $550.0 million revolving credit facility, the equity issuance discussed below and/or future debt issuances.

On July 19, 2010, we completed a public offering of 5,750,000 of our common units at a price to the public of $46.65 per common unit. We received net proceeds of approximately $258.8 million after deducting underwriting discounts but before offering expenses payable by us. We intend to use the net proceeds from this offering to pay a portion of the $289.0 million cash purchase price for the crude oil storage assets and petroleum pipelines we have agreed to acquire from BP as described above. Pending such use, we have applied some of the net proceeds to repay the borrowings outstanding under our existing $550.0 million revolving credit facility with the balance used for general partnership purposes, including investments in interest bearing securities or accounts. Had these additional units been outstanding during the second quarter of 2010, basic and diluted earnings per limited partner unit for the three and six months ended June 30, 2010 would have been $0.91 and $1.52, respectively.

In July 2010, our general partner declared a quarterly distribution of $0.7325 per unit to be paid on August 13, 2010 to unitholders of record at the close of business on August 6, 2010. The total cash distributions to be paid are $82.4 million (see Note 11—Distributions for details).

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Introduction

We are a publicly traded limited partnership formed to own, operate and acquire a diversified portfolio of complementary energy assets. We are principally engaged in the transportation, storage and distribution of refined petroleum products. As of June 30, 2010, our three operating segments included:

•

petroleum products pipeline system, which is primarily comprised of our 9,500-mile petroleum products pipeline system, including 52 terminals;

•

petroleum products terminals, which principally includes our six marine terminal facilities, 27 inland terminals and one crude oil terminal, which is under construction; 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 products terminals segment to our petroleum products pipeline system segment due to its increasing usage as a pipeline terminal. Since the beginning of 2010, this facility has been under petroleum products 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 July 2010, the board of directors of our general partner declared a quarterly cash distribution of $0.7325 per unit for the period of April 1, 2010 through June 30, 2010. This quarterly cash distribution will be paid on August 13, 2010 to unitholders of record on August 6, 2010. Total distributions to be paid under this declaration are approximately $82.4 million.

Acquisition of Petroleum Storage and Pipelines. On July 12, 2010, we entered into a definitive agreement to acquire 7.8 million barrels of crude oil storage in Cushing, Oklahoma and more than 100 miles of active petroleum pipelines from BP Pipelines (North America), Inc. (“BP”) for $289.0 million. The acquisition includes nearly 40 miles of crude oil pipelines running between Houston and Texas City, Texas. This common carrier pipeline system is or can be connected to every major refinery within the Houston and Texas City areas. Also included with the acquisition are two 35-mile common carrier pipelines that transport refined petroleum products from the Texas City refining region to the Houston area, including connections to third-party pipelines for delivery to other end-use markets.

This acquisition will leverage our expertise in transporting and storing petroleum products by greatly expanding our crude oil logistics infrastructure and our energy footprint in the Cushing, Oklahoma and Houston, Texas markets. These 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.

The acquisition is expected to close in third quarter 2010, subject to regulatory approval and other customary closing conditions. At closing, we will also purchase from the seller certain crude oil working inventories associated with the Cushing crude oil storage assets for fair market value, which we currently estimate to be approximately $50.0 million.

On July 12, 2010, we received a commitment letter for a 364-day unsecured revolving credit facility in the amount of $300.0 million. The lenders’ commitment to extend loans to us under this facility will expire on August 15, 2010, with any borrowings under the facility maturing after 364 days. We intend to fund the purchase price for the acquisition from BP, in part, with borrowings under this new facility, our existing $550.0 million revolving credit facility, the equity issuance discussed below and/or future debt issuances.

Public Unit Offering. On July 19, 2010, we completed a public offering of 5,750,000 of our common units at a price to the public of $46.65 per common unit. We received net proceeds of approximately $258.8 million after deducting underwriting discounts but before offering expenses payable by us. We intend to use the net proceeds from such offering to pay a portion of the $289.0 million cash purchase price for the crude oil storage assets and petroleum pipelines we have agreed to acquire from BP as described above. Pending such use, we have applied some of the net proceeds to repay the borrowings outstanding under our existing $550.0 million revolving credit facility with the balance used for general partnership purposes, including investments in interest bearing securities or accounts.

Magellan Crude Oil, LLC (“MCO”). MCO was formed on May 10, 2010 with approximately 65% of its common equity owned by us and approximately 35% by private investors. We own all of MCO’s 8.5% cumulative preferred equity. Upon formation of MCO, we contributed cash of $8.7 million, of which $6.4 million was common equity and $2.3 million was preferred equity. An unaffiliated private investment group made a cash contribution of $0.9 million and non-cash contributions of $10.3 million, which included $9.1 million of terminalling agreements and $1.2 million of property, plant & equipment. MCO was formed to construct and operate crude oil storage facilities for lease to third parties. Initial construction of 2.0 million barrels of crude oil storage in Cushing, Oklahoma, which will be leased to third parties, is expected to be completed by the second quarter of 2011. MCO’s operating results will be consolidated with the operating results of our petroleum products terminals segment and the non-controlling owners’ interest in MCO will be allocated to the private investors. We expect to spend an additional $29.3 million over the next twelve months for this initial construction, bringing our total capital contribution to this project to approximately $38.0 million

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.

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


	Three Months Ended June 30,						Variance Favorable (Unfavorable)
	2009			2010			$ Change			% Change
Financial Highlights ($ in millions, except operating statistics)

Transportation and terminals revenues:
Petroleum products pipeline system	$	122.0		$	141.5		$	19.5		16
Petroleum products terminals		40.0			48.4			8.4		21
Ammonia pipeline system		5.3			3.8			(1.5	)	(28	)
Intersegment eliminations		(0.6	)		(0.6	)		—		—

Total transportation and terminals revenues		166.7			193.1			26.4		16
Affiliate management fee revenue		0.2			0.2			—		—
Operating expenses:
Petroleum products pipeline system		43.6			49.4			(5.8	)	(13	)
Petroleum products terminals		15.1			18.2			(3.1	)	(21	)
Ammonia pipeline system		3.2			3.2			—		—
Intersegment eliminations		(1.0	)		(0.6	)		(0.4	)	(40	)

Total operating expenses		60.9			70.2			(9.3	)	(15	)

Product margin:
Product sales revenues		41.3			229.6			188.3		456
Product purchases		41.0			183.6			(142.6	)	(348	)

Product margin		0.3			46.0			45.7		n/a
Equity earnings		0.9			1.5			0.6		67

Operating margin		107.2			170.6			63.4		59
Depreciation and amortization expense		23.1			25.7			(2.6	)	(11	)
G&A expense		20.2			20.2			—		—

Operating profit		63.9			124.7			60.8		95
Interest expense (net of interest income and interest capitalized)		14.7			21.7			(7.0	)	(48	)
Debt placement fee amortization expense		0.2			0.4			(0.2	)	(100	)
Other income		(0.5	)		—			(0.5	)	(100	)

Income before provision for income taxes		49.5			102.6			53.1		107
Provision for income taxes		0.4			0.1			0.3		75

Net income	$	49.1		$	102.5		$	53.4		109


Operating Statistics

Petroleum products pipeline system:
Transportation revenue per barrel shipped	$	1.202		$	1.304
Volume shipped (million barrels)		73.9			78.7
Petroleum products terminals:
Marine terminal average storage utilized (million barrels per month)		23.6			23.8
Inland terminal throughput (million barrels)		27.9			30.3
Ammonia pipeline system:
Volume shipped (thousand tons)		171			111

Transportation and terminals revenues increased by $26.4 million, resulting from:

•

an increase in petroleum products pipeline system revenues of $19.5 million primarily attributable to higher transportation revenues, higher storage lease revenues and incremental fees for terminal throughput, ethanol blending and additives. Transportation revenues increased primarily as a result of higher average tariffs due largely to mid-year 2009 tariff escalations and 7% higher transportation volumes driven by improved demand for diesel fuel;

•

an increase in petroleum products terminals revenues of $8.4 million due to higher revenues at both our marine and inland terminals. Marine revenues increased principally due to higher rates on existing storage contracts and additional marine storage. Inland revenues benefitted from higher fees for ethanol blending and higher throughput volumes; and

•

a decrease in ammonia pipeline system revenues of $1.5 million due to decreased shipments. The pipeline has been mostly unavailable since mid-May 2010 because of hydrostatic testing being conducted on the pipeline. These hydrostatic tests should continue until fall 2010.

Operating expenses increased by $9.3 million, resulting from:

•

an increase in petroleum products pipeline system expenses of $5.8 million resulting primarily from higher operating expenses related to our Houston-to-El Paso pipeline section (acquired from Longhorn Partners Pipeline, L.P. in third quarter 2009) and less favorable product overages (which reduce operating expenses).

•

an increase in petroleum products terminals expenses of $3.1 million primarily related to higher asset maintenance and personnel costs; and

•

unchanged ammonia pipeline system expenses as higher asset integrity costs from the hydrostatic testing performed during the current quarter were offset by a current quarter gain on the sale of a portion of our pipeline linefill to our customers (which reduced operating expenses).

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. Despite a $5.2 million lower-of-cost-or-market expense recognized in the current quarter associated with the Houston-to-El Paso pipeline inventory, product margin increased $45.7 million between periods due primarily to the timing of realized profits from NYMEX hedges. Product margin also increased due to higher profits from our fractionation and petroleum products blending activities and the sale of additional terminal product overages at higher prices.

Depreciation and amortization expense increased by $2.6 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.

Interest expense, net of interest income and interest capitalized, increased $7.0 million. Our average debt outstanding, excluding fair value adjustments for interest rate hedges, increased to $1.7 billion for second quarter 2010 from $1.2 billion for second 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, decreased to 5.1% in second quarter 2010 from 5.3% in 2009.

Other income for second quarter 2009 included fair-value adjustments for certain interest rate swap agreements that were settled during 2009.

Provision for income tax decreased by $0.3 million as a result of an adjustment to the 2009 franchise tax accrual made in second quarter 2010 reflecting lower revenues apportioned to the state of Texas.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2010


	Six Months Ended June 30,						Variance Favorable (Unfavorable)
	2009			2010			$ Change			% Change
Financial Highlights ($ in millions, except operating statistics)

Transportation and terminals revenues:
Petroleum products pipeline system	$	236.9		$	264.4		$	27.5		12
Petroleum products terminals		77.4			94.1			16.7		22
Ammonia pipeline system		8.5			8.9			0.4		5
Intersegment eliminations		(1.1	)		(1.1	)		—		—

Total transportation and terminals revenues		321.7			366.3			44.6		14
Affiliate management fee revenue		0.4			0.4			—		—
Operating expenses:
Petroleum products pipeline system		86.6			92.3			(5.7	)	(7	)
Petroleum products terminals		30.4			34.6			(4.2	)	(14	)
Ammonia pipeline system		6.3			7.2			(0.9	)	(14	)
Intersegment eliminations		(2.0	)		(1.7	)		(0.3	)	(15	)

Total operating expenses		121.3			132.4			(11.1	)	(9	)

Product margin:
Product sales revenues		99.0			386.0			287.0		290
Product purchases		93.6			316.5			(222.9	)	(238	)

Product margin		5.4			69.5			64.1		n/a
Equity earnings		1.4			2.7			1.3		93

Operating margin		207.6			306.5			98.9		48
Depreciation and amortization expense		46.3			52.1			(5.8	)	(13	)
G&A expense		41.3			43.4			(2.1	)	(5	)

Operating profit		120.0			211.0			91.0		76
Interest expense (net of interest income and interest capitalized)		29.1			42.6			(13.5	)	(46	)
Debt placement fee amortization expense		0.4			0.7			(0.3	)	(75	)
Other income		(0.6	)		—			(0.6	)	(100	)

Income before provision for income taxes		91.1			167.7			76.6		84
Provision for income taxes		0.8			0.7			0.1		13

Net income	$	90.3		$	167.0		$	76.7		85


Operating Statistics

Petroleum products pipeline system:
Transportation revenue per barrel shipped	$	1.174		$	1.265
Volume shipped (million barrels)		145.6			148.4
Petroleum products terminals:
Marine terminal average storage utilized (million barrels per month)		23.1			23.8
Inland terminal throughput (million barrels)		53.9			56.4
Ammonia pipeline system:
Volume shipped (thousand tons)		295			278

Transportation and terminals revenues increased by $44.6 million, resulting from:

•

an increase in petroleum products pipeline system revenues of $27.5 million primarily attributable to higher transportation revenues, higher capacity and storage lease revenues and incremental fees for ethanol blending and additives. Transportation revenues increased primarily as a result of higher average tariffs due largely to mid-year 2009 tariff escalations and an increase in diesel fuel shipments reflecting higher demand;

•

an increase in petroleum products terminals revenues of $16.7 million due to higher revenues at both our marine and inland terminals. Marine revenues increased principally due to higher rates on existing storage and leasing new storage tanks placed in service over the past year. Inland revenues benefitted from higher fees for ethanol and additive blending and higher throughput volumes; and

•

an increase in ammonia pipeline system revenues of $0.4 million. Higher shipments in first quarter 2010 (first quarter 2009 shipments were negatively impacted by operational issues at two of our customers’ plants) were largely offset by lower second quarter 2010 shipments because of hydrostatic testing being conducted on the pipeline during second quarter 2010. The year-over-year increase in revenues was due to higher terminalling fees.

Operating expenses increased by $11.1 million, resulting from:

•

an increase in petroleum products pipeline system expenses of $5.7 million resulting primarily from higher operating expenses related to our Houston-to-El Paso pipeline section (acquired from Longhorn Partners Pipeline, L.P. in third quarter 2009), partially offset by lower property taxes;

•

an increase in petroleum products terminals expenses of $4.2 million primarily related to higher asset maintenance and personnel costs; and

•

an increase in ammonia pipeline system expenses of $0.9 million due primarily to an increase in environmental costs resulting from a 2010 pipeline release. Higher asset integrity costs from the hydrostatic testing performed during the current period were largely offset by a current period gain on the sale of a portion of our pipeline linefill to our customers (which reduced operating expenses).

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. Despite a $5.2 million lower-of-cost-or-market expense recognized in the second quarter of 2010 associated with the Houston-to-El Paso pipeline inventories, product margin increased $64.1 million between periods due primarily to the timing of realized profits from our NYMEX hedges. 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 fractionation and petroleum products blending activities and the sale of additional terminal product overages at higher prices.

Depreciation and amortization expense increased by $5.8 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 $2.1 million between periods primarily due to higher equity-based incentive compensation costs.

Interest expense, net of interest income and interest capitalized, increased $13.5 million. Our average debt outstanding, excluding fair value adjustments for interest rate hedges, increased to $1.7 billion for the six months ending June 30, 2010 from $1.1 billion for the six months ending June 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 5.1% in 2010 from 5.5% in 2009.

Other income for second quarter 2009 included fair value adjustments for certain interest rate swap agreements that were settled during 2009.

Liquidity and Capital Resources

Cash Flows and Capital Expenditures

Net cash provided by operating activities was $91.1 million and $213.3 million for the six months ended June 30, 2009 and 2010, respectively. The $122.2 million increase from 2009 to 2010 was primarily attributable to:

•

an increase in net income of $76.7 million;

•

a $16.1 million increase in cash resulting from a $9.3 million decrease in trade accounts receivable and other accounts receivable in 2010 versus a $6.8 million increase in 2009 primarily due to the timing of payments received from customers;

•

a $9.6 million increase in cash resulting from a $15.8 million increase in inventory in 2010 versus a $25.4 million increase in inventory in 2009. The increase in 2009 is primarily due to additional purchases of natural gas liquids inventory used for our petroleum products blending activity to take advantage of favorable market conditions; and

•

an $8.6 million increase in cash resulting from a $5.4 million increase in accounts payable in 2010 versus a $3.2 million decrease in 2009 due primarily to the timing of invoices paid to vendors and suppliers.

Net cash used by investing activities for the six months ended June 30, 2009 and 2010 was $114.1 million and $118.2 million, respectively. During 2010, we spent $97.9 million for capital expenditures, which included $15.5 million for maintenance capital and $82.4 million for expansion capital. In addition, during 2010 we acquired petroleum products storage tanks at various locations on our petroleum products pipeline system for $29.3 million. Also, during 2010, proceeds from the sale of assets were $5.1 million, including $3.0 million of proceeds from the settlement of our insurance claim related to a tank fire at one of our petroleum products pipeline system terminals. During 2009, we spent $96.4 million for capital expenditures and $14.8 million for escrow deposits associated with acquisitions we completed during third quarter 2009. Capital expenditures in 2009 included $22.4 million for maintenance capital and $74.0 million for expansion capital.

Net cash provided (used) by financing activities for the six months ended June 30, 2009 and 2010 was $79.2 million and $(64.2) million, respectively. During 2010, we paid cash distributions of $152.6 million to our unitholders while net borrowings on our revolving credit facility, primarily to finance expansion capital projects, were $83.4 million. During 2009, borrowings under notes (net of discounts) of $299.0 million were used to repay $208.3 million of borrowings on our revolving credit facility, with the balance used for general purposes, including capital expenditures. Net borrowings on the revolver during 2009, prior to our repayment of the $208.3 million in June 2009, were $138.3 million. Additionally, we paid cash distributions of $140.1 million.

During second quarter 2010, we paid $76.8 million in cash distributions to our unitholders. Based on the declared quarterly distribution of $0.7325 per unit associated with the second quarter of 2010, we will pay $82.4 million in distributions during third 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 $329.6 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.

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 six months ended June 30, 2010, our maintenance capital spending was $15.5 million, including $0.5 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 six months of 2010, we spent $82.4 million for organic growth capital and $29.3 million to acquire petroleum products storage at various locations on our petroleum products 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 $100.0 million in future years to complete these projects.

Liquidity

As of June 30, 2010, total debt reported on our consolidated balance sheet was $1,779.7 million. The difference between this amount and the $1,735.0 million face value of our outstanding debt results from gains realized on various fair value hedges and unamortized discounts and premiums on debt issuances.

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


	December 31, 2009		June 30, 2010		Weighted-Average Interest Rate at June 30, 2010 (1)
Revolving credit facility	$	101,600	$	185,000	0.8%
6.45% Notes due 2014		249,732		249,758	6.3%
5.65% Notes due 2016		252,897		252,682	5.7%
6.40% Notes due 2018		260,340		259,732	5.9%
6.55% Notes due 2019		566,500		583,544	4.8%
6.40% Notes due 2037		248,935		248,942	6.3%

Total debt	$	1,680,004	$	1,779,658

(1)

Weighted-average interest rate includes the impact of interest rate swaps and the amortization 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.

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 (see Interest rate derivatives, below). 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 $16.1 million at June 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.

Interest Rate Derivatives

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.

Other Items

NYMEX Contracts. We began using NYMEX contracts during the third quarter of 2008 as economic hedges against changes in the future price of petroleum products. From the third quarter of 2008 through the second quarter of 2009 and during second quarter 2010, none of the NYMEX contracts we entered into qualified as hedges for accounting purposes under Accounting Standards Codification (“ASC”) 815-30, Derivatives and Hedging. For the period from July 2009 through March 2010, because of other agreements that we entered into, some of the NYMEX contracts entered into qualified for hedge accounting treatment. Currently, we have two specific groups of commodities that are being hedged with NYMEX contracts:

•

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

Since July 2009, some of the NYMEX contracts associated with future sales of petroleum products qualified for hedge accounting treatment and were recorded as cash flow hedges. The gains and losses resulting from the mark-to-market changes in value of these contracts were not included in product sales revenues in our consolidated statement of income until the petroleum products hedged were physically sold. As of June 30, 2010, we had no open NYMEX contracts of petroleum products that qualified for hedge accounting treatment. During the first quarter of 2010, we recognized $2.0 million of losses associated with derivative agreements that qualified as hedges when the hedged products were sold and the contracts were settled.

As of June 30, 2010, we had open NYMEX contracts for 0.7 million barrels of petroleum products that did not qualify for hedge accounting treatment. These contracts mature between July 2010 and October 2010. The cumulative amount of unrealized gains through June 30, 2010 associated with these agreements of $5.8 million have 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 $2.1 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:

At June 30, 2010, we had open NYMEX contracts covering 1.5 million barrels to hedge against changes in the future price of petroleum products associated with the linefill barrels. Contracts covering 0.5 million barrels mature between July 2010 and August 2010 and contracts covering 1.0 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 June 30, 2010 associated with these agreements was $6.2 million. Of the $6.2 million of cumulative gains, $7.4 million of gains was recognized during the first two quarters of 2010 and $1.2 million of losses was recognized in the last two quarters of 2009. Additionally, we recognized $1.5 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.

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 six months ended June 30, 2009 and 2010 (in millions):


2009
NYMEX losses associated with physical product sales during the six months ended June 30, 2009	$	(6.1	)
NYMEX losses associated with future physical product sales		(17.3	))

Total NYMEX losses recorded during the six months ended June 30, 2009	$	(23.4	)


2010
NYMEX gains associated with physical product sales during the six months ended June 30, 2010	$	1.6
NYMEX gains associated with future physical product sales		13.2

Total NYMEX gains recorded during the six months ended June 30, 2010	$	14.8

Ammonia Pipeline Testing. Since second quarter 2010, we have performed extensive hydrostatic testing of our ammonia pipeline system, which will continue until fall 2010. Expenditures during 2010 to complete this testing are estimated to be up to $10.0 million, which is $5.0 million higher than testing costs incurred in 2009. During certain periods of testing, the pipeline has been/will be unavailable for shipments, resulting in reduced shipment volumes. We are unable to estimate the impact this will have on our current year revenues because we expect product shipments on our ammonia pipeline by our customers before and after the testing to be higher than at historical levels.

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 current approved methodology is the annual change in the producer price index for finished goods (“PPI-FG”) plus 1.3%. The change in PPI-FG for 2009 is approximately negative 2.6%. As a result, we decreased our rates in the 40% of our markets that are subject to the FERC’s index methodology by approximately 1.3% on July 1, 2010.

Unrecognized Product Gains. Our petroleum products terminals operations generate product overages and shortages that result from metering inaccuracies, product evaporation or expansion, product releases and product contamination. Most of the contracts we have with our customers state that we bear the risk of loss (or gain) from these conditions. When our petroleum products terminals experience net product shortages, we recognize expense for those losses in the periods in which they occur. When our petroleum products terminals experience net product overages, we have product on hand for which we have no cost basis. Therefore, these net overages are not recognized in our financial statements until the associated barrels are either sold or used to offset product losses. The net unrecognized product overages for our petroleum products terminals operations had a market value of approximately $3.1 million as of June 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, 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 June 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 $21.5 million, and we had commitments under forward sales contracts for product sales of approximately 0.2 million barrels that are being accounted for as normal sales totaling approximately $20.6 million.

We use NYMEX contracts as economic hedges against changes in the price of petroleum products we expect to sell from our petroleum products blending activities and as economic hedges against the changes in value of the petroleum products associated with linefill and working inventory purchased in connection with our Houston-to-El Paso pipeline section. At June 30, 2010, none of the NYMEX contracts we used as economic hedges of the linefill of our Houston-to-El Paso pipeline section qualified for hedge accounting treatment.

At June 30, 2010, the fair value of open NYMEX contracts, representing 2.2 million barrels of petroleum products, was a net liability of $12.1 million, of which $6.0 million was recorded as energy commodity derivatives contracts and $6.1 million was recorded as noncurrent assets on our consolidated balance sheet. These open NYMEX contracts mature between July 2010 and July 2011. At June 30, 2010, we had received $2.0 million in margin cash from these agreements, 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.

Based on our open NYMEX contracts at June 30, 2010, a $1.00 per barrel increase in the price of the NYMEX contract for reformulated gasoline blendstock for oxygen blending (“RBOB”) gasoline or heating oil would result in a $2.2 million decrease in our product sales revenues and a $1.00 per barrel decrease in the price of the NYMEX contract for RBOB or heating oil would result in a $2.2 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 June 30, 2010, we had $185.0 million outstanding on our variable rate revolving credit facility. Considering the amount outstanding on our revolving credit facility as of June 30, 2010, our annual interest expense would change by $0.2 million if LIBOR were to change by 0.125%.

ITEM 4.

CONTROLS AND PROCEDURES

An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in rule 13a-14(c) of the Securities Exchange Act) was performed as of the end of the period covered by the date of this report. This evaluation was performed under the supervision and with the participation of our management, including our general partner’s Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our general partner’s Chief Executive Officer and Chief Financial Officer concluded that these disclosure controls and practices are effective in providing reasonable assurance that all required disclosures are included in the current report. Additionally, these disclosure controls and practices are effective in ensuring that information required to be disclosed is accumulated and communicated to our Chief Executive Officer and Chief Financial Officer to allow timely decisions regarding required disclosures. 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 June 30, 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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

•

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

•

changes in the financial condition of our customers;

•

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

•

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

•

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

•

changes in demand for storage in our petroleum products terminals;

•

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

•

our ability to manage interest rate and commodity price exposures;

•

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

•

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

•

weather patterns materially different than historical trends;

•

an increase in the competition our operations encounter;

•

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

•

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

•

our ability to identify 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;

•

supply disruption; and

•

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

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

PART II

OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

In June 2009, we received notice from the Department of Justice (“DOJ”) that the EPA had requested the DOJ to initiate a lawsuit alleging violations of Sections 301 and 311 of the Clean Water Act with respect to a release of petroleum product that occurred near Oologah, Oklahoma in January 2008. We settled this matter during second quarter 2010 for $0.4 million.

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

ITEM 1A.

RISK FACTORS

In addition to the information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 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 have agreed to acquire 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 have agreed to acquire 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 agreed to acquire, which could adversely affect our cash flows and our ability to pay distributions.

The crude oil storage assets that we have agreed to acquire in Cushing, Oklahoma will initially be leased solely by an affiliate of the seller of those assets, and we will be subject to substantial 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

ITEM 5.

OTHER INFORMATION

None.

ITEM 6.

EXHIBITS



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.

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.

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.DEF		XBRL Taxonomy Extension Definition Linkbase.

Exhibit 101.LAB		XBRL Taxonomy Extension Label Linkbase.

Exhibit 101.PRE		XBRL Taxonomy Extension Presentation Linkbase.

SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized in Tulsa, Oklahoma on August 3, 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)

INDEX TO EXHIBITS


EXHIBIT NUMBER		DESCRIPTION
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.

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.

12		Ratio of Earnings to Fixed Charges.

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

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

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

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

101.INS		XBRL Instance Document.

101.SCH		XBRL Taxonomy Extension Schema.

101.CAL		XBRL Taxonomy Extension Calculation Linkbase.

101.DEF		XBRL Taxonomy Extension Definition Linkbase.

101.LAB		XBRL Taxonomy Extension Label Linkbase.

101.PRE		XBRL Taxonomy Extension Presentation Linkbase.

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