Magellan Midstream Partners, L.P. - FORM 10-Q

Attached files

file	filename
EX-12 - RATIO OF EARNINGS TO FIXED CHARGES - Magellan Midstream Partners, L.P.	dex12.htm
EX-31.1 - RULE 13A-14(A)/15D-14(A) CERTIFICATION OF THE PEO - Magellan Midstream Partners, L.P.	dex311.htm
EX-32.1 - SECTION 1350 CERTIFICATION OF THE CEO - Magellan Midstream Partners, L.P.	dex321.htm
EX-32.2 - SECTION 1350 CERTIFICATION OF THE CFO - Magellan Midstream Partners, L.P.	dex322.htm
EX-31.2 - RULE 13A-14(A)/15D-14(A) CERTIFICATION OF THE PFO - Magellan Midstream Partners, L.P.	dex312.htm

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, 2010

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

For the transition period from to

Commission File No.: 1-16335

Magellan Midstream Partners, L.P.

(Exact name of registrant as specified in its charter)

Delaware

73-1599053

(State or other jurisdiction of

incorporation or organization)

(IRS Employer

Identification No.)

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

(Address of principal executive offices and zip code)

(918) 574-7000

(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ 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, 2010, there were 106,731,349 outstanding limited partner units of Magellan Midstream Partners, L.P. that trade on the New York Stock Exchange under the ticker symbol “MMP.”

TABLE OF CONTENTS

PART I

FINANCIAL INFORMATION


ITEM 1.		FINANCIAL STATEMENTS
CONSOLIDATED STATEMENTS OF INCOME			2
CONSOLIDATED BALANCE SHEETS			3
CONSOLIDATED STATEMENTS OF CASH FLOWS			4
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME			5
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
	1.	Organization and Basis of Presentation	6
	2.	Product Sales Revenues	7
	3.	Segment Disclosures	8
	4.	Inventory	9
	5.	Employee Benefit Plans	9
	6.	Debt	10
	7.	Derivative Financial Instruments	11
	8.	Commitments and Contingencies	13
	9.	Long-Term Incentive Plan	14
	10.	Distributions	15
	11.	Fair Value Disclosures	16
	12.	Subsequent Events	17
ITEM 2.		MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Results of Operations			18
Liquidity and Capital Resources			20
Other Items			23
New Accounting Pronouncements			25
ITEM 3.		QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	26
ITEM 4.		CONTROLS AND PROCEDURES	27
Forward-Looking Statements			28

PART II
OTHER INFORMATION

ITEM 1.		LEGAL PROCEEDINGS	30
ITEM 1A.		RISK FACTORS	30
ITEM 2.		UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	30
ITEM 3.		DEFAULTS UPON SENIOR SECURITIES	30
ITEM 4.		RESERVED	30
ITEM 5.		OTHER INFORMATION	30
ITEM 6.		EXHIBITS	30

PART I

FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except per unit amounts)

(Unaudited)


	Three Months Ended March 31,
	2009			2010
Transportation and terminals revenues	$	155,020		$	173,169
Product sales revenues		57,716			156,336
Affiliate management fee revenue		190			190

Total revenues		212,926			329,695
Costs and expenses:
Operating		60,467			62,109
Product purchases		52,630			132,884
Depreciation and amortization		23,152			26,342
General and administrative		21,136			23,242

Total costs and expenses		157,385			244,577
Equity earnings		519			1,189

Operating profit		56,060			86,307
Interest expense		15,552			21,774
Interest income		(221	)		(4	)
Interest capitalized		(936	)		(848	)
Debt placement fee amortization		220			328
Other income		(82	)		—

Income before provision for income taxes		41,527			65,057
Provision for income taxes		357			523

Net income	$	41,170		$	64,534

Allocation of net income:
Noncontrolling owners’ interests	$	29,148		$	—
Limited partners’ interest		12,022			64,534

Net income	$	41,170		$	64,534


Basic and diluted net income per limited partner unit	$	0.30		$	0.60


Weighted average number of limited partner units outstanding used for basic and diluted net income per unit calculation		39,637			106,843

See notes to consolidated financial statements.

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(In thousands)


	December 31, 2009			March 31, 2010
				(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	4,168		$	6,916
Accounts receivable (less allowance for doubtful accounts of $139 and $134 at December 31, 2009 and March 31, 2010, respectively)		72,978			64,162
Other accounts receivable		8,216			7,018
Inventory		193,001			242,643
Energy commodity derivatives deposit		17,943			19,871
Reimbursable costs		13,280			11,691
Other current assets		14,382			17,451

Total current assets		323,968			369,752
Property, plant and equipment		3,398,606			3,437,316
Less: accumulated depreciation		617,989			642,526

Net property, plant and equipment		2,780,617			2,794,790
Equity investments		22,054			22,223
Long-term receivables		618			569
Goodwill		14,766			14,766
Other intangibles (less accumulated amortization of $9,974 and $10,491 at December 31, 2009 and March 31, 2010, respectively)		5,896			5,379
Debt placement costs (less accumulated amortization of $4,038 and $4,366 at December 31, 2009 and March 31, 2010, respectively)		10,894			10,566
Other noncurrent assets		4,335			4,115

Total assets	$	3,163,148		$	3,222,160

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	37,063		$	55,375
Accrued payroll and benefits		30,300			16,787
Accrued interest payable		32,877			29,412
Accrued taxes other than income		21,261			19,163
Environmental liabilities		11,943			11,728
Deferred revenue		27,776			28,739
Accrued product purchases		36,797			44,050
Energy commodity derivatives contracts		9,257			12,924
Other current liabilities		22,123			21,111

Total current liabilities		229,397			239,289
Long-term debt		1,680,004			1,734,109
Long-term pension and benefits		22,582			25,353
Other noncurrent liabilities		12,317			13,684
Environmental liabilities		22,494			21,127
Commitments and contingencies
Partners’ capital:
Limited partner unitholders (106,588 units and 106,731 units outstanding at December 31, 2009 and March 31, 2010, respectively)		1,204,355			1,194,879
Accumulated other comprehensive loss		(8,001	)		(6,281	)

Total partners’ capital		1,196,354			1,188,598

Total liabilities and partners’ capital	$	3,163,148		$	3,222,160

See notes to consolidated financial statements.

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, in thousands)


	Three Months Ended March 31,
	2009			2010
Operating Activities:
Net income	$	41,170		$	64,534
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense		23,152			26,342
Debt placement fee amortization		220			328
Loss (gain) on sale and retirement of assets		1,253			(1,617	)
Equity earnings		(519	)		(1,189	)
Distributions from equity investment		519			1,020
Equity-based incentive compensation expense		3,217			4,959
Amortization of prior service cost (credit) and actuarial loss		(15	)		15
Changes in operating assets and liabilities:
Accounts receivable and other accounts receivable		(5,925	)		10,014
Inventory		(18,091	)		(49,642	)
Energy commodity derivative contracts, net of derivative deposits		(5,211	)		1,821
Reimbursable costs		(3,591	)		1,589
Accounts payable		3,245			19,850
Accrued payroll and benefits		(6,001	)		(13,513	)
Accrued interest payable		6,786			(3,465	)
Accrued taxes other than income		(1,703	)		(2,098	)
Accrued product purchases		16,355			7,253
Current and noncurrent environmental liabilities		(2,524	)		(1,582	)
Other current and noncurrent assets and liabilities		7,368			8,718

Net cash provided by operating activities		59,705			73,337

Investing Activities:
Property, plant and equipment:
Additions to property, plant and equipment		(47,585	)		(41,553	)
Proceeds from sale and disposition of assets		—			3,037
Changes in accounts payable related to capital expenditures		(301	)		(1,538	)
Distributions in excess of equity investment earnings		1,031			—

Net cash used by investing activities		(46,855	)		(40,054	)
Financing Activities:
Distributions paid		(70,027	)		(75,779	)
Net borrowings under revolver		42,000			50,600
Increase (decrease) in outstanding checks		2,490			(1,672	)
Settlement of tax withholdings on long-term incentive compensation		(3,450	)		(3,371	)
Costs associated with the simplification of capital structure		(5,345	)		—
Other		—			(313	)

Net cash used by financing activities		(34,332	)		(30,535	)

Change in cash and cash equivalents		(21,482	)		2,748
Cash and cash equivalents at beginning of period		37,912			4,168

Cash and cash equivalents at end of period	$	16,430		$	6,916

Supplemental non-cash financing activity:
Issuance of limited partner units in settlement of long-term incentive plan awards	$	1,943		$	2,034

See notes to consolidated financial statements.

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited, in thousands)


	Three Months Ended March 31,
	2009			2010
Net income	$	41,170		$	64,534
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 cost (credit) and actuarial loss		(15	)		15

Total other comprehensive income (loss)		(56	)		1,720

Comprehensive income		41,114			66,254
Comprehensive income attributable to non-controlling owners’ interest in consolidated subsidiaries		(29,093	)		—

Comprehensive income attributable to partners’ capital	$	12,021		$	66,254

See notes to consolidated financial statements.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.	Organization and Basis of Presentation

Organization

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

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

Basis of Presentation

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

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


	Three Months Ended March 31, 2009
Net income, as previously reported	$	45,231
Depreciation expense (a)		(3,837	)
Other (b)		(224	)

Net income	$	41,170

(a)

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

(b)

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

Basic and diluted earnings per unit as originally reported for the three months ended March 31, 2009 was $0.19. The difference between this amount and the $0.30 currently reported for basic and diluted earnings per unit for that period is due to the retrospective restatement of the weighted average number of limited partner units outstanding used for basic and diluted net income per unit calculation as a result of the simplification.

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

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Pursuant to the rules and regulations of the Securities and Exchange Commission, the financial statements in this report do not include all of the information and notes normally included with financial statements prepared in accordance with accounting principles generally accepted in the United States. These financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2009.

2.	Product Sales Revenues

The amounts reported as product sales revenues on our consolidated statements of income include revenues from the sale of petroleum products and from mark-to-market adjustments from New York Mercantile Exchange (“NYMEX”) contracts. We use NYMEX contracts as economic hedges against changes in the price of petroleum products we expect to sell from our petroleum products blending and fractionation activities. During the first quarter of 2009, none of the NYMEX contracts we entered into qualified for hedge accounting treatment under Accounting Standards Codification (“ASC”) 815-30, Derivatives and Hedging. However, beginning in July 2009, because of other agreements that we entered into, some of the NYMEX contracts associated with our petroleum products blending activities qualified for hedge accounting treatment and were recorded as cash flow hedges. We also use NYMEX contracts as economic hedges against changes in the value of petroleum products associated with linefill and working inventory associated with our Houston-to-El Paso, Texas pipeline section (the pipeline we acquired from Longhorn Partners Pipeline, L.P. in July 2009), none of which have qualified for hedge accounting treatment. As a result of the various types of NYMEX contracts we execute, the amounts reported as product sales revenues can include amounts from the following sources:

•

The physical sale of petroleum products;

•

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

•

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

•

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

For the three months ended March 31, 2009 and 2010, product sales revenues included the following (in thousands):


	Three Months Ended
	March 31, 2009			March 31, 2010
Physical sale of petroleum products	$	61,254		$	165,305
NYMEX contract adjustments:
Change in value of NYMEX contracts that did not qualify for hedge accounting treatment associated with our petroleum products blending and fractionation activities		(3,538	)		(2,282	)
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		—			(2,035	)
Change in value of NYMEX contracts that did not qualify for hedge accounting treatment associated with the Houston-to-El Paso pipeline section linefill and working inventory		—			(4,652	)

Total NYMEX contract adjustments		(3,538	)		(8,969	)


Total product sales revenues	$	57,716		$	156,336

The increase in physical sale of petroleum products between the three months ended March 31, 2009 and the three months ended March 31, 2010 was due to the physical sale of petroleum products related to management of the linefill and working inventory associated with the Houston-to-El Paso pipeline section we acquired in July 2009.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

3.	Segment Disclosures

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

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

Beginning in 2010, our East Houston, Texas terminal was transferred from our petroleum products terminals segment to our petroleum products pipeline system segment. The East Houston terminal is an origin for our pipeline system and has been increasingly utilized as a pipeline terminal. For instance, we are building a connection between the East Houston terminal and our recently-acquired Houston-to-El Paso pipeline section to serve as an origin for that pipeline. Further, we are in the final stages of constructing a pipeline connection from our East Houston terminal to a third-party pipeline near Houston to allow us to transport petroleum products from the Port Arthur, Texas refinery region into our pipeline markets. We are commercially managing the East Houston terminal as a pipeline facility to provide seamless marketing to our customers so they no longer must work with different segments to do business at the East Houston facility. Since the beginning of 2010, this facility has been realigned under petroleum products pipeline management and its operating results have been reported both internally and externally as part of that segment. As a result, historical financial results for our segments have been adjusted to conform to the current period’s presentation. The historical adjustments to revenues and expenses were not material and consolidated operating profit did not change as a result of this reclassification. The net book value of the asset transferred was approximately $79.0 million.


	Three Months Ended March 31, 2009
	(in thousands)
	Petroleum Products Pipeline System			Petroleum Products Terminals		Ammonia Pipeline System			Intersegment Eliminations			Total
Transportation and terminals revenues	$	114,901		$	37,406	$	3,229		$	(516	)	$	155,020
Product sales revenues		54,232			3,484		—			—			57,716
Affiliate management fee revenue		190			—		—			—			190

Total revenues		169,323			40,890		3,229			(516	)		212,926
Operating expenses		43,000			15,337		3,113			(983	)		60,467
Product purchases		51,588			1,536		—			(494	)		52,630
Equity earnings		(519	)		—		—			—			(519	)

Operating margin		75,254			24,017		116			961			100,348
Depreciation and amortization expense		14,778			7,061		352			961			23,152
G&A expenses		15,337			5,179		620			—			21,136

Operating profit (loss)	$	45,139		$	11,777	$	(856	)	$	—		$	56,060

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


	Three Months Ended March 31, 2010
	(in thousands)
	Petroleum Products Pipeline System			Petroleum Products 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

4.	Inventory

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


	December 31, 2009		March 31, 2010
Refined petroleum products	$	152,776	$	186,682
Natural gas liquids		17,263		18,197
Transmix		17,230		31,981
Additives		5,732		5,783

Total inventory	$	193,001	$	242,643

5.	Employee Benefit Plans

We sponsor two union pension plans for certain employees and a pension plan primarily for salaried employees, a postretirement benefit plan for selected employees and a defined contribution plan. The following tables present our consolidated net periodic benefit costs related to the pension plans and other postretirement benefit plan during the three months ended March 31, 2009 and 2010 (in thousands):


	Three Months Ended March 31, 2009						Three Months Ended March 31, 2010
	Pension Benefits			Other Post- Retirement Benefits			Pension Benefits			Other Post- Retirement Benefits
Components of net periodic benefit costs:
Service cost	$	1,389		$	116		$	1,937		$	88
Interest cost		784			279			866			203
Expected return on plan assets		(686	)		—			(854	)		—
Amortization of prior service cost (credit)		77			(213	)		77			(213	)
Amortization of net actuarial loss		57			64			151			—

Net periodic benefit cost	$	1,621		$	246		$	2,177		$	78

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Debt

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


	December 31, 2009		March 31, 2010		Weighted-Average Interest Rate at March 31, 2010 (1)
Revolving credit facility	$	101,600	$	152,200	0.6%
6.45% Notes due 2014		249,732		249,745	6.3%
5.65% Notes due 2016		252,897		252,789	5.7%
6.40% Notes due 2018		260,340		260,036	5.9%
6.55% Notes due 2019		566,500		570,401	4.6%
6.40% Notes due 2037		248,935		248,938	6.3%

Total debt	$	1,680,004	$	1,734,109

(1)

Weighted-average interest rate includes the impact of interest rate swaps and the amortization of discounts and gains and losses realized on various cash flow hedges (see Note 7—Derivative Financial Instruments for detailed information regarding the amortization of these gains and losses).

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

Revolving Credit Facility. The total borrowing capacity under the revolving credit facility, which matures in September 2012, is $550.0 million. Borrowings under the facility are unsecured and bear interest at LIBOR plus a spread ranging from 0.3% to 0.8% based on our credit ratings and amounts outstanding under the facility. Additionally, a commitment fee is assessed at a rate from 0.05% to 0.125%, depending on our credit ratings. Borrowings under this facility are used for general purposes, including capital expenditures. As of March 31, 2010, $152.2 million was outstanding under this facility and $4.4 million was obligated for letters of credit. Amounts obligated for letters of credit are not reflected as debt on our consolidated balance sheets.

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

5.65% Notes due 2016. In October 2004, we issued $250.0 million of 5.65% notes due 2016 in an underwritten public offering. The notes were issued for the discounted price of 99.9%, or $249.7 million. The outstanding principal amount of the notes was increased by $3.1 million and $3.0 million at December 31, 2009 and March 31, 2010, respectively, for the unamortized portion of a gain realized upon termination of a related interest rate swap (see Note 7—Derivative Financial Instruments).

6.40% Notes due 2018. In July 2008, we issued $250.0 million of 6.40% notes due 2018 in an underwritten public offering. The outstanding principal amount of the notes was increased by $10.4 million and $10.1 million at December 31, 2009 and March 31, 2010, respectively, for the unamortized portion of gains realized upon termination or discontinuation of hedge accounting treatment of associated interest rate swaps (see Note 7—Derivative Financial Instruments).

6.55% Notes due 2019. In June and August 2009, we issued $550.0 million of 6.55% notes due 2019 in underwritten public offerings. The notes were issued at a net premium of 103.4%, or $568.7 million. In connection with these offerings, we entered into interest rate swap agreements to effectively convert $250.0 million of these notes to floating-rate debt (see Note 7—Derivative Financial Instruments). The outstanding principal amount of the notes was increased (decreased) by $(1.6) million and $2.6 million at December 31, 2009 and March 31, 2010, respectively, for the fair value less accrued interest of the associated interest rate swap agreements.

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

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

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

7.	Derivative Financial Instruments

Commodity Derivatives

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

As discussed in Note 2—Product Sales Revenues, we use NYMEX contracts as economic hedges against changes in the price of petroleum products we expect to sell from our petroleum products blending activities. In third quarter 2009, we began using NYMEX contracts as economic hedges against the changes in value of the linefill petroleum products purchased in connection with our Houston-to-El Paso pipeline section. Through the second quarter of 2009, none of the NYMEX contracts we entered into qualified for hedge accounting treatment under ASC 815-30, Derivatives and Hedging. However, beginning in July 2009, because of other agreements that we entered into, some of the NYMEX contracts associated with our petroleum products blending activities qualified for hedge accounting treatment and have been recorded as cash flow hedges. None of the NYMEX contracts we used as economic hedges of the linefill of our Houston-to-El Paso pipeline section qualified for hedge accounting treatment.

At March 31, 2010, the fair value of open NYMEX contracts, representing 2.4 million barrels of petroleum products, was a net liability of $14.1 million, of which $12.9 million was recorded as energy commodity derivatives contracts and $1.2 million was recorded as noncurrent liabilities on our consolidated balance sheet. These open NYMEX contracts mature between April 2010 and July 2011. At March 31, 2010, we had made margin deposits of $19.9 million for these contracts, which were recorded as an energy commodity derivatives deposit on our consolidated balance sheet. We have the right to offset the fair value of our open NYMEX contracts against our margin deposits under a master netting arrangement with our counterpart; however, we have elected to separately disclose these amounts on our consolidated balance sheet.

Interest Rate Derivatives

In June and August 2009, we entered into $150.0 million and $100.0 million, respectively, of interest rate swap agreements to hedge against changes in the fair value of a portion of the $550.0 million of 6.55% notes due 2019. We account for these agreements as fair value hedges. These agreements effectively convert $250.0 million of our 6.55% fixed-rate notes to floating-rate debt. Under the terms of the agreements, we receive the 6.55% fixed rate of the notes and pay six-month LIBOR in arrears plus 2.18% for the $150.0 million swaps and 2.34% for the other $100.0 million. The agreements terminate in June 2019, 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 these swaps 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. These interest rate derivatives contain credit-risk-related contingent features. These contingent features provide that in the event of our default on any obligation of $25.0 million or more or a merger in which our credit rating becomes “materially weaker,” which would generally be interpreted as falling below investment grade, the counterparties to our interest rate derivatives agreements could terminate those agreements and require immediate settlement. None of our interest rate derivatives were in a net liability position as of March 31, 2010.

The changes in derivative gains included in accumulated other comprehensive loss (“AOCL”) for the three months ended March 31, 2009 and 2010 were as follows (in thousands):


	Three Months Ended March 31,
Derivative Gains Included in AOCL	2009			2010
Beginning balance	$	3,653		$	1,743
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	$	3,612		$	3,448

As of March 31, 2010, the net gain estimated to be classified to interest expense over the next twelve months from AOCL is approximately $0.2 million.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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


			Unamortized Amount Recorded in Long-term Debt				Amount Reclassified to Interest Expense from Long-term Debt
Hedge	Total Gain Realized		As of December 31, 2009		As of March 31, 2010		Three Months Ended March 31, 2009			Three Months Ended March 31, 2010
Fair value hedges (date executed):
Interest rate swaps 6.40% Notes (July 2008)	$	11,652	$	10,358	$	10,054	$	(304	)	$	(304	)
Interest rate swaps 5.65% Notes (October 2004)		3,830		3,093		2,979		(114	)		(114	)

Total fair value hedges			$	13,451	$	13,033	$	(418	)	$	(418	)

The following is a summary of the effect of derivatives accounted for under ASC 815-25, Derivatives and Hedging—Fair Value Hedges, that were designated as hedging instruments on our consolidated statement of income for the three months ended March 31, 2010 (in thousands):

Derivative Instrument

Location of Gain

Recognized on Derivative

Amount of Gain
Recognized on
Derivative

Amount of Interest
Expense Recognized on
Fixed-Rate Debt (Related
Hedged Item)

Interest rate swap agreements

Interest expense

3,016

(8,641

)

The following is a summary of the effect of derivatives accounted for under ASC 815-30, Derivatives and Hedging—Cash Flow Hedges, that were designated as hedging instruments on our consolidated statement of income for the three months ended March 31, 2009 and 2010 (in thousands):


	Three Months Ended March 31, 2009 Effective Portion
Derivative Instrument	Amount of Gain Recognized in AOCL on Derivative			Location of Gain Reclassified from AOCL into Income	Amount of Gain Reclassified from AOCL into Income
Interest rate swap agreements	$	—		Interest expense	$	41

	Three Months Ended 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	)	Total	$	(1,994	)

There was no ineffectiveness recognized on the financial instruments disclosed in the above tables during the three months ended March 31, 2009 or 2010.

The following is a summary of the effect of derivatives accounted for under ASC 815-10-35; Paragraph 2, Derivatives and Hedging—Overall—Subsequent Measurement, that were not designated as hedging instruments on our consolidated statement of income for the three months ended March 31, 2009 and 2010 (in thousands):


		Amount of Gain (Loss) Recognized on Derivative
Derivative Instrument	Location of Gain (Loss) Recognized on Derivative	Three Months Ended March 31, 2009			Three Months Ended March 31, 2010
Interest rate swap agreements	Other income	$	82		$	—
NYMEX commodity contracts	Product sales revenues		(3,538	)		(6,934	)

	Total	$	(3,456	)	$	(6,934	)

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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


	December 31, 2009
	Asset Derivatives			Liability Derivatives
Derivative Instrument	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Interest rate swap agreements, current portion	Other current assets	$	4,446	Other current liabilities	$	—
Interest rate swap agreements, noncurrent portion	Other noncurrent assets		—	Other noncurrent liabilities		1,649
NYMEX commodity contracts	Energy commodity derivatives contracts		—	Energy commodity derivatives contracts		1,211

	Total	$	4,446	Total	$	2,860


	March 31, 2010
	Asset Derivatives			Liability Derivatives
Derivative Instrument	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Interest rate swap agreements, current portion	Other current assets	$	8,243	Other current liabilities	$	—
Interest rate swap agreements, noncurrent portion	Other noncurrent assets		—	Other noncurrent liabilities		3,882

	Total	$	8,243	Total	$	3,882

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


	December 31, 2009
	Asset Derivatives			Liability Derivatives
Derivative Instrument	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
NYMEX commodity contracts	Energy commodity derivatives contracts	$	—	Energy commodity derivatives contracts	$	8,046
NYMEX commodity contracts	Other noncurrent assets		—	Other noncurrent liabilities		1,146

	Total	$	—	Total	$	9,192


	March 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	$	12,924
NYMEX commodity contracts	Other noncurrent assets		—	Other noncurrent liabilities		1,228

	Total	$	—	Total	$	14,152

8.	Commitments and Contingencies

Environmental Liabilities. Liabilities recognized for estimated environmental costs were $34.4 million and $32.9 million at December 31, 2009 and March 31, 2010, respectively. Environmental liabilities have been classified as current or noncurrent based on management’s estimates regarding the timing of actual payments. Management estimates that expenditures associated with these environmental liabilities will be paid over the next 10 years. Environmental expenses recognized as a result of changes in our environmental liabilities are included in operating expenses on our consolidated statements of income. Environmental expense was $1.3 million and $2.4 million for the three months ended March 31, 2009 and 2010, respectively.

Unrecognized Contingent Liability: Clean Air Act. Section 185 of the Clean Air Act (“CAA 185”) requires each state to assess fees against major stationary emission sources in “severe” or “extreme” non-attainment areas. During 2009, the Texas Commission on Environmental Quality (“TCEQ”), in response to an Environmental Protection Agency (“EPA”) request, issued proposed rules which, if adopted as proposed, may result in fees assessed against our Galena Park, Texas terminal for the 2008 and 2009 calendar years of up to $8.1 million and $4.8 million, respectively.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Based on the monitoring data for the Houston/Galveston/Brazoria, Texas area prepared by the TCEQ, which indicates that the area obtained the ozone standard for past three consecutive years, the TCEQ is pursuing a Termination Determination from the EPA, which, if approved by the EPA, would terminate any requirements by the TCEQ to pursue actions under CAA 185. However, an environmental group has submitted a petition in Federal Court challenging the Termination Determination process. We believe we will not be assessed penalties under CAA 185 and at March 31, 2010 we had no amounts accrued for this matter.

Environmental Receivables. Receivables from insurance carriers related to environmental matters were $3.9 million at both December 31, 2009 and March 31, 2010.

Unrecognized Product Gains. Our petroleum products terminals operations generate product overages and shortages that result from metering inaccuracies, product evaporation or expansion, product releases and product contamination. Most of the contracts we have with our customers state that we bear the risk of loss (or gain) from these conditions. When our petroleum products terminals experience net product shortages, we recognize expense for those losses in the periods in which they occur. When our petroleum products terminals experience net product overages, we have product on hand for which we have no cost basis. Therefore, these net overages are not recognized in our financial statements until the associated barrels are either sold or used to offset product losses. The net unrecognized product overages for our petroleum products terminals operations had a market value of approximately $7.0 million as of March 31, 2010. However, the actual amounts we will recognize in future periods will depend on product prices at the time the associated barrels are either sold or used to offset future product losses.

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

9.	Long-Term Incentive Plan

We have a long-term incentive plan (“LTIP”) for certain of our employees and for directors of our general partner. The LTIP primarily consists of phantom units and permits the grant of awards covering an aggregate of 3.2 million of our limited partner units. The remaining units available under the LTIP at March 31, 2010 total 1.0 million. The compensation committee of our general partner’s board of directors administers the LTIP.

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


	Three Months Ended
	March 31, 2009						March 31, 2010
	Equity Method		Liability Method		Total		Equity Method		Liability Method		Total
2007 awards	$	934	$	195	$	1,129	$	—	$	6	$	6
2008 awards		1,256		292		1,548		2,463		1,106		3,569
2009 awards		349		95		444		350		274		624
2010 awards		—		—		—		456		130		586
Retention awards		96		—		96		174		—		174

Total	$	2,635	$	582	$	3,217	$	3,443	$	1,516	$	4,959

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

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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

10.

Distributions

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


Payment Date	Per Unit Cash Distribution Amount		Limited Partner Units		General Partner (a)		Total Cash Distribution
02/13/09	$	0.71	$	47,537	$	23,478	$	71,015
05/15/09		0.71		47,537		23,478		71,015
08/14/09		0.71		47,537		23,478		71,015
11/13/09		0.71		75,677		—		75,677

Total	$	2.84	$	218,288	$	70,434	$	288,722

02/12/10	$	0.71	$	75,779	$	—	$	75,779
05/14/10 (b)		0.72		76,847		—		76,847

Total	$	1.43	$	152,626	$	—	$	152,626

(a) Includes amounts paid to MMP GP for its incentive distribution rights. (b) Our general partner declared this cash distribution in April 2010 to be paid on May 14, 2010 to unitholders of record at the close of business on May 7, 2010

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


Payment Date	Per Unit Cash Distribution Amount		Total Cash Distribution
02/13/09	$	0.56759	$	22,490
05/15/09		0.56759		22,490
08/14/09		0.56759		22,490

Total	$	1.70277	$	67,470

Total distributions paid were as follows (in thousands):


	Three Months Ended March 31,
	2009			2010
Cash distributions we paid	$	71,015		$	75,779
Less distributions we paid to our general partner		(23,478	)		—

Distributions we paid to outside owners		47,537			75,779
Cash distributions paid by Holdings to its outside owners		22,490			—

Total distributions	$	70,027		$	75,779

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

11.

Fair Value Disclosures

Fair Value of Financial Instruments

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

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

Energy commodity derivatives deposit. This asset represents a short-term deposit we paid associated with our energy commodity derivatives contracts. The carrying amount reported in the balance sheet 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. The carrying amounts reported in the balance sheet represent fair value of the liability (see Note 7—Derivative Financial Instruments).

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

Interest rate swaps. Fair value was determined based on an assumed exchange, at each period end, in an orderly transaction with the financial institution counterparties of the interest rate derivative agreements (see Note 7 – Derivative Financial Instruments). The exchange value is calculated using present value techniques on estimated future cash flows based on forward interest rate curves.

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


Assets (Liabilities)	December 31, 2009						March 31, 2010
Assets (Liabilities)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and cash equivalents	$	4,168		$	4,168		$	6,916		$	6,916
Energy commodity derivatives contracts (current)		(9,257	)		(9,257	)		(12,924	)		(12,924	)
Energy commodity derivatives contracts (noncurrent)		(1,146	)		(1,146	)		(1,228	)		(1,228	)
Long-term receivables		618			589			569			548
Energy commodity derivatives deposit		17,943			17,943			19,871			19,871
Debt		(1,680,004	)		(1,777,064	)		(1,734,109	)		(1,836,825	)
Interest rate swaps (current)		4,446			4,446			8,243			8,243
Interest rate swaps (noncurrent)		(1,649	)		(1,649	)		(3,882	)		(3,882	)

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Fair Value Measurements

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


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


Assets (Liabilities)				Asset Fair Value Measurements as of March 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)	$	(12,924	)	$	(12,924	)	$	—		$	—
Energy commodity derivatives contracts (noncurrent)		(1,228	)		(1,228	)		—			—
Interest rate swaps (current)		8,243			—			8,243			—
Interest rate swaps (noncurrent)		(3,882	)		—			(3,882	)		—

12.

Subsequent Events

Recognizable events

No recognizable events occurred during the period.

Non-recognizable events

In April 2010, our general partner declared a quarterly distribution of $0.72 per unit to be paid on May 14, 2010, to unitholders of record at the close of business on May 7, 2010. The total cash distributions to be paid are $76.8 million (see Note 10—Distributions for details).

ITEM 2.

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

Introduction

We are a publicly traded limited partnership formed to own, operate and acquire a diversified portfolio of complementary energy assets. We are principally engaged in the transportation, storage and distribution of refined petroleum products. As of March 31, 2010, our three operating segments included:

•

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

•

petroleum products terminals, which principally includes our six marine terminal facilities and 27 inland terminals; and

•

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

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

The following discussion provides an analysis of the results for each of our operating segments, an overview of our liquidity and capital resources and other items related to our partnership. The following discussion and analysis should be read in conjunction with (i) our accompanying interim consolidated financial statements and related notes and (ii) our consolidated financial statements, related notes and management’s discussion and analysis of financial condition and results of operations included in our Annual Report on Form 10-K for the year ended December 31, 2009.

Recent Developments

Cash Distribution. During April 2010, the board of directors of our general partner declared a quarterly cash distribution of $0.72 per unit for the period of January 1, 2010 through March 31, 2010. This quarterly cash distribution will be paid on May 14, 2010 to unitholders of record on May 7, 2010. Total distributions to be paid under this declaration are approximately $76.8 million.

Health Care Reform. On March 23, 2010, the Patient Protection and Affordable Care Act was enacted and on March 30, 2010, a companion bill, the Health Care and Education Reconciliation Act of 2010 was also enacted (collectively, the “Health Care Acts”). The initial impact of the Health Care Acts for most entities will be that the employers which receive the Medicare Part D subsidy will recognize the deferred tax effects of the reduced deductibility of the postretirement prescription drug coverage in the period the Health Care Acts were enacted. Because our postretirement benefit plans do not receive this Medicare Part D subsidy, we will be unaffected by this provision of the Health Care Acts.

As with any significant government action, the other provisions of the Health Care Acts are still being assessed, and we expect that government agencies, such as the Departments of the Treasury, Health and Human Services and Labor will provide additional regulations or interpretations of certain provisions of the Health Care Acts in the future. These additional regulations, interpretations or other guidance may provide clarification of certain aspects of the Health Care Acts. We will evaluate this guidance when it is received to determine whether it results in a significant event for our plans.

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”) costs, which management does not consider when evaluating the core profitability of our operations. Additionally, product margin, which management primarily uses to evaluate the profitability of our commodity-related activities, is provided in this table. Product margin is a non-GAAP measure; however, its components of product sales and product purchases are determined in accordance with GAAP.

Three Months Ended March 31, 2009 Compared to Three Months Ended March 31, 2010


	Three Months Ended March 31,						Variance Favorable (Unfavorable)
	2009			2010			$ Change			% Change
Financial Highlights ($ in millions, except operating statistics)

Transportation and terminals revenues:
Petroleum products pipeline system	$	114.9		$	122.9		$	8.0		7
Petroleum products terminals		37.4			45.7			8.3		22
Ammonia pipeline system		3.2			5.1			1.9		59
Intersegment eliminations		(0.5	)		(0.5	)		—		—

Total transportation and terminals revenues		155.0			173.2			18.2		12
Affiliate management fee revenue		0.2			0.2			—		—
Operating expenses:
Petroleum products pipeline system		43.0			42.9			0.1		—
Petroleum products terminals		15.3			16.4			(1.1	)	(7	)
Ammonia pipeline system		3.1			4.0			(0.9	)	(29	)
Intersegment eliminations		(1.0	)		(1.1	)		0.1		10

Total operating expenses		60.4			62.2			(1.8	)	(3	)

Product margin:
Product sales		57.7			156.4			98.7		171
Product purchases		52.6			132.9			(80.3	)	(153	)

Product margin		5.1			23.5			18.4		361
Equity earnings		0.5			1.2			0.7		140

Operating margin		100.4			135.9			35.5		35
Depreciation and amortization expense		23.2			26.4			(3.2	)	(14	)
G&A expense		21.1			23.2			(2.1	)	(10	)

Operating profit		56.1			86.3			30.2		54
Interest expense (net of interest income and interest capitalized)		14.4			20.9			(6.5	)	(45	)
Debt placement fee amortization		0.2			0.3			(0.1	)	(50	)
Other income		(0.1	)		—			(0.1	)	(100	)

Income before provision for income taxes		41.6			65.1			23.5		56
Provision for income taxes		0.4			0.6			(0.2	)	(50	)

Net income	$	41.2		$	64.5		$	23.3		57


Operating Statistics

Petroleum products pipeline system:
Transportation revenue per barrel shipped	$	1.145		$	1.222
Volume shipped (million barrels)		71.7			69.7
Petroleum products terminals:
Marine terminal average storage utilized (million barrels per month)		22.5			23.8
Inland terminal throughput (million barrels)		26.0			26.1
Ammonia pipeline system:
Volume shipped (thousand tons)		124			167

Transportation and terminals revenues increased by $18.2 million, resulting from:

•

an increase in petroleum products pipeline system revenues of $8.0 million primarily attributable to higher transportation revenues, higher capacity and storage lease revenues and incremental fees for ethanol blending and additives. Transportation revenues increased primarily as a result of higher average tariffs due largely to mid-year 2009 tariff escalations;

•

an increase in petroleum products terminals revenues of $8.3 million due to higher revenues at both our marine and inland terminals. Marine revenues increased primarily at our Galena Park, Texas and Wilmington, Delaware facilities due to leasing new storage tanks placed in service and higher rates on existing storage. Inland revenues benefitted from higher fees due to ethanol blending; and

•

an increase in ammonia pipeline system revenues of $1.9 million due to increased shipments. First quarter 2009 shipments were negatively impacted by operational issues at two of our customers’ plants.

Operating expenses increased by $1.8 million, resulting from:

•

a decrease in petroleum products pipeline system expenses of $0.1 million as lower property taxes and more favorable product overages were largely offset by higher operating expenses related to our Houston-to-El Paso, Texas pipeline section (acquired from Longhorn Partners Pipeline, L.P. in third quarter 2009);

•

an increase in petroleum products terminals expenses of $1.1 million primarily related to timing of maintenance projects and higher personnel costs; and

•

an increase in ammonia pipeline system expenses of $0.9 million due primarily to an increase in environmental costs due to a 2010 pipeline release.

Product sales revenues primarily resulted from our petroleum products blending activities, product marketing and linefill management associated with our Houston-to-El Paso pipeline section, terminal product gains and transmix fractionation. We utilize New York Mercantile Exchange (“NYMEX”) contracts to hedge against changes in the future price of petroleum products related to these activities. Product margin increased $18.4 million between periods primarily due to the timing of realized profits for these hedged volumes. Due to mark-to-market adjustments, much of the profit related to the commodity sales activity in first quarter 2009 was realized in late 2008. Product margin also increased due to profits from our linefill management activities associated with our Houston-to-El Paso pipeline section.

Depreciation and amortization expense increased by $3.2 million primarily due to expansion capital projects placed into service during the past twelve months and the acquisition of our Houston-to-El Paso pipeline section.

G&A expense increased by $2.1 million between periods primarily due to higher equity-based incentive compensation costs.

Interest expense, net of interest income and interest capitalized, increased $6.5 million. Our average debt outstanding, excluding fair value adjustments for interest rate hedges, increased to $1.69 billion for first quarter 2010 from $1.09 billion for first quarter 2009 principally due to borrowings for expansion capital expenditures and the Houston-to-El Paso pipeline section acquisition. The weighted-average interest rate on our borrowings, after giving effect to the impact of associated fair value hedges, decreased to 5.1% in first quarter 2010 from 5.6% in 2009.

Liquidity and Capital Resources

Cash Flows and Capital Expenditures

Net cash provided by operating activities was $59.7 million and $73.3 million for the three months ended March 31, 2009 and 2010, respectively. The $13.6 million increase from 2009 to 2010 was primarily attributable to:

•

an increase in net income of $23.3 million;

•

a $15.9 million increase in cash resulting from a $10.0 million decrease in accounts receivable and other accounts receivable in 2010 versus a $5.9 million increase in 2009 primarily due to the timing of payments received from customers; and

•

a $16.7 million increase in cash resulting from a $19.9 million increase in accounts payable in 2010 versus a $3.2 million increase in 2009 due primarily to the timing of invoices received from vendors and suppliers.

These increases were partially offset by:

•

a $31.5 million decrease in cash resulting from a $49.6 million increase in inventory in 2010 versus an $18.1 million increase in inventory in 2009 primarily due to the linefill and working inventory of our Houston-to-El Paso pipeline section, which we acquired in July 2009; and

•

a $10.3 million decrease in cash resulting from a $3.5 million decrease in accrued interest payable in 2010 versus a $6.8 million increase in 2009 due primarily to the timing of semi-annual interest payments.

Net cash used by investing activities for the three months ended March 31, 2009 and 2010 was $46.9 million and $40.1 million, respectively. 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. During 2009, we spent $47.6 million for capital expenditures, which included $11.3 million for maintenance capital and $36.3 million for expansion capital.

Net cash used by financing activities for the three months ended March 31, 2009 and 2010 was $34.3 million and $30.5 million, respectively. During 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. Net borrowings on our revolving credit facility during first quarter 2009, primarily to finance expansion capital projects, were $42.0 million.

During first quarter 2010, we paid $75.8 million in cash distributions to our unitholders. Based on the declared quarterly distribution of $0.72 per unit associated with the first quarter of 2010, we will pay $76.8 million in distributions during second quarter 2010. If we continue to pay cash distributions at this current level and the number of outstanding units remains the same, we will pay total cash distributions of $307.4 million on an annual basis.

In January 2010, the cumulative amounts of the January 2007 award grants were settled by issuing 140,317 limited partner units and distributing those units to the participants. Associated tax withholdings and employer taxes totaling $3.9 million were paid in January 2010.

Capital Requirements

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

•

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

•

expansion capital expenditures to acquire additional complementary assets to grow our business and to expand or upgrade our existing facilities, which we refer to as organic growth projects. Organic growth projects include capital expenditures that increase storage or throughput volumes or develop pipeline connections to new supply sources.

For the three months ended March 31, 2010, our maintenance capital spending was $6.4 million, including $0.4 million of spending reimbursable by insurance. For 2010, we expect to incur maintenance capital expenditures for our existing businesses of approximately $45.0 million.

In addition to maintenance capital expenditures, we also incur expansion capital expenditures at our existing facilities. During first quarter 2010, we spent $35.2 million for organic growth projects. Based on the progress of expansion projects already underway, we expect to spend approximately $250.0 million of expansion capital during 2010, including acquisitions, with an additional $30.0 million in future years to complete these projects.

Liquidity

As of March 31, 2010, total debt reported on our consolidated balance sheet was $1,734.1 million. The difference between this amount and the $1,702.2 million face value of our outstanding debt results from gains and losses realized on various cash flow hedges and unamortized discounts and premiums on debt issuances.

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


	December 31, 2009		March 31, 2010		Weighted-Average Interest Rate at March 31, 2010 (1)
Revolving credit facility	$	101,600	$	152,200	0.6	%
6.45% Notes due 2014		249,732		249,745	6.3	%
5.65% Notes due 2016		252,897		252,789	5.7	%
6.40% Notes due 2018		260,340		260,036	5.9	%
6.55% Notes due 2019		566,500		570,401	4.6	%
6.40% Notes due 2037		248,935		248,938	6.3	%

Total debt	$	1,680,004	$	1,734,109

(1)

Weighted-average interest rate includes the impact of interest rate swaps and the amortization of discounts and gains and losses realized on various cash flow hedges.

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

6.55% Notes due 2019. In June and August 2009, we issued $550.0 million of 6.55% notes due 2019 in underwritten public offerings. The notes were issued at a net premium of 103.4%, or $568.7 million. In connection with these offerings, we entered into interest rate swap agreements to effectively convert $250.0 million of these notes to floating-rate debt. The outstanding principal amount of the notes was increased (decreased) by $(1.6) million and $2.6 million at December 31, 2009 and March 31, 2010, respectively, for the fair value less accrued interest of the associated interest rate swap agreements.

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

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

Interest rate derivatives.

In June and August 2009, we entered into a total of $150.0 million and $100.0 million, respectively, of interest rate swap agreements to hedge against changes in the fair value of a portion of the $550.0 million of 6.55% notes due 2019. We account for these agreements as fair value hedges. These agreements effectively convert $250.0 million of our 6.55% fixed-rate notes to floating-rate debt. Under the terms of the agreements, we receive the 6.55% fixed rate of the notes and pay six-month LIBOR in arrears plus 2.18% for the $150.0 million swaps and 2.34% for the other $100.0 million. The agreements terminate in June 2019, 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 these swaps 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. These interest rate derivatives contain credit-risk-related contingent features. These contingent features provide that in the event of our default on any obligation of $25.0 million or more or a merger in which our credit rating becomes “materially weaker,” which would generally be interpreted as falling below investment grade, the counterparties to our interest rate derivatives agreements could terminate those agreements and require immediate settlement. None of our interest rate derivatives were in a liability position as of March 31, 2010.

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

Off-Balance Sheet Arrangements

None.

Environmental

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

Clean Air Act. Section 185 of the Clean Air Act (“CAA 185”) requires each state to assess fees against major stationary emission sources in “severe” or “extreme” non-attainment areas. During 2009, the Texas Commission on Environmental Quality (“TCEQ”), in response to an Environmental Protection Agency (“EPA”) request, issued proposed rules which, if adopted as proposed, may result in fees assessed against our Galena Park, Texas terminal for the 2008 and 2009 calendar years of up to $8.1 million and $4.8 million, respectively.

Based on the monitoring data for the Houston/Galveston/Brazoria, Texas area prepared by the TCEQ, which indicates that the area obtained the ozone standard for past three consecutive years, the TCEQ is pursuing a Termination Determination from the EPA, which, if approved by the EPA, would terminate any requirements by the TCEQ to pursue actions under CAA 185. However, an environmental group has submitted a petition in Federal Court challenging the Termination Determination process. We believe our Galena Park, Texas terminal will not be assessed penalties under CAA 185 and at March 31, 2010 we had no amounts accrued for this matter.

Other Items

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

•

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

Since July 2009, some of the NYMEX contracts associated with future sales of petroleum products qualified for hedge accounting treatment and have been recorded as cash flow hedges. The gains and losses resulting from the mark-to-market changes in value of these contracts are not included in product sales revenues in our consolidated statement of income until the petroleum products they are hedging are physically sold. As of March 31, 2010, we had no open NYMEX contracts of petroleum products that qualified for hedge accounting treatment. During the first quarter of 2010, we recognized $2.0 million of losses associated with derivative agreements that qualified as hedges when the hedged products were sold and the contracts were settled.

We had open NYMEX contracts for 0.8 million barrels of petroleum products as of March 31, 2010 that did not qualify for hedge accounting treatment. These contracts mature between April 2010 and October 2010. The cumulative amount of unrealized losses through March 31, 2010 associated with these agreements of $2.8 million have been recorded as a decrease in product sales revenues on our consolidated statements of income and energy commodity derivatives contracts on our consolidated balance sheet, of which $1.8 million was recorded during the first quarter 2010. Additionally, we realized losses of $0.5 million on NYMEX contracts that did not qualify for hedge accounting treatment that settled during first quarter 2010.

•

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

At March 31, 2010, we had open NYMEX contracts covering 1.6 million barrels to hedge against changes in the future price of petroleum products associated with the linefill barrels. Contracts covering 1.4 million barrels mature between April 2010 and July 2010 and contracts covering 0.2 million barrels mature in July 2011. Because these NYMEX contracts do not qualify for hedge accounting treatment, we recognize the period change in fair value of these agreements in our consolidated income statement. The cumulative amount of unrealized losses through March 31, 2010 associated with these agreements were $11.3 million, which have been recorded as a decrease in product sales revenues on our consolidated statements of income, and $10.1 million and $1.2 million were recorded as energy commodity derivatives contracts and other noncurrent liabilities, respectively, on our consolidated balance sheet. Of the $11.3 million of cumulative losses, $5.0 million was recorded in the first quarter 2010. Additionally, we recognized $0.3 million of gains associated with the linefill NYMEX contracts that were settled during the first quarter of 2010 and recorded as product sales revenues on our consolidated income statement.

The following table provides a summary of the mark-to-market gains and losses associated with NYMEX contracts and the accounting period that the gains and losses were recognized in our consolidated statements of income for the three months ended March 31, 2009 and 2010 (in millions):


2009
NYMEX losses associated with physical product sales in first quarter 2009	$	(0.4	)
NYMEX losses associated with physical product sales in 2009 subsequent to March 31, 2009		(3.1	)

Total NYMEX losses recorded in first quarter 2009	$	(3.5	)


2010
NYMEX losses associated with physical product sales in first quarter 2010	$	(2.2	)
NYMEX losses associated with future physical product sales		(6.8	)

Total NYMEX losses recorded in first quarter 2010	$	(9.0	)

Ammonia Pipeline Testing. We will be performing extensive hydrostatic testing of our ammonia pipeline system during 2010. Expenditures during 2010 to complete this testing are estimated to be up to $10.0 million, which is $5.0 million higher than testing costs incurred in 2009. During certain periods of testing, it is anticipated that the pipeline will be unavailable for shipments, resulting in reduced shipment volumes. We are unable to estimate the impact this will have on our current year revenues because we expect our customer movements before and after the testing to be higher than at historical levels.

Pipeline Tariff Changes. The Federal Energy Regulatory Commission (“FERC”) regulates the rates charged on interstate common carrier pipeline operations primarily through an index methodology, which establishes the maximum amount by which tariffs can be adjusted. Approximately 40% of our tariffs are subject to this indexing methodology while the remaining 60% of the tariffs can be adjusted at our discretion based on competitive factors. The current approved methodology is the annual change in the producer price index for finished goods (“PPI-FG”) plus 1.3%. The preliminary change in PPI-FG for 2009 is approximately negative 2.5%. As a result, we expect to decrease our rates in the 40% of our markets that are subject to the FERC’s index methodology by approximately 1.2% in July 2010.

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

petroleum products terminals experience net product overages, we have product on hand for which we have no cost basis. Therefore, these net overages are not recognized in our financial statements until the associated barrels are either sold or used to offset product losses. The net unrecognized product overages for our petroleum products terminals operations had a market value of approximately $7.0 million as of March 31, 2010. However, the actual amounts we will recognize in future periods will depend on product prices at the time the associated barrels are either sold or used to offset future product losses.

New Accounting Pronouncements

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

On January 21, 2010, the FASB issued ASU No. 2010-06, Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements. This ASU requires disclosure of: (i) separate fair value measurements for each class of assets and liabilities, (ii) significant transfers between level 1 and level 2 in the fair value hierarchy and the reasons for such transfers, (iii) gains and losses for the period and purchases, sales, issuances, and settlements for Level 3 fair value measurements, (iv) transfers into and out of Level 3 of the hierarchy and the reasons for such transfers, and (v) the valuation techniques applied and inputs used in determining Level 2 and Level 3 measurements for each class of assets and liabilities. This ASU was generally effective for interim and annual reporting periods beginning after December 15, 2009; however, the requirements to disclose separately purchases, sales, issuances and settlements in the Level 3 reconciliation are effective for fiscal years beginning after December 15, 2010 (and for interim periods within such years). Early adoption is allowed. Our adoption of the applicable sections of this ASU did not have a material impact on our financial position, results of operations or cash flows.

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

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

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

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

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

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Commodity Price Risk

We use derivatives to help us manage product purchases and sales. Derivatives that qualify for and are designated as normal purchases and sales are accounted for using traditional accrual accounting. As of March 31, 2010, we had commitments under forward purchase contracts for product purchases of approximately 0.4 million barrels that are being accounted for as normal purchases totaling approximately $34.6 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 $17.5 million.

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

Based on our open NYMEX contracts at March 31, 2010, a $1.00 per barrel increase in the price of the NYMEX contract for reformulated gasoline blendstock for oxygen blending (“RBOB”) gasoline or heating oil would result in a $2.4 million decrease in our product sales revenues and a $1.00 per barrel decrease in the price of the NYMEX contract for RBOB or heating oil would result in a $2.4 million increase in our product sales revenues. However, the increases or decreases in product sales revenues we recognize from our open NYMEX contracts are substantially offset by higher or lower product sales revenues when the physical sale of the product occurs. These contracts may be for the purchase or sale of product in markets different from those in which we are attempting to hedge our exposure, resulting in hedges that do not eliminate all price risks.

Interest Rate Risk

During 2009, we entered into a total of $250.0 million of interest rate swap agreements to hedge against changes in the fair value of a portion of our $550.0 million of 6.55% notes due 2019. We account for these agreements as fair value hedges. These agreements effectively convert $250.0 million of our 6.55% fixed-rate notes issued in June and August 2009 to floating-rate debt. Under the terms of the agreements, we will receive the 6.55% fixed rate of the notes and pay six-month LIBOR in arrears plus 2.18% on $150.0 million of the agreements and pay six-month LIBOR in arrears plus 2.34% on the other $100.0 million. The agreements terminate in June 2019, which is the maturity date of the related notes. Payments settle in January and July each year. During each period, we will record the impact of these swaps 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 interest expense. A 0.125% change in LIBOR would result in an annual adjustment to our interest expense of $0.3 million associated with these hedges.

As of March 31, 2010, we had $152.2 million outstanding on our variable rate revolving credit facility. Considering the amount outstanding on our revolving credit facility as of March 31, 2010, our annual interest expense would change by $0.2 million if LIBOR were to change by 0.125%.

ITEM 4.

CONTROLS AND PROCEDURES

An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in rule 13a-14(c) of the Securities Exchange Act) was performed as of the end of the period covered by the date of this report. This evaluation was performed under the supervision and with the participation of our management, including our general partner’s Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our general partner’s Chief Executive Officer and Chief Financial Officer concluded that these disclosure controls and practices are effective in providing reasonable assurance that all required disclosures are included in the current report. Additionally, these disclosure controls and practices are effective in ensuring that information required to be disclosed is accumulated and communicated to our Chief Executive Officer and Chief Financial Officer to allow timely decisions regarding required disclosures. There has been no change in our internal control over financial reporting (as defined in Rule 13a-15(f) of the Securities Exchange Act) during the quarter ended March 31, 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Forward-Looking Statements

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

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

•

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

•

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

•

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

•

changes in the financial condition of our customers;

•

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

•

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

•

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

•

changes in demand for storage in our petroleum products terminals;

•

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

•

our ability to manage interest rate and commodity price exposures;

•

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

•

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

•

weather patterns materially different than historical trends;

•

an increase in the competition our operations encounter;

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

the effect of changes in accounting policies;

•

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

•

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

•

supply disruption; and

•

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

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

PART II

OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

In June 2009, we received notice from the Department of Justice (“DOJ”) that the EPA had requested the DOJ to initiate a lawsuit alleging violations of Sections 301 and 311 of the Clean Water Act with respect to a release of petroleum product that occurred in Oklahoma in January 2008. The DOJ stated that the maximum statutory penalty for alleged violations of the Clean Water Act for the release was approximately $1.2 million. As a result of subsequent negotiations, we and the EPA agreed on a settlement in the amount of $0.4 million.

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

ITEM 1A.

RISK FACTORS

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

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 12	–	Ratio of Earnings to Fixed Charges.

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

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

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

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

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, 2010.


MAGELLAN MIDSTREAM PARTNERS, L.P.

By:		Magellan GP, LLC
		its General Partner

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

INDEX TO EXHIBITS


EXHIBIT NUMBER		DESCRIPTION
12		Ratio of Earnings to Fixed Charges.

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

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

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

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

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