Magellan Midstream Partners, L.P. - Quarter Report: 2011 March (Form 10-Q)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________________________________

FORM 10-Q



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

For the quarterly period ended March 31, 2011



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

For the transition period from to

Commission File No.: 1-16335

__________________________________________

Magellan Midstream Partners, L.P.

(Exact name of registrant as specified in its charter)



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

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

(Address of principal executive offices and zip code)

(918) 574-7000

(Registrant’s telephone number, including area code)

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

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

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

Large accelerated filer x Accelerated filer £ Non-accelerated filer £ Smaller reporting company £

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

Act). Yes £ No x

As of May 3, 2011 there were 112,736,571 outstanding limited partner units of Magellan Midstream Partners, L.P. that trade on the New York Stock Exchange under the ticker symbol "MMP."

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TABLE OF CONTENTS

PART I

FINANCIAL INFORMATION



ITEM 1.		CONSOLIDATED FINANCIAL STATEMENTS
	CONSOLIDATED STATEMENTS OF INCOME		2
	CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME		3
	CONSOLIDATED BALANCE SHEETS		4
	CONSOLIDATED STATEMENTS OF CASH FLOWS		5
	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS:
	1.	Organization and Basis of Presentation	6
	2.	Owners' Equity	6
	3.	Acquisitions	7
	4.	Product Sales Revenues	7
	5.	Segment Disclosures	8
	6.	Inventory	9
	7.	Employee Benefit Plans	9
	8.	Debt	10
	9.	Derivative Financial Instruments	11
	10.	Commitments and Contingencies	14
	11.	Long Term Incentive Plan	14
	12.	Distributions	15
	13.	Fair Value	16
	14.	Subsequent Events	17
ITEM 2.		MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Introduction		19
	Recent Developments		19
	Results of Operations		19
	Liquidity and Capital Resources		22
	Off-Balance Sheet Arrangements		25
	Environmental		25
	Other Items		25
	New Accounting Pronouncements		27
ITEM 3.		QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	28
ITEM 4.		CONTROLS AND PROCEDURES	28
Forward-Looking Statements			29
		PART II OTHER INFORMATION
ITEM 1.		LEGAL PROCEEDINGS	31
ITEM 1A.		RISK FACTORS	31
ITEM 2.		UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	31
ITEM 3.		DEFAULTS UPON SENIOR SECURITIES	31
ITEM 4.		RESERVED	31
ITEM 5.		OTHER INFORMATION	31
ITEM 6.		EXHIBITS	31

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PART I

FINANCIAL INFORMATION


ITEM 1.	CONSOLIDATED FINANCIAL STATEMENTS

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except per unit amounts)

(Unaudited)



	Three Months Ended March 31,
	2010			2011
Transportation and terminals revenues	$	173,169		$	205,408
Product sales revenues	156,336			237,296
Affiliate management fee revenue	190			193
Total revenues	329,695			442,897
Costs and expenses:
Operating	62,109			62,361
Product purchases	132,884			211,230
Depreciation and amortization	26,342			29,363
General and administrative	23,242			24,590
Total costs and expenses	244,577			327,544
Equity earnings	1,189			1,367
Operating profit	86,307			116,720
Interest expense	21,774			26,486
Interest income	(4		)	(10		)
Interest capitalized	(848		)	(671		)
Debt placement fee amortization expense	328			385
Income before provision for income taxes	65,057			90,530
Provision for income taxes	523			465
Net income	$	64,534		$	90,065
Allocation of net income (loss):
Non-controlling owners’ interest	$	—		$	(63	)
Limited partners’ interest	64,534			90,128
Net income	$	64,534		$	90,065
Basic and diluted net income per limited partner unit	$	0.60		$	0.80
Weighted average number of limited partner units outstanding used for basic and diluted net income per unit calculation	106,843			112,762

See notes to consolidated financial statements.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited, in thousands)



	Three Months Ended March 31,
	2010			2011
Net income	$	64,534		$	90,065
Other comprehensive income:
Net loss on commodity hedges	(289		)	—
Reclassification of net gain on interest rate cash flow hedges to interest expense	(41		)	(41		)
Reclassification of net loss on commodity hedges to product sales revenues	2,035			—
Amortization of prior service credit and actuarial loss	15			78
Total other comprehensive income	1,720			37
Comprehensive income	66,254			90,102
Comprehensive loss attributable to non-controlling owners’ interest in consolidated subsidiaries	—			(63		)
Comprehensive income attributable to partners’ capital	$	66,254		$	90,165

See notes to consolidated financial statements.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(In thousands)



	December 31, 2010			March 31, 2011
				(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	7,483		$	28,532
Restricted cash	14,379			—
Trade accounts receivable (less allowance for doubtful accounts of $106 and $109 at December 31, 2010 and March 31, 2011, respectively)	92,192			86,726
Other accounts receivable	6,175			20,299
Inventory	216,408			224,559
Energy commodity derivatives deposit	22,302			47,918
Reimbursable costs	13,870			7,607
Other current assets	11,774			12,637
Total current assets	384,583			428,278
Property, plant and equipment	3,894,610			3,948,782
Less: accumulated depreciation	716,054			743,174
Net property, plant and equipment	3,178,556			3,205,608
Equity investments	23,728			25,099
Long-term receivables	1,167			1,138
Goodwill	39,925			39,961
Other intangibles (less accumulated amortization of $11,964 and $12,816 at December 31, 2010 and March 31, 2011, respectively)	16,924			17,172
Debt placement costs (less accumulated amortization of $5,439 and $5,824 at December 31, 2010 and March 31, 2011, respectively)	11,871			11,486
Tank bottom inventory	57,937			65,092
Other noncurrent assets	3,209			3,003
Total assets	$	3,717,900		$	3,796,837
LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable	$	41,425		$	46,604
Accrued payroll and benefits	32,393			19,005
Accrued interest payable	35,799			31,514
Accrued taxes other than income	26,953			20,790
Environmental liabilities	12,202			13,039
Deferred revenue	34,733			35,402
Accrued product purchases	47,324			84,635
Energy commodity derivatives contracts	11,790			28,846
Other current liabilities	32,428			39,479
Total current liabilities	275,047			319,314
Long-term debt	1,906,148			1,967,599
Long-term pension and benefits	28,965			31,875
Other noncurrent liabilities	17,597			23,012
Environmental liabilities	20,572			21,767
Commitments and contingencies
Owners’ equity:
Partners’ capital:
Limited partner unitholders (112,481 units and 112,737 units outstanding at December 31, 2010 and March 31, 2011, respectively)	1,466,404			1,444,329
Accumulated other comprehensive loss	(11,096		)	(11,059		)
Total partners’ capital	1,455,308			1,433,270
Non-controlling owners’ interest in consolidated subsidiaries	14,263			—
Total owners’ equity	1,469,571			1,433,270
Total liabilities and owners’ equity	$	3,717,900		$	3,796,837

See notes to consolidated financial statements.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, in thousands)



	Three Months Ended March 31,
	2010			2011
Operating Activities:
Net income	$	64,534		$	90,065
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	26,342			29,363
Debt placement fee amortization	328			385
Loss (gain) on sale and retirement of assets	(1,617		)	1,830
Equity earnings	(1,189		)	(1,367		)
Distributions from equity investments	1,020			1,367
Equity-based incentive compensation expense	4,959			3,750
Amortization of prior service credit and net actuarial loss	15			78
Changes in operating assets and liabilities:
Restricted cash	—			14,379
Trade accounts receivable and other accounts receivable	10,014			(8,658		)
Inventory	(49,642		)	(8,151		)
Energy commodity derivatives contracts, net of derivatives deposit	1,821			(1,404		)
Reimbursable costs	1,589			6,263
Accounts payable	19,850			2,596
Accrued payroll and benefits	(13,513		)	(13,388		)
Accrued interest payable	(3,465		)	(4,285		)
Accrued taxes other than income	(2,098		)	(6,163		)
Accrued product purchases	7,253			37,311
Tank bottom inventory	—			(7,155		)
Current and noncurrent environmental liabilities	(1,582		)	2,032
Other current and noncurrent assets and liabilities	8,718			8,537
Net cash provided by operating activities	73,337			147,385
Investing Activities:
Property, plant and equipment:
Additions to property, plant and equipment	(41,553		)	(50,219		)
Proceeds from sale and disposition of assets	3,037			27
Increase (decrease) in accounts payable related to capital expenditures	(1,538		)	2,583
Acquisition of assets	—			(7,363		)
Acquisition of non-controlling owners' interests	—			(40,500		)
Other	—			(2,449		)
Net cash used by investing activities	(40,054		)	(97,921		)
Financing Activities:
Distributions paid	(75,779		)	(85,398		)
Net borrowings under revolver	50,600			62,000
Increase (decrease) in outstanding checks	(1,672		)	2,393
Settlement of tax withholdings on long-term incentive compensation	(3,371		)	(7,410		)
Other	(313		)	—
Net cash used by financing activities	(30,535		)	(28,415		)
Change in cash and cash equivalents	2,748			21,049
Cash and cash equivalents at beginning of period	4,168			7,483
Cash and cash equivalents at end of period	$	6,916		$	28,532
Supplemental non-cash financing activity:
Issuance of limited partner units in settlement of equity-based incentive plan awards	$	2,034		$	4,315

See notes to consolidated financial statements.

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.	Organization and Basis of Presentation

Organization

Unless indicated otherwise, the terms “our,” “we,” “us” and similar language refer to Magellan Midstream Partners, L.P. together with its subsidiaries. We are a Delaware limited partnership and our limited partner units are traded on the New York Stock Exchange under the ticker symbol “MMP.” Magellan GP, LLC (“MMP GP”), a wholly-owned Delaware limited liability company, serves as our general partner.

We operate and report in three business segments: the petroleum pipeline system, the petroleum terminals and the ammonia pipeline system. Our reportable segments offer different products and services and are managed separately because each requires different marketing strategies and business knowledge.

Basis of Presentation

In the opinion of management, our accompanying consolidated financial statements, which are unaudited except for the consolidated balance sheet as of December 31, 2010, which is derived from audited financial statements, include all normal and recurring adjustments necessary to present fairly our financial position as of March 31, 2011, and the results of operations for the three months ended March 31, 2010 and 2011 and cash flows for the three months ended March 31, 2010 and 2011. The results of operations for the three months ended March 31, 2011 are not necessarily indicative of the results to be expected for the full year ending December 31, 2011.

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, 2010.


2.	Owners’ Equity

The changes in owners’ equity for the three months ended March 31, 2011 are provided in the table below (dollars in thousands):



	Limited Partners’ Capital			Limited Partners’ Accumulated Other Comprehensive Loss			Non-controlling Owners’ Interest			Total Owners’ Equity
Balance, January 1, 2011	$	1,466,404		$	(11,096	)	$	14,263		$	1,469,571
Comprehensive income:
Net income (loss)	90,128			—			(63		)	90,065
Reclassification of net gain on interest rate cash flow hedges to interest expense	—			(41		)	—			(41		)
Amortization of prior service credit and net actuarial loss	—			78			—			78
Total comprehensive income (loss)	90,128			37			(63		)	90,102
Distributions	(85,398		)	—			—			(85,398		)
Equity method portion of equity-based incentive compensation expense	2,629			—			—			2,629
Issuance of 255,222 common units in settlement of long-term incentive plan awards	4,315			—			—			4,315
Settlement of tax withholdings on long-term incentive compensation	(7,410		)	—			—			(7,410		)
Acquisition of non-controlling owners' interest	(26,300		)	—			(14,200		)	(40,500		)
Other	(39		)	—			—			(39		)
Balance, March 31, 2011	$	1,444,329		$	(11,059	)	$	—		$	1,433,270

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


3.	Acquisitions

In January 2011, we acquired the remaining undivided interest in our Southlake, Texas terminal for $7.4 million. We accounted for this purchase as an acquisition of assets. The operating results of the Southlake terminal are reported in our petroleum pipeline system segment.

In February 2011, we acquired a private investment group's common equity in Magellan Crude Oil, LLC ("MCO") for $40.5 million, which represented all of the non-controlling owners' interest in subsidiaries on our consolidated balance sheet (see Note 2 - Owners' Equity). The operating results of MCO continue to be reported in our petroleum terminals segment.

In September 2010, we acquired certain assets from BP Pipelines (North America), Inc. ("BP") and accounted for this purchase as a business combination. We have not adjusted the preliminary purchase price and fair value of the assets acquired and liabilities assumed as reported in our Annual Report on Form 10-K for the year ended December 31, 2010 as we are still in the process of determining the fair value of the assets acquired and liabilities assumed. The final allocation of the purchase price will be made when that process is complete.

The following summarized pro forma consolidated income statement information assumes that the business acquired from BP referred to above occurred as of January 1, 2010. These pro forma results are for comparative purposes only and may not be indicative of the results that would have occurred had this acquisition been completed on January 1, 2010 or the results that will be attained in the future. The amounts presented below are in thousands:



	Three Months Ended
	March 31,
	2010						2011
	As Reported		Pro Forma Adjustments		Pro Forma		As Reported
Revenues	$	329,695	$	13,636	$	343,331	$	442,897
Net income	$	64,534	$	5,666	$	70,200	$	90,065

Significant pro forma adjustments include historical results of the acquired assets and our calculation of general and administrative ("G&A") costs, depreciation expense and interest expense on borrowings necessary to finance the acquisition.


4.	Product Sales Revenues

The amounts reported as product sales revenues on our consolidated statements of income include revenues from the physical sale of petroleum products and from mark-to-market adjustments from New York Mercantile Exchange (“NYMEX”) contracts. We use NYMEX contracts as economic hedges against changes in the price of petroleum products we expect to sell from our business activities where we acquire or produce petroleum products. Some of the NYMEX contracts we have entered into have qualified for hedge accounting treatment under Accounting Standards Codification ("ASC ") 815-30, Derivatives and Hedging, while others have not. See Note 8 - Derivative Financial Instruments for further disclosures regarding our NYMEX contracts.

For the three months ended March 31, 2010 and 2011, product sales revenues included the following (in thousands):

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



	Three Months Ended March 31,
	2010			2011
Physical sale of petroleum products	$	165,305		$	275,629
NYMEX contract adjustments:
Change in value of NYMEX contracts that did not qualify for hedge accounting treatment and the effective portion of gains and losses of matured NYMEX contracts that qualified for hedge accounting treatment associated with our petroleum products blending and fractionation activities⁽¹⁾	(4,317		)	(19,980		)
Change in value of NYMEX contracts that did not qualify for hedge accounting treatment associated with the Houston-to-El Paso pipeline section linefill working inventory⁽¹⁾	(4,652		)	(18,427		)
Change in value of NYMEX contracts that did not qualify for hedge accounting treatment associated with our crude oil activities	—			74
Total NYMEX contract adjustments	(8,969		)	(38,333		)
Total product sales revenues	$	156,336		$	237,296

(1) The associated petroleum products for these activities are, to the extent still owned as of the statement date, or were, to the extent no longer owned as of the statement date, classified as inventories in current assets on our consolidated balance sheets.


5.	Segment Disclosures

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

We believe that investors benefit from having access to the same financial measures used 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 by using amounts that are determined in accordance with GAAP. A reconciliation of operating margin to operating profit, which is its nearest comparable GAAP financial measure, is included in the tables. Operating profit includes expense items, such as depreciation and amortization expense and G&A expenses, that management does not consider when evaluating the core profitability of our operations.



	Three Months Ended March 31, 2010
	(in thousands)
	Petroleum Pipeline System			Petroleum Terminals		Ammonia Pipeline System		Intersegment Eliminations			Total
Transportation and terminals revenues	$	122,915		$	45,659	$	5,093	$	(498	)	$	173,169
Product sales revenues	152,226			4,110		—		—			156,336
Affiliate management fee revenue	190			—		—		—			190
Total revenues	275,331			49,769		5,093		(498		)	329,695
Operating expenses	42,820			16,373		3,981		(1,065		)	62,109
Product purchases	130,776			2,606		—		(498		)	132,884
Equity earnings	(1,189		)	—		—		—			(1,189		)
Operating margin	102,924			30,790		1,112		1,065			135,891
Depreciation and amortization expense	16,861			8,059		357		1,065			26,342
G&A expenses	16,852			5,774		616		—			23,242
Operating profit	$	69,211		$	16,957	$	139	$	—		$	86,307

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



	Three Months Ended March 31, 2011
	(in thousands)
	Petroleum Pipeline System			Petroleum Terminals		Ammonia Pipeline System		Intersegment Eliminations			Total
Transportation and terminals revenues	$	144,062		$	55,221	$	7,032	$	(907	)	$	205,408
Product sales revenues	226,988			10,418		—		(110		)	237,296
Affiliate management fee revenue	193			—		—		—			193
Total revenues	371,243			65,639		7,032		(1,017		)	442,897
Operating expenses	37,710			21,996		3,331		(676		)	62,361
Product purchases	208,473			3,774		—		(1,017		)	211,230
Equity earnings	(1,367		)	—		—		—			(1,367		)
Operating margin	126,427			39,869		3,701		676			170,673
Depreciation and amortization expense	18,552			9,771		364		676			29,363
G&A expenses	18,455			5,471		664		—			24,590
Operating profit	$	89,420		$	24,627	$	2,673	$	—		$	116,720


6.	Inventory

Inventory at December 31, 2010 and March 31, 2011 was as follows (in thousands):



	December 31, 2010		March 31, 2011
Refined petroleum products	$	146,211	$	114,026
Natural gas liquids	27,982		49,127
Transmix	32,277		43,092
Crude oil	5,008		12,398
Additives	4,930		5,916
Total inventory	$	216,408	$	224,559


7.	Employee Benefit Plans

We sponsor two union pension plans for certain employees and a pension plan primarily for salaried employees, a postretirement benefit plan for selected employees and a defined contribution plan. The following tables present our consolidated net periodic benefit costs related to these plans during the three months ended March 31, 2010 and 2011 (in thousands):



	Three Months Ended March 31, 2010						Three Months Ended March 31, 2011
	Pension Benefits			Other Post- Retirement Benefits			Pension Benefits			Other Post- Retirement Benefits
Components of net periodic benefit costs:
Service cost	$	1,937		$	88		$	1,985		$	91
Interest cost	866			203			949			259
Expected return on plan assets	(854		)	—			(1,021		)	—
Amortization of prior service cost (credit)	77			(213		)	77			(213		)
Amortization of actuarial loss	151			—			151			63
Net periodic benefit cost	$	2,177		$	78		$	2,141		$	200

Contributions estimated to be paid into the plans in 2011 are $8.1 million and $0.5 million for the pension and other

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MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

postretirement benefit plans, respectively.


8.	Debt

Consolidated debt at December 31, 2010 and March 31, 2011 was as follows (in thousands):



	December 31, 2010		March 31, 2011		Weighted-Average Interest Rate at March 31, 2011 (1)
Revolving credit facility	$	15,000	$	77,000	0.7%
6.45% Notes due 2014	249,786		249,800		6.3%
5.65% Notes due 2016	252,466		252,359		5.7%
6.40% Notes due 2018	259,125		259,479		5.6%
6.55% Notes due 2019	581,890		581,055		5.9%
4.25% Notes due 2021	298,932		298,953		4.3%
6.40% Notes due 2037	248,949		248,953		6.3%
Total debt	$	1,906,148	$	1,967,599


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

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

Revolving Credit Facility. The total borrowing capacity under the revolving credit facility, which matures in September 2012, was $550.0 million at March 31, 2011. 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 March 31, 2011, there was $77.0 million outstanding under this facility and $4.6 million was obligated for letters of credit. Amounts obligated for letters of credit are not reflected as debt on our consolidated balance sheets but do decrease our borrowing capacity under the facility.

6.45% Notes due 2014. In May 2004, we issued $250.0 million 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 as reflected on our consolidated balance sheets was increased $2.6 million and $2.5 million at December 31, 2010 and March 31, 2011, respectively, for the unamortized portion of a gain realized upon termination of a related interest rate swap.

6.40% Notes due 2018. In July 2008, we issued $250.0 million of 6.40% notes due 2018 in an underwritten public offering. In February 2011, we entered into an interest rate swap agreement to effectively convert $50.0 million of these notes to floating-rate debt (see Note 9—Derivative Financial Instruments). The outstanding principal amount of the notes as reflected on our consolidated balance sheets was increased by $0.7 million at March 31, 2011 for the fair value of the associated interest rate swap agreement. Additionally, the outstanding principal amount of the notes as reflected on our consolidated balance sheets was increased $9.1 million and $8.8 million at December 31, 2010 and March 31, 2011, respectively, for the unamortized portion of gains realized upon termination or discontinuation of hedge accounting treatment of other associated interest rate swaps.

6.55% Notes due 2019. In June and August 2009, we issued $550.0 million of 6.55% notes due 2019 in underwritten public offerings. The notes were issued at a net premium of 103.4%, or $568.7 million. The outstanding principal amount of the notes as reflected on our consolidated balance sheets was increased $15.2 million and $14.8 million at December 31, 2010 and March 31, 2011, respectively, for the unamortized portion of a gain realized upon termination of related interest rate swaps.

4.25% Notes due 2021. In August 2010, we issued $300.0 million of 4.25% notes due 2021 in an underwritten public offering. The notes were issued for the discounted price of 99.6%, or $298.9 million.

6.40% Notes due 2037. In April 2007, we issued $250.0 million of 6.40% notes due 2037 in an underwritten public

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

offering. The notes were issued for the discounted price of 99.6%, or $248.9 million.

The amounts outstanding under the revolving credit facility and notes described above are senior indebtedness.


9.	Derivative Financial Instruments

Commodity Derivatives

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

We account for the forward purchase and sales contracts we use in our blending activities as normal purchases and sales. As of March 31, 2011, 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 $22.3 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 $18.7 million.

We use NYMEX contracts as economic hedges against changes in the price of petroleum products we expect to sell in future periods. Some of the NYMEX contracts we have entered into have qualified for hedge accounting treatment under ASC 815, Derivatives and Hedging, while others have not. At March 31, 2011, we had open NYMEX contracts, representing 2.6 million barrels of petroleum products we expect to sell in the future in connection with the following business activities:


•	Petroleum products blending and fractionation - Contracts representing 1.0 million barrels of petroleum products that did not qualify as hedges for accounting purposes that mature between April and December 2011;


•	Linefill on our Houston-to-El Paso pipeline section - Contracts representing 0.8 million barrels of petroleum products that did not qualify as hedges for accounting purposes that mature between April and July 2011; and


•	Crude oil storage and pipeline


◦	Contracts associated with our crude oil tank bottom inventory for our Cushing storage facility representing 0.7 million barrels of crude oil, designated as fair value hedges for accounting purposes, that mature in November 2013.


◦	Contracts associated with our crude oil pipeline activity and linefill representing 0.1 million barrels of crude oil, designated as fair value hedges for accounting purposes, that mature between May 2011 and August 2011.

At March 31, 2011, the fair value of our open NYMEX contracts was a net liability of $40.9 million, of which $28.8 million was recorded as energy commodity derivatives contracts and $12.1 million was recorded as other noncurrent liabilities on our consolidated balance sheet. At March 31, 2011, we had made margin deposits of $47.9 million for these contracts, which were recorded as energy commodity derivatives deposits on our consolidated balance sheet. We have the right to offset the fair value of our open NYMEX contracts against our margin deposits under a master netting arrangement with our counterparty; however, we have elected to separately disclose these amounts on our consolidated balance sheet. We have netted the fair value of our NYMEX agreements together on our consolidated balance sheets.

Interest Rate Derivatives

In February 2011, we entered into a $50.0 million interest rate swap agreement to hedge against changes in the fair value of a portion of our 6.40% notes due 2018. We account for this agreement as a fair value hedge. This agreement effectively converts $50.0 million of our 6.40% fixed-rate notes to floating-rate debt. Under the terms of the agreement, we receive the 6.40% fixed rate of the notes and pay six-month LIBOR in arrears plus 2.65%. The agreement terminates in July 2018, which is the maturity date of the related notes. Payments settle in January and July each year. During each period, we record the impact of this swap based on the forward LIBOR curve. Any differences between actual LIBOR determined on the settlement date and our estimate of LIBOR will result in an adjustment to our interest expense. This interest rate derivative contains

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

credit-risk-related contingent features, which provide that, in the event we default on any material obligation or a merger in which our credit rating becomes "materially weaker," which would generally be interpreted as falling below investment grade, the counterparty to our interest rate derivative agreement could terminate the agreement and require immediate settlement. This interest rate derivative was in a net asset position as of March 31, 2011.

The changes in derivative gains included in accumulated other comprehensive loss ("AOCL") for the three months ended March 31, 2010 and 2011 were as follows (in thousands):



	Three Months Ended March 31,
Derivative Gains Included in AOCL	2010			2011
Beginning balance	$	1,743		$	3,325
Net loss on commodity hedges	(289		)	—
Reclassification of net gain on cash flow hedges to interest expense	(41		)	(41		)
Reclassification of net loss on commodity hedges to product sales revenues	2,035			—
Ending balance	$	3,448		$	3,284

As of March 31, 2011, 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, 2010 and March 31, 2011, and for the three months ended March 31, 2010 and 2011 (in thousands):



			Unamortized Amount Recorded in Long-term Debt				Amount Reclassified to Interest Expense from Long-term Debt
			As of				Three Months Ended
Hedge	Total Gain Realized		December 31, 2010		March 31, 2011		March 31, 2010			March 31, 2011
Fair value hedges (date executed):
Interest rate swaps 6.40% Notes (July 2008)	$	11,652	$	9,142	$	8,838	$	(304	)	$	(304	)
Interest rate swaps 5.65% Notes (October 2004)	3,830		2,638		2,524		(114		)	(114		)
Interest rate swaps 6.55% Notes (June and August 2009)	16,238		15,222		14,773		—			(449		)
Total fair value hedges			$	27,002	$	26,135	$	(418	)	$	(867	)



Derivative Instrument	Location of Gain Recognized on Derivative	Amount of Gain Recognized on Derivative				Amount of Interest Expense Recognized on Fixed-Rate Debt (Related Hedged Item)
		Three Months Ended				Three Months Ended
		March 31, 2010		March 31, 2011		March 31, 2010			March 31, 2011
Interest rate swap agreements	Interest expense	$	3,016	$	203	$	(8,641	)	$	(2,222	)

During first quarter 2011, we had open NYMEX contracts on 0.8 million barrels of crude oil which were designated as fair value hedges. Because there was no ineffectiveness recognized on these hedges, the unrealized losses of $13.1 million from the agreements as of March 31, 2011 were fully offset by adjustments of $12.1 million, $0.6 million and $0.4 million to tank bottom inventory, other current assets and crude oil inventory, respectively; therefore, there was no net impact on product sales revenues.

The following is a summary of the effect on our consolidated statements of income for the three months ended March 31,

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2010 and 2011 of the effective portion of derivatives accounted for under ASC 815-30, Derivatives and Hedging—Cash Flow Hedges, that were designated as hedging instruments (in thousands). See Note 4 - Product Sales Revenues for further details regarding the impact of our NYMEX agreements on product sales.



	Three Months Ended March 31, 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		$	41
NYMEX commodity contracts		(289		)	Product sales revenues		(2,035		)
Total cash flow hedges		$	(289	)			$	(1,994	)

	Three Months Ended March 31, 2011 Effective Portion
Derivative Instrument	Amount of Gain Recognized in AOCL on Derivative				Location of Gain (Loss) Reclassified from AOCL into Income	Amount of Gain Reclassified from AOCL into Income
Interest rate swap agreements		$	—		Interest expense		$	41

There was no ineffectiveness recognized for any of our cash flow or fair value hedges during the three months ended March 31, 2010 or 2011.

The following table provides a summary of the effect on our consolidated statements of income for the three months ended March 31, 2010 and 2011 of derivatives accounted for under ASC 815-10-35; Derivatives and Hedging—Overall—Subsequent Measurement, that were not designated as hedging instruments (in thousands). See Note 4 - Product Sales Revenues for further details regarding the impact of our NYMEX agreements on product sales.



		Amount of Loss Recognized on Derivative
		Three Months Ended March 31,
Derivative Instrument	Location of Loss Recognized on Derivative	2010			2011
NYMEX commodity contracts	Product sales revenues	$	(6,934	)	$	(38,333	)

The following tables provide a summary of the amounts included on our consolidated balance sheets of the fair value of derivatives accounted for under ASC 815, Derivatives and Hedging, that were designated as hedging instruments as of December 31, 2010 and March 31, 2011 (in thousands):



	December 31, 2010
	Asset Derivatives			Liability Derivatives
Derivative Instrument	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
NYMEX commodity contracts	Other noncurrent assets	$	—	Other noncurrent liabilities	$	4,920

	March 31, 2011
	Asset Derivatives			Liability Derivatives
Derivative Instrument	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Interest rate swap agreement, current portion	Other current assets	$	1,290	Other current liabilities	$	—
Interest rate swap agreement, noncurrent portion	Other noncurrent assets	—		Other noncurrent liabilities	429
NYMEX commodity contracts	Energy commodity derivatives contracts	—		Energy commodity derivatives contracts	1,034
NYMEX commodity contracts	Other noncurrent assets	—		Other noncurrent liabilities	12,076
	Total	$	1,290	Total	$	13,539

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2010 and March 31, 2011 (in thousands):



	December 31, 2010
	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	$	11,790

	March 31, 2011
	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	$	27,812


10.	Commitments and Contingencies

Environmental Liabilities. Liabilities recognized for estimated environmental costs were $32.8 million and $34.8 million at December 31, 2010 and March 31, 2011, respectively. We have classified environmental liabilities 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 $2.4 million and $3.9 million for the three months ended March 31, 2010 and 2011, respectively.

Environmental Receivables. Receivables from insurance carriers related to environmental matters at December 31, 2010 were $2.2 million, of which $1.0 million and $1.2 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 March 31, 2011 were $2.1 million, of which $1.0 million and $1.1 million were recorded to other accounts receivable and long-term receivables, respectively, on our consolidated balance sheets.

Unrecognized Product Gains. Our petroleum terminals operations generate product overages and shortages that result from metering inaccuracies and product evaporation, expansion, releases and contamination. Most of the contracts we have with our customers state that we bear the risk of loss (or gain) from these conditions. When our petroleum terminals experience net product shortages, we recognize expense for those losses in the periods in which they occur. When our petroleum terminals experience net product overages, we have product on hand for which we have no cost basis. Therefore, these net overages are not recognized in our financial statements until the associated barrels are either sold or used to offset product losses. The net unrecognized product overages for our petroleum terminals operations had a market value of approximately $5.7 million as of March 31, 2011. 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 net future product shortages.

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


11.	Long-Term Incentive Plan

We have a long-term incentive plan (“LTIP”) for certain of our employees and for directors of our general partner. The LTIP primarily consists of phantom units and, as of March 31, 2011, 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 March 31, 2011 total 0.1 million. See Note 14—Subsequent Events for discussion of the approval by our unitholders to increase the number of units available under the LTIP. The compensation committee of our general partner’s board of directors administers the LTIP.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



	Three Months Ended March 31, 2010
	Equity Method		Liability Method		Total
2007 awards	$	—	$	6	$	6
2008 awards	2,463		1,106		3,569
2009 awards	350		274		624
2010 awards	456		130		586
Retention awards	174		—		174
Total	$	3,443	$	1,516	$	4,959



	Three Months Ended March 31, 2011
	Equity Method		Liability Method		Total
2009 awards	$	927	$	622	$	1,549
2010 awards	950		354		1,304
2011 awards	562		145		707
Retention awards	190		—		190
Total	$	2,629	$	1,121	$	3,750

Effective January 31, 2011, our former chairman of the board, president and chief executive officer, Don R. Wellendorf, retired. In conjunction with Mr. Wellendorf's retirement, our general partner's board of directors engaged Mr. Wellendorf as a consultant to us for a period of twelve months beginning February 1, 2011, to assist in the transition of his duties and responsibilities on an as-needed basis and to provide other advisory and consulting services for consideration of $0.3 million and an agreement that his 2009 and 2010 phantom unit awards that were performance-based, a portion of which would otherwise have been forfeited as a result of his retirement, will not be forfeited. The payout of these awards will continue to be subject to the same financial performance metrics as originally established for 2009 and 2010 awards. The fair value of these awards on March 31, 2011 was $1.8 million, which was recognized as consulting expense in first quarter 2011.

In January 2011, the cumulative amounts of the 2008 LTIP awards were settled by issuing 252,746 limited partner units and distributing those units to the LTIP participants. The minimum tax withholdings associated with this settlement and employer taxes totaling $8.3 million were paid in January 2011.

In January 2011, the compensation committee of our general partners' board of directors approved 148,670 phantom unit awards pursuant to our LTIP. These awards have a three-year vesting period that will end on December 31, 2013.


12.	Distributions

Distributions we paid during 2010 and 2011 were as follows (in thousands, except per unit amounts):

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Payment Date	Per Unit Cash Distribution Amount			Total Cash Distribution to Limited Partners
2/12/2010		$	0.7100		$	75,779
5/14/2010		0.7200			76,847
8/13/2010		0.7325			82,393
11/12/2010		0.7450			83,798
Total		$	2.9075		$	318,817

2/14/2011		$	0.7575		$	85,398
5/13/2011(a)		0.7700			86,807
		$	1.5275		$	172,205


(a)	Our general partner's board of directors declared this cash distribution on April 27, 2011 to be paid on May 13, 2011 to unitholders of record at the close of business on May 9, 2011.


13.	Fair Value

Fair Value of Financial Instruments

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


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


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


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


•	Energy commodity derivatives contracts. These include NYMEX contracts related to petroleum products. These contracts are carried at fair value on our consolidated balance sheets and are valued based on quoted prices in active markets. See Note 9 - Derivative Financial Instruments for further disclosures regarding our NYMEX contracts.


•	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, 2010 and March 31, 2011. The carrying amount of borrowings under our revolving credit facility approximates fair value due to the variable rates of that instrument.


•	Interest rate swaps. Fair value was determined based on an assumed exchange, at the end of each period, in an orderly transaction with market participants using market observable interest rate swap curves (see Note 9 – Derivative Financial Instruments). The exchange value was calculated using present value techniques on estimated future cash flows based on forward interest rate curves.

The following table reflects the carrying amounts and fair values of our financial instruments as of December 31, 2010 and March 31, 2011 (in thousands):

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



Assets (Liabilities)	December 31, 2010						March 31, 2011
Assets (Liabilities)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and cash equivalents	$	7,483		$	7,483		$	28,532		$	28,532
Restricted cash	$	14,379		$	14,379		$	—		$	—
Energy commodity derivatives deposits	$	22,302		$	22,302		$	47,918		$	47,918
Long-term receivables	$	1,167		$	1,161		$	1,138		$	1,131
Energy commodity derivatives contracts (current)	$	(11,790	)	$	(11,790	)	$	(28,846	)	$	(28,846	)
Energy commodity derivatives contracts (noncurrent)	$	(4,920	)	$	(4,920	)	$	(12,076	)	$	(12,076	)
Debt	$	(1,906,148	)	$	(2,048,895	)	$	(1,967,599	)	$	(2,110,530	)
Interest rate swaps (current)	$	—		$	—		$	1,290		$	1,290
Interest rate swaps (noncurrent)	$	—		$	—		$	(429	)	$	(429	)

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, 2010 and March 31, 2011, based on the three levels established by ASC 820-10-50; Fair Value Measurements and Disclosures—Overall—Disclosure (in thousands):



Assets (Liabilities)				Fair Value Measurements as of December 31, 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)	$	(11,790	)	$	(11,790	)	$	—	$	—
Energy commodity derivatives contracts (noncurrent)	$	(4,920	)	$	(4,920	)	$	—	$	—



Assets (Liabilities)				Fair Value Measurements as of March 31, 2011 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)	$	(28,846	)	$	(28,846	)	$	—		$	—
Energy commodity derivatives contracts (noncurrent)	$	(12,076	)	$	(12,076	)	$	—		$	—
Interest rate swaps (current)	$	1,290		$	—		$	1,290		$	—
Interest rate swaps (noncurrent)	$	(429	)	$	—		$	(429	)	$	—


14.	Subsequent Events

Recognizable events

No recognizable events occurred during the period.

Non-recognizable events

On April 6, 2011, we entered into a $50.0 million interest rate swap to hedge against changes in the fair value of a portion of our 6.4% notes due 2018.

On April 27, 2011, at our annual meeting of limited partners, our limited partners:


•	Elected James C. Kempner, Michael N. Mears and James R. Montague to serve as Class III directors until the 2014 annual meeting of limited partners;

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


•	Approved an amendment to our LTIP that increased the total number of common units authorized to be issued from 3.2 million to 4.7 million;


•	Approved, on an advisory basis, the compensation of our named executive officers (as described in our proxy dated February 28, 2011); and


•	Approved, on an advisory basis, a proposal to hold an advisory vote by our limited partners on executive compensation annually.

On April 27, 2011, our general partner's board of directors declared a quarterly distribution of $0.77 per unit to be paid on May 13, 2011 to unitholders of record at the close of business on May 9, 2011. The total cash distributions to be paid are $86.8 million (see Note 12—Distributions for details).

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ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Introduction

We are a publicly traded limited partnership formed to own, operate and acquire a diversified portfolio of complementary energy assets. We are principally engaged in the transportation, storage and distribution of refined petroleum products, such as gasoline and diesel fuel, and crude oil. As of March 31, 2011, our three operating segments included:


•	petroleum pipeline system, comprised of approximately 9,600 miles of pipeline and 51 terminals;


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


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

The following discussion provides an analysis of the results for each of our operating segments, an overview of our liquidity and capital resources and other items related to our partnership. The following discussion and analysis should be read in conjunction with (i) our accompanying interim consolidated financial statements and related notes and (ii) our consolidated financial statements, related notes and management’s discussion and analysis of financial condition and results of operations included in our Annual Report on Form 10-K for the year ended December 31, 2010.

Recent Developments

Acquisition. In February 2011, we acquired a private investment group's common equity in Magellan Crude Oil, LLC ("MCO") for $40.5 million, which represented all of the non-controlling owners' interest in subsidiaries on our consolidated balance sheet. The operating results of MCO continue to be reported in our petroleum terminals segment.

Unitholder Elections. In April 2011, at our annual meeting of limited partners, our limited partners:


•	Elected James C. Kempner, Michael N. Mears and James R. Montague to serve as Class III directors until the 2014 annual meeting of limited partners;


•	Approved an amendment to our long-term incentive plan ("LTIP") that increased the total number of common units authorized to be issued from 3.2 million to 4.7 million;


•	Approved, on an advisory basis, the compensation of our named executive officers (as described in our proxy dated February 28, 2011); and


•	Approved, on an advisory basis, a proposal to hold an advisory vote by our limited partners on executive compensation annually.

Cash Distribution. In April 2011, the board of directors of our general partner declared a quarterly cash distribution of $0.77 per unit for the period of January 1, 2011 through March 31, 2011. This quarterly cash distribution will be paid on May 13, 2011 to unitholders of record on May 9, 2011. Total distributions to be paid under this declaration are approximately $86.8 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 table, 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 table. Operating profit includes expense items, such as depreciation and amortization expense and general and administrative (“G&A”) expenses, 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 this table. Product margin is a non-GAAP measure; however, its components of product sales and product purchases are determined in accordance with GAAP.

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Three Months Ended March 31, 2010 Compared to Three Months Ended March 31, 2011



	Three Months Ended March 31,						Variance Favorable (Unfavorable)
	2010			2011			$ Change			% Change
Financial Highlights ($ in millions, except operating statistics)
Transportation and terminals revenues:
Petroleum pipeline system	$	122.9		$	144.1		$	21.2		17
Petroleum terminals	45.7			55.2			9.5			21
Ammonia pipeline system	5.1			7.0			1.9			37
Intersegment eliminations	(0.5		)	(0.9		)	(0.4		)	(80)
Total transportation and terminals revenues	173.2			205.4			32.2			19
Affiliate management fee revenue	0.2			0.2			—			—
Operating expenses:
Petroleum pipeline system	42.9			37.7			5.2			12
Petroleum terminals	16.4			22.0			(5.6		)	(34)
Ammonia pipeline system	4.0			3.3			0.7			18
Intersegment eliminations	(1.1		)	(0.6		)	(0.5		)	(45)
Total operating expenses	62.2			62.4			(0.2		)	—
Product margin:
Product sales revenues	156.4			237.3			80.9			52
Product purchases	132.9			211.2			(78.3		)	(59)
Product margin	23.5			26.1			2.6			11
Equity earnings	1.2			1.4			0.2			17
Operating margin	135.9			170.7			34.8			26
Depreciation and amortization expense	26.4			29.4			(3.0		)	(11)
G&A expense	23.2			24.6			(1.4		)	(6)
Operating profit	86.3			116.7			30.4			35
Interest expense (net of interest income and interest capitalized)	20.9			25.8			(4.9		)	(23)
Debt placement fee amortization expense	0.3			0.4			(0.1		)	(33)
Income before provision for income taxes	65.1			90.5			25.4			39
Provision for income taxes	0.6			0.4			0.2			33
Net income	$	64.5		$	90.1		$	25.6		40
Operating Statistics:
Petroleum pipeline system:
Transportation revenue per barrel shipped	$	1.222		$	1.043
Volume shipped (million barrels):
Refined products:
Gasoline	39.3			52.4
Distillates	24.4			29.6
Aviation fuel	4.8			5.1
Liquefied petroleum gases	1.2			0.9
Crude oil	—			7.0
Total volume shipped	69.7			95.0
Petroleum terminals:
Storage terminal average utilization (million barrels per month)	23.8			30.0
Inland terminal throughput (million barrels)	26.1			27.6
Ammonia pipeline system:
Volume shipped (thousand tons)	167			221

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Transportation and terminals revenues increased by $32.2 million, resulting from:


•	an increase in petroleum pipeline system revenues of $21.2 million. The Houston, Texas-area pipeline purchase we completed in September 2010 contributed $6.8 million to revenues in the current quarter and transportation volumes of 19.3 million barrels. Excluding this acquisition:


◦	Revenues increased $14.4 million primarily attributable to higher transportation revenues (resulting from 9% higher volumes driven by improved demand for gasoline and diesel fuel), higher storage lease revenues and incremental fees for terminal throughput, ethanol blending and additives.


◦	Transportation revenue per barrel shipped increased 2% between periods, going from $1.222 per barrel to $1.241 per barrel, due to longer-haul movements on our system;

•

an increase in petroleum terminals revenues of $9.5 million, of which approximately half of this increase was contributed by the Cushing, Oklahoma terminalling assets acquired in September 2010. Excluding this acquisition, revenues increased at both our storage and inland terminals. Storage terminal revenues increased principally due to higher rates on existing storage contracts and new tank construction. Inland revenues benefited from higher fees due to ethanol blending and higher throughput volumes; and


•	an increase in ammonia pipeline system revenues of $1.9 million due to increased shipments during first quarter 2011. Our pipeline was unavailable for shipments during much of 2010 due to hydrostatic testing being performed on the pipeline, which resulted in an increase in customer movements after the testing.

Operating expenses increased by $0.2 million, resulting from:

•

a decrease in petroleum pipeline system expenses of $5.2 million. Pipeline system expenses decreased $3.6 million related to our September 2010 pipeline purchase because favorable product overages (which reduce operating expenses) more than offset other operating expenses. Excluding this reduction, petroleum pipeline expenses decreased $1.6 million due to more favorable product overages and lower asset integrity costs, partially offset by higher losses from asset replacements, higher power costs due to increased pipeline volumes and higher property taxes;


•	an increase in petroleum terminals expenses of $5.6 million, of which $1.5 million was attributable to the terminalling assets acquired in September 2010. Excluding these costs, operating expenses increased $4.1 million primarily related to higher environmental expenses, a product downgrade settlement in the 2011 period and higher maintenance expense; and


•	a decrease in ammonia pipeline system expenses of $0.7 million resulting primarily from lower environmental costs.

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 price of petroleum products we expect to sell in the future related to these activities. The period change in the mark-to-market value of these contracts that do not qualify for hedge accounting treatment plus the effective portion of the change in value of matured NYMEX contracts that qualified for hedge accounting treatment are also included in product sales revenues. Product margin increased $2.6 million between periods due primarily to higher profits from our fractionation and petroleum products blending activities, principally related to higher product prices, and the sale of more terminal product overages at higher prices, partially offset by the recognition of higher unrealized losses from NYMEX contracts.

Depreciation and amortization expense increased by $3.0 million primarily due to expansion capital projects placed into service and recent acquisitions.

G&A expense increased by $1.4 million primarily due to higher consulting costs.

Interest expense, net of interest income and interest capitalized, increased $4.9 million. Our average debt outstanding, excluding fair value adjustments for interest rate hedges, increased to $1.9 billion for first quarter 2011 from $1.7 billion for first quarter 2010 principally due to borrowings for expansion capital expenditures and acquisitions. The weighted-average interest rate on our borrowings, after giving effect to the impact of associated fair value hedges, increased to 5.5% in first quarter 2011 from 5.1% in first quarter 2010 in part due to the termination of the fixed-to-floating interest rate swaps in mid-2010. These swaps favorably impacted interest expense during first quarter 2010.

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Liquidity and Capital Resources

Distributable Cash Flow

Distributable cash flow is a non-GAAP measure that management uses to evaluate our ability to generate cash for distribution to our limited partners. Management also uses this measure as a basis for recommending to the board of directors the amount of cash distributions to be paid each period. Management believes investors benefit from having access to the same financial measures they use for these evaluations. A reconciliation of distributable cash flow for the three months ended March 31, 2010 and 2011 to net income, which is its nearest comparable GAAP financial measure, was as follows (in thousands):



	Three Months Ended March 31,
	2010			2011			Variance
Net income	$	64,534		$	90,065		$	25,531
Add:
Depreciation and amortization⁽¹⁾	26,670			29,748			3,078
Equity-based incentive compensation expense⁽²⁾	1,560			(3,660		)	(5,220		)
Asset retirements	(1,617		)	1,830			3,447
Commodity-related adjustments:
NYMEX losses recognized in the current period associated with products that will be sold in the future⁽³⁾	6,780			23,971			17,191
NYMEX losses recognized in previous periods associated with products sold in the current period⁽⁴⁾	(1,020		)	(9,606		)	(8,586		)
Lower-of-cost-or-market adjustments	63			—			(63		)
Houston-to-El Paso cost of sales adjustments⁽⁵⁾	(5,204		)	(5,844		)	(640		)
Total commodity-related adjustments	619			8,521			7,902
Less:
Maintenance capital	6,033			8,650			(2,617		)
Other	529			138			391
Distributable cash flow⁽⁶⁾	$	85,204		$	117,716		$	32,512

(1) Depreciation and amortization includes debt placement fee amortization.

(2) Because the partnership intends to satisfy vesting of units under its equity-based incentive compensation program with the issuance of limited partner units, expenses related to this program generally are deemed non-cash and added back for distributable cash flow purposes. Total equity-based incentive compensation expense for the three months ended March 31, 2010 and 2011 was $4,959 thousand and $3,750 thousand, respectively. However, the figures above include an adjustment for minimum statutory tax withholdings taxes paid by the partnership in 2010 and 2011 of $3,399 thousand and $7,410 thousand, respectively, for equity-based incentive compensation units that vested on the previous year end.

(3) Certain derivatives the partnership uses as economic hedges do not qualify for hedge accounting treatment. The partnership recognizes the change in fair value of these agreements each accounting period in its earnings, even if the hedged product has not yet been physically sold. These amounts represent the gains or losses of hedged products recognized in the partnership's earnings for product that it has not yet physically sold.

(4) When the partnership physically sells products that it has economically hedged (but did not qualify for hedge accounting treatment), it includes in its distributable cash flow calculations the full amount of the change in fair value of the associated derivative agreement.

(5) Cost of goods sold adjustment related to transitional commodity activities for our Houston-to-El Paso pipeline to more closely resemble current market prices for distributable cash flow purposes rather than average inventory costing as used to determine our results of operations.

(6) Distributable cash flow does not include fluctuations related to working capital.

Distributable cash flow increased $32.5 million. The change in net income and depreciation and amortization is discussed in detail in Results of Operations above. Cash from equity-based incentive compensation decreased primarily because the settlement of the equity-based unit awards in 2011 was higher than in 2010 and the corresponding tax withholdings we paid on those awards was higher in the current period. Asset retirements in the 2010 period included a $3.0 million insurance settlement and the gain from that settlement was excluded from our distributable cash flow. The increase in cash flows from commodity-related adjustments is primarily due to the impact of higher petroleum prices on our NYMEX contracts. A discussion of our maintenance capital expenditures is provided in Capital Requirements below.

Cash Flows and Capital Expenditures

Net cash provided by operating activities was $73.3 million and $147.4 million for the three months ended March 31,

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2010 and 2011, respectively. The $74.1 million increase from 2010 to 2011 was primarily attributable to:


•	an increase in net income of $25.5 million;


•	a $41.4 million increase resulting from lower levels of inventory purchases in 2011 as compared to 2010; specifically, a $8.2 million increase in inventory in 2011 versus a $49.6 million increase in inventory in 2010 primarily associated with our Houston-to-El Paso pipeline linefill inventory;


•	a $30.0 million increase resulting from a $37.3 million increase in accrued product purchases in 2011 versus a $7.3 million increase in accrued product purchases in 2010 primarily due to higher product prices during 2011 and the timing of invoices paid to vendors and suppliers; and


•	a $14.4 million increase due to the elimination of restricted cash resulting from our purchase of the private investment group's common equity in MCO during first quarter 2011. Prior to this, MCO's cash on hand was unavailable to us for our partnership matters and was recorded as restricted cash on our consolidated balance sheet at December 31, 2010.

These increases were partially offset by:


•	an $18.7 million decrease resulting from an $8.7 million increase in trade accounts receivable and other accounts receivable in 2011 versus a $10.0 million decrease in trade accounts receivable and other accounts receivable in 2010 primarily due to timing of payments from our customers;


•	a $17.3 million decrease resulting from a $2.6 million increase in accounts payable in 2011 versus a $19.9 million increase in 2010 primarily due to the timing of invoices paid to vendors and suppliers; and


•	a $7.2 million decrease resulting from higher-valued tank bottom inventory during 2011 related to our acquisition of terminalling assets in September 2010.

Net cash used by investing activities for the three months ended March 31, 2010 and 2011 was $40.1 million and $97.9 million, respectively. During 2011, we spent $50.2 million for capital expenditures, which included $8.7 million for maintenance capital and $41.5 million for expansion capital. Also during first quarter 2011, we acquired a private investment group's common equity in MCO for $40.5 million and spent $7.4 million to acquire the remaining undivided interest in our Southlake, Texas terminal. During 2010, we spent $41.6 million for capital expenditures, which included $6.4 million for maintenance capital and $35.2 million for expansion capital. Also during first quarter 2010, we settled our insurance claim related to a tank fire at one of our petroleum products pipeline system terminals, and we recognized proceeds of $3.0 million from that settlement.

Net cash used by financing activities for three months ended March 31, 2010 and 2011 was $30.5 million and $28.4 million, respectively. During the first quarter of 2011, we paid cash distributions of $85.4 million to our unitholders while net borrowings on our revolving credit facility, primarily to finance expansion capital projects and the MCO buyout noted above, were $62.0 million. During the first quarter of 2010, we paid cash distributions of $75.8 million to our unitholders while net borrowings on our revolving credit facility, primarily to finance expansion capital projects, were $50.6 million. The settlement of tax withholdings on LTIP awards was $3.4 million and $7.4 million during the first quarter of 2010 and 2011, respectively.

In January 2011, the cumulative amounts of the January 2008 awards were settled by issuing 252,746 limited partner units and distributing those units to the LTIP participants. Associated tax withholdings of $7.4 million and employer taxes of $0.9 million were paid in January 2011.

The quarterly distribution amount related to our first quarter 2011 financial results (to be paid in second quarter 2011) was $0.77 per unit. If we are able to meet management's targeted distribution growth of 7% for 2011 and the number of outstanding limited partner units remains at 112.7 million, total cash distributions of approximately $351.0 million will be paid to our unitholders in 2011.

Capital Requirements

Our businesses require continual investment to maintain, 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

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capital expenditures that increase storage or throughput capacity or develop pipeline connections to new supply sources.

For the three months ended March 31, 2011, our maintenance capital spending was $8.7 million. For 2011, we expect to incur maintenance capital expenditures for our existing businesses of approximately $65.0 million.

In addition to maintenance capital expenditures, we also incur expansion capital expenditures at our existing facilities. During the first three months of 2011, we spent $41.5 million for organic growth capital, $7.4 million to acquire the remaining undivided interest in our Southlake, Texas terminal and $40.5 million to acquire the remaining interest in MCO. Based on the progress of expansion projects already underway, we expect to spend approximately $225.0 million for expansion capital during 2011, including acquisitions, with an additional $30.0 million in future years to complete these projects.

Liquidity

Consolidated debt at December 31, 2010 and March 31, 2011 was as follows (in thousands):



	December 31, 2010		March 31, 2011		Weighted-Average Interest Rate at March 31, 2011⁽¹⁾
Revolving credit facility	$	15,000	$	77,000	0.7%
6.45% Notes due 2014	249,786		249,800		6.3%
5.65% Notes due 2016	252,466		252,359		5.7%
6.40% Notes due 2018	259,125		259,479		5.6%
6.55% Notes due 2019	581,890		581,055		5.9%
4.25% Notes due 2021	298,932		298,953		4.3%
6.40% Notes due 2037	248,949		248,953		6.3%
Total debt	$	1,906,148	$	1,967,599


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

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

6.45% Notes due 2014. In May 2004, we issued $250.0 million 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.

6.40% Notes due 2018. In July 2008, we issued $250.0 million of 6.40% notes due 2018 in an underwritten public offering. In February 2011, we entered into an interest rate swap agreement to effectively convert $50.0 million of these notes to floating-rate debt. The outstanding principal amount of the notes as reflected on our consolidated balance sheets was increased by $0.7 million at March 31, 2011 for the fair value of the associated interest rate swap agreement. Additionally, the outstanding principal amount of the notes as reflected on our consolidated balance sheets was increased $9.1 million and $8.8 million at December 31, 2010 and March 31, 2011, respectively, for the unamortized portion of gains realized upon termination or discontinuation of hedge accounting treatment of other associated interest rate swaps.

6.55% Notes due 2019. In June and August 2009, we issued $550.0 million of 6.55% notes due 2019 in underwritten

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public offerings. The notes were issued at a net premium of 103.4%, or $568.7 million. The outstanding principal amount of the notes as reflected on our consolidated balance sheets was increased $15.2 million and $14.8 million at December 31, 2010 and March 31, 2011, respectively, for the unamortized portion of a gain realized upon termination of related interest rate swaps.

4.25% Notes due 2021. In August 2010, we issued $300.0 million of 4.25% notes due 2021 in an underwritten public offering. The notes were issued for the discounted price of 99.6%, or $298.9 million.

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 amounts outstanding under 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 use NYMEX contracts as economic hedges against changes in the price of petroleum products we expect to sell from our business activities where we acquire or produce petroleum products. Some of the NYMEX contracts we entered into qualify as hedges for accounting purposes under Accounting Standards Codification (“ASC”) 815-30, Derivatives and Hedging, while others have not. Currently, we have three specific groups of commodities that are being hedged with NYMEX contracts:


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

◦

As of March 31, 2011, we had open NYMEX contracts for 1.0 million barrels of petroleum products that did not qualify for hedge accounting treatment. We recognize the period change in fair value of these agreements in our consolidated income statement. These contracts mature between April and December 2011. The cumulative amount of unrealized losses through March 31, 2011 associated with these agreements, which are related to products we expected to sell in the future, was $9.6 million. We recorded this amount as a decrease in product sales revenues on our consolidated statements of income and as energy commodity derivatives contracts on our consolidated balance sheet. Of the $9.6 million of unrealized losses, $9.2 million was recognized in first quarter 2011 and $0.4 million was recognized in fourth quarter 2010. Additionally, we recognized losses of $9.0 million on NYMEX contracts that settled during 2011 related to physical product sales during first quarter 2011. Furthermore, we realized losses of $1.8 million on NYMEX contracts that settled during 2011 but were rolled to other hedges that are associated with products we expect to sell in the future, of which $1.5 million was recognized during first quarter 2011 and $0.3 million was recognized during fourth quarter 2010.


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

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◦

At March 31, 2011, we had open NYMEX contracts covering 0.8 million barrels to hedge against changes in the price of petroleum products associated with the linefill barrels we expect to sell in future periods. These contracts mature between April and July 2011. Because these NYMEX contracts did 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 losses through March 31, 2011 associated with these agreements was $18.2 million, of which $12.5 million of losses were recognized during 2011 and $5.7 million of losses were recognized during 2010 and 2009. Additionally, we recognized $5.9 million of losses associated with the linefill NYMEX contracts that were settled during 2011, related to physical product sales during first quarter 2011, that were recorded as a decrease in product sales revenues on our consolidated income statement. The linefill and working inventory associated with our Houston-to-El Paso pipeline section are classified as inventory in current assets on our consolidated balance sheets.


•	Future commodity sales of linefill, tank bottom inventory and product overages associated with our crude pipeline and storage activities:

◦

At March 31, 2011, we had open NYMEX contracts covering less than 0.1 million barrels to hedge against future price changes of linefill in a crude pipeline connected to our Cushing, Oklahoma terminal. These contracts qualified for and were designated as fair value hedges and mature in August 2011. The unrealized losses of $0.6 million from these agreements during the year were fully offset by an adjustment to other current assets and, therefore, there was no impact on product sales revenues. The linefill for our crude pipeline connected to our Cushing terminal is classified as an other current asset on our consolidated balance sheets. Prior to entering into the fair value hedges above, we had open NYMEX contracts hedging less than 0.1 million barrels of linefill in a crude pipeline connected to our Cushing, Oklahoma terminal that did not qualify for hedge accounting treatment. As a result, we recognized $0.1 million of gains during 2011 associated with these agreements, which were recorded as an increase in product sales revenues on our consolidated income statement.

◦

At March 31, 2011, we had open NYMEX contracts covering 0.7 million barrels to hedge future price changes on tank bottom inventory. These contracts qualified for and were designated as fair value hedges and mature in November 2013. The cumulative unrealized losses of $12.1 million from these agreements as of March 31, 2011 were fully offset by an adjustment to the tank bottom inventory and, therefore, there was no impact on product sales revenues. The tank bottom inventory at our Cushing terminal is separately classified as a long-term asset on our consolidated balance sheets.

◦

At March 31, 2011, we had open NYMEX contracts covering 0.1 million barrels to hedge against future price changes of product overages related to our crude pipeline activities. These contracts qualified for and were designated as fair value hedges and mature in May 2011 and July 2011. The unrealized losses of $0.4 million from these agreements during the year were fully offset by an adjustment to inventory and, therefore, there was no impact on product sales revenues. The product overages related to our crude pipeline activities are classified as inventory on our consolidated balance sheets. Realized gains and losses associated with these agreements will be recorded as adjustments to operating expenses.

The following table provides a summary of the mark-to-market gains and losses associated with NYMEX contracts and the accounting periods in which the gains and losses were recognized in our consolidated statements of income for the periods ended March 31, 2010 and 2011 (in millions):

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2010
NYMEX losses recorded in first quarter 2010 that were associated with physical product sales during first quarter 2010	$	(2.2	)
NYMEX losses recorded in first quarter 2010 that were associated with future physical product sales	(6.8		)
Total NYMEX losses which impacted product sales revenues during first quarter 2010	$	(9.0	)

2011
NYMEX losses recorded in first quarter 2011 that were associated with physical product sales during first quarter 2011	$	(14.9	)
NYMEX losses recorded in first quarter 2011 that were associated with future physical product sales	(23.4		)
Total NYMEX losses which impacted product sales revenues during first quarter 2011	$	(38.3	)

Pipeline Tariff Increase. The Federal Energy Regulatory Commission ("FERC") regulates the rates charged on interstate common carrier pipeline operations primarily through an index methodology, which establishes the maximum amount by which tariffs can be adjusted each year. 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 FERC-approved methodology used for the last five-year period was the annual change in the producer price index for finished goods (“PPI-FG”) plus 1.3%. In December 2010, FERC approved the indexing methodology to be used for the five-year period beginning in July 2011 equal to the change in PPI-FG plus 2.65%. Certain shippers have requested a rehearing of this matter by the FERC, and the FERC issued an order in February 2011 granting rehearing for the limited purpose of further consideration in the five-year index review. At this time, management is unable to determine what outcome might result. Assuming the currently-approved methodology is not changed, based on preliminary estimates of PPI-FG for 2010, we anticipate increasing virtually all of our tariff rates by up to 7% on July 1, 2011.

New Accounting Pronouncements

There were no new accounting standards that we adopted during the three months ended March 31, 2011, or that would be adopted in the future periods, with any material financial statement impact.

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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 manage product purchases and sales. Derivatives that qualify for and are designated as normal purchases and sales are accounted for using traditional accrual accounting. As of March 31, 2011, 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 $22.3 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 $18.7 million.

At March 31, 2011, we had open NYMEX contracts used as economic hedges against changes in the price of petroleum products we expect to sell in the future. Some of the NYMEX contracts we have entered into have qualified for hedge accounting treatment under ASC 815-30, Derivatives and Hedging, while others have not.

At March 31, 2011, the fair value of open NYMEX contracts, representing 2.6 million barrels of petroleum products, was a net liability of $40.9 million, of which $28.8 million was recorded as energy commodity derivatives contracts and $12.1 million was recorded as other noncurrent liabilities on our consolidated balance sheet. These open NYMEX contracts mature between April 2011 and November 2013. At March 31, 2011, we had made margin deposits of $47.9 million for these contracts, which was recorded as energy commodity derivatives deposits on our consolidated balance sheet. We have the right to offset the fair value of our open NYMEX contracts against our margin deposits under a master netting arrangement with our counterpart; however, we have elected to separately disclose these amounts on our consolidated balance sheet.

At March 31, 2011, open NYMEX contracts representing 1.8 million barrels of petroleum products did not qualify for hedge accounting treatment. A $1.00 per barrel increase in the price of these NYMEX contracts for reformulated gasoline blendstock for oxygen blending (“RBOB”) gasoline or heating oil would result in a $1.8 million decrease in our product sales revenues and a $1.00 per barrel decrease in the price of these NYMEX contracts for RBOB or heating oil would result in a $1.8 million increase in our product sales revenues. However, the cumulative increases or decreases in product sales revenues we recognize from our open NYMEX contracts will be substantially offset by higher or lower product sales revenues when the physical sale of the product occurs. These contracts may be for the purchase or sale of product in markets different from those in which we are attempting to hedge our exposure, resulting in hedges that do not eliminate all price risks.

Interest Rate Risk

As of March 31, 2011, we had $77.0 million outstanding on our variable rate revolving credit facility. Considering the amount outstanding on our revolving credit facility as of March 31, 2011, our annual interest expense would change by $0.1 million if LIBOR were to change by 0.125%.


ITEM 4.	CONTROLS AND PROCEDURES

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

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quarter ended March31, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. On September 1, 2010, we completed an acquisition of a business from BP Pipelines (North America), Inc. As permitted by the Securities and Exchange Commission, management has elected to exclude this acquisition from its assessment of the effectiveness of our internal control over financial reporting as of March 31, 2011. This acquired business represented approximately 10% of consolidated total assets and approximately 3% of consolidated total revenues as of and for the three months ended March 31, 2011, respectively.

Forward-Looking Statements

Certain matters discussed in this Quarterly Report on Form 10-Q include forward-looking statements that discuss our expected future results based on current and pending business operations. Forward-looking statements can be identified by words such as “anticipates,” “believes,” “expects,” “estimates,” “forecasts,” “projects,” “should” and other similar expressions. Although we believe our forward-looking statements are based on reasonable assumptions, statements made regarding future results are not guarantees of future performance and subject to numerous assumptions, uncertainties and risks that are difficult to predict. Therefore, actual outcomes and results may be materially different from the results stated or implied in such forward-looking statements included in this report.

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


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


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


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


•	changes in the financial condition of our customers, vendors, derivatives counterparties or lenders;


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


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


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


•	changes in demand for storage in our petroleum terminals and along our petroleum pipeline system;


•	changes in supply patterns for our storage terminals;


•	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 or more aggressive enforcement or increased assessments under existing forms of 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 that govern the product quality specifications that could impact our ability to produce gasoline volumes through our blending activities or that could require significant capital outlays for compliance;


•	changes in laws and regulations to which we are or could become subject, including tax withholding issues, safety, employment and environmental laws and regulations, including laws and regulations designed to address climate change;


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


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


•	the effect of changes in accounting policies;


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


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

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•	supply disruption; and


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

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

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PART II

OTHER INFORMATION


ITEM 1.	LEGAL PROCEEDINGS

We are a party to various claims, legal actions and complaints arising in the ordinary course of business. While the results cannot be predicted with certainty, management believes 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, 2010, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K are not our only risks. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.


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

None.


ITEM 3.	DEFAULTS UPON SENIOR SECURITIES

None.


ITEM 4.	RESERVED


ITEM 5.	OTHER INFORMATION

None.


ITEM 6.	EXHIBITS



Exhibit Number		Description

Exhibit 10	—	Separation and Consulting Agreement dated January 26, 2011 between Magellan Midstream Holdings, GP, LLC and Don Wellendorf.

Exhibit 12	—	Ratio of earnings to fixed charges.

Exhibit 31.1	—	Certification of Michael N. Mears, principal executive officer.

Exhibit 31.2	—	Certification of John D. Chandler, principal financial officer.

Exhibit 32.1	—	Section 1350 Certification of Michael N. Mears, 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.

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SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized in Tulsa, Oklahoma on May 4, 2011.



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)

Table of Contents

INDEX TO EXHIBITS



EXHIBIT NUMBER		DESCRIPTION

Exhibit 10	—	Separation and Consulting Agreement dated January 26, 2011 between Magellan Midstream Holdings, GP, LLC and Don Wellendorf.

Exhibit 12	—	Ratio of earnings to fixed charges.

Exhibit 31.1	—	Certification of Michael N. Mears, principal executive officer.

Exhibit 31.2	—	Certification of John D. Chandler, principal financial officer.

Exhibit 32.1	—	Section 1350 Certification of Michael N. Mears, 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.