Edgar Filing: MAGELLAN MIDSTREAM PARTNERS LP

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2008

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

For the transition period from to

Commission File No.: 1-16335

Magellan Midstream Partners, L.P.

(Exact name of registrant as specified in its charter)


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

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

(Address of principal executive offices and zip code)

(918) 574-7000

(Registrant’s telephone number, including area code)

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

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12-b-2 of the Exchange Act). Yes ¨ No x

As of May 5, 2008, there were 66,743,730 outstanding common units of Magellan Midstream Partners, L.P., that trade on the New York Stock Exchange under the ticker symbol “MMP.”

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
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1.	Organization and Basis of Presentation and Other	5
2.	Allocation of Net Income	6
3.	Comprehensive Income	7
4.	Segment Disclosures	7
5.	Related Party Disclosures	8
6.	Inventory	10
7.	Employee Benefit Plans	10
8.	Debt	11
9.	Derivative Financial Instruments	11
10.	Commitments and Contingencies	12
11.	Long-Term Incentive Plan	14
12.	Distributions	15
13.	Net Income Per Unit	16
14.	Assignment of Supply Agreement	16
15.	Recent Accounting Standard	16
16.	Subsequent Events	17
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Introduction		18
Recent Developments		18
Significant Events		18
Results of Operations		19
Liquidity and Capital Resources		21
Off-Balance Sheet Arrangements		23
Environmental		23
Other Items		24
New Accounting Pronouncements		25
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		26
ITEM 4. CONTROLS AND PROCEDURES		26
Forward-Looking Statements		26

PART II OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS		29
ITEM 1A. RISK FACTORS		29
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		30
ITEM 3. DEFAULTS UPON SENIOR SECURITIES		30
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS		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,
	2007			2008
Transportation and terminals revenues	$	143,151		$	144,592
Product sales revenues		148,663			201,718
Affiliate management fee revenues		173			183

Total revenues		291,987			346,493
Costs and expenses:
Operating		60,975			55,592
Product purchases		133,980			177,568
Depreciation and amortization		15,440			17,176
Affiliate general and administrative		17,685			17,780

Total costs and expenses		228,080			268,116
Gain on assignment of supply agreement		—			26,492
Equity earnings		763			405

Operating profit		64,670			105,274
Interest expense		14,867			12,936
Interest income		(371	)		(293	)
Interest capitalized		(897	)		(1,302	)
Debt placement fee amortization		645			168

Income before provision for income taxes		50,426			93,765
Provision for income taxes		724			443
Net income	$	49,702		$	93,322

Allocation of net income:
Limited partners’ interest	$	36,851		$	59,620
General partner’s interest		12,851			33,702

Net income	$	49,702		$	93,322


Basic net income per limited partner unit	$	0.55		$	0.89

Weighted average number of limited partner units outstanding used for basic net income per unit calculation		66,538			66,772


Diluted net income per limited partner unit	$	0.55		$	0.89

Weighted average number of limited partner units outstanding used for diluted net income per unit calculation		66,546			66,772

See notes to consolidated financial statements.

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(In thousands)


	December 31,			March 31,
	2007			2008
				(Unaudited)
ASSETS
Current assets:
Accounts receivable (less allowance for doubtful accounts of $10 and $23 at December 31, 2007 and March 31, 2008, respectively)	$	62,834		$	54,998
Other accounts receivable		10,696			10,048
Affiliate accounts receivable		208			892
Inventory		120,462			100,195
Other current assets		10,882			11,411

Total current assets		205,082			177,544
Property, plant and equipment		2,435,890			2,497,115
Less: accumulated depreciation		615,329			630,323

Net property, plant and equipment		1,820,561			1,866,792
Equity investments		24,324			23,429
Long-term receivables		7,506			7,523
Goodwill		23,945			26,808
Other intangibles (less accumulated amortization of $6,743 and $7,130 at December 31, 2007 and March 31, 2008, respectively)		7,086			6,699
Debt placement costs (less accumulated amortization of $2,170 and $2,338 at December 31, 2007 and March 31, 2008, respectively)		6,368			6,200
Other noncurrent assets		6,322			10,244

Total assets	$	2,101,194		$	2,125,239

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	39,622		$	28,777
Affiliate accounts payable		12,947			1,739
Affiliate payroll and benefits		23,364			13,198
Accrued interest payable		7,197			18,829
Accrued taxes other than income		21,039			18,743
Environmental liabilities		36,127			36,288
Deferred revenue		20,797			23,053
Accrued product purchases		43,230			49,821
Other current liabilities		16,322			17,704

Total current liabilities		220,645			208,152
Long-term debt		914,536			952,171
Long-term affiliate payable		1,878			380
Long-term affiliate pension and benefits		22,370			24,489
Supply agreement deposit		18,500			—
Noncurrent portion of product supply liability		24,348			—
Other deferred liabilities		6,081			13,032
Environmental liabilities		21,672			21,380
Commitments and contingencies
Partners’ capital:
Partners’ capital		882,642			923,483
Accumulated other comprehensive loss		(11,478	)		(17,848	)

Total partners’ capital		871,164			905,635

Total liabilities and partners’ capital	$	2,101,194		$	2,125,239

See notes to consolidated financial statements.

MAGELLAN MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, in thousands)


	Three Months Ended March 31,
	2007			2008
Operating Activities:
Net income	$	49,702		$	93,322
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		15,440			17,176
Debt placement fee amortization		645			168
Loss on sale and retirement of assets		862			103
Equity earnings		(763	)		(405	)
Distributions from equity investment		1,100			1,300
Equity method incentive compensation expense		537			1,139
Amortization of prior service cost and actuarial loss		384			377
Gain on assignment of supply agreement		—			(26,492	)
Changes in operating assets and liabilities:
Accounts receivable and other accounts receivable		(8,585	)		8,484
Affiliate accounts receivable		(264	)		(684	)
Inventory		11,943			20,267
Accounts payable		(16,764	)		(6,348	)
Affiliate accounts payable		(1,492	)		(2,672	)
Affiliate payroll and benefits		(11,312	)		(10,166	)
Accrued interest payable		12,912			11,632
Accrued taxes other than income		123			(2,296	)
Accrued product purchases		(17,307	)		6,591
Restricted cash		(5,337	)		—
Supply agreement deposit		(1,000	)		(18,500	)
Current and noncurrent environmental liabilities		3,352			(131	)
Other current and noncurrent assets and liabilities		(1,795	)		3,019

Net cash provided by operating activities		32,381			95,884
Investing Activities:
Property, plant and equipment:
Additions to property, plant and equipment		(39,356	)		(54,882	)
Proceeds from sale of assets		202			909
Changes in accounts payable		(10,761	)		(4,497	)
Acquisition of business		—			(12,010	)

Net cash used by investing activities		(49,915	)		(70,480	)
Financing Activities:
Distributions paid		(56,291	)		(63,793	)
Net borrowings under revolver		66,800			33,500
Capital contributions by affiliate		700			1,637
Change in outstanding checks		—			3,252

Net cash provided (used) by financing activities		11,209			(25,404	)

Change in cash and cash equivalents		(6,325	)		—
Cash and cash equivalents at beginning of period		6,390			—

Cash and cash equivalents at end of period	$	65		$	—


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

See notes to consolidated financial statements.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Basis of Presentation

Organization and Basis of Presentation

Unless indicated otherwise, the terms “our,” “we,” “us” and similar language refer to Magellan Midstream Partners, L.P., together with our subsidiaries. We are a Delaware limited partnership, and our units are traded on the New York Stock Exchange under the ticker symbol “MMP.” Magellan GP, LLC, a Delaware limited liability company, serves as our general partner and owns an approximate 2% general partner interest in us as well as all of our incentive distribution rights. Magellan GP, LLC is a wholly-owned subsidiary of Magellan Midstream Holdings, L.P., a publicly traded Delaware limited partnership. We and Magellan GP, LLC have contracted with Magellan Midstream Holdings GP, LLC, Magellan Midstream Holdings, L.P.’s general partner, to provide all general and administrative (“G&A”) services and operating functions required for our operations. Our organizational structure at March 31, 2008, and that of our affiliate entities, as well as how we refer to these affiliates in our notes to consolidated financial statements, is provided below.

LOGO

We operate and report in three business segments: the petroleum products pipeline system, the petroleum products terminals and the ammonia pipeline system. Our reportable segments offer different products and services and are managed separately because each requires different marketing strategies and business knowledge. In January 2008, we acquired a petroleum products terminal in Bettendorf, Iowa for $12.0 million. The results of this facility are included in our petroleum products pipeline system segment.

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

Pursuant to the rules and regulations of the Securities and Exchange Commission, the financial statements in this report do not include all of the information and notes normally included with financial statements prepared in accordance with accounting principles generally accepted in the United States. These financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2007.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. Allocation of Net Income

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


	Three Months Ended March 31,
	2007			2008
Allocation of net income to general partner:
Net income	$	49,702		$	93,322
Direct charges to general partner:
Reimbursable G&A costs		276			408
Previously indemnified environmental charges		2,250			1,529

Total direct charges to general partner		2,526			1,937

Income before direct charges to general partner		52,228			95,259
General partner’s share of income ^(a)		29.44	%		37.41	%

General partner’s allocated share of net income before direct charges		15,377			35,639
Direct charges to general partner		(2,526	)		(1,937	)

Net income allocated to general partner	$	12,851		$	33,702


Net income	$	49,702		$	93,322
Less: net income allocated to general partner		12,851			33,702

Net income allocated to limited partners	$	36,851		$	59,620

(a)

For periods when the distributions we pay exceed our net income, our general partner’s percentage share of income is its proportion of cash distributions paid for the period. For periods when our net income exceeds the cash distributions we pay, our general partner’s percentage share of income is its proportion of theoretical distributions that equal net income (before direct charges to general partner). The distributions we paid for the three months ended March 31, 2007 exceeded net income for that period; therefore, our general partner’s share of net income was based on its share of cash distributions paid for that period. Our net income for the three months ended March 31, 2008 exceeded the cash distributions we will pay for that period; therefore, our general partner’s share of income was allocated based on a theoretical distribution of $0.8933 per limited partner unit, at which rate distributions would be equal to our net income (before direct charges to general partner) for the period.

The reimbursable G&A costs above represent G&A expenses charged against our income during the periods presented that were required to be reimbursed to us by our general partner under the terms of the omnibus agreement. Because the limited partners do not share in these costs, we have allocated these G&A expense amounts directly to our general partner. We record these reimbursements by our general partner as capital contributions. Prior to 2007, we and our general partner entered into an agreement with a former affiliate to settle certain of our former affiliate’s indemnification obligations to us (see Note 10—Commitments and Contingencies). Under this agreement, our former affiliate paid us $117.5 million, which we recorded as a capital contribution from our general partner. Current period costs associated with this indemnification agreement settlement are designated as “previously indemnified environmental charges.” Since our limited partners do not share in these costs, we have allocated these amounts directly to our general partner.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3. Comprehensive Income

Comprehensive income is the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from nonowner sources. Comprehensive income includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. The term other comprehensive income (“OCI”) refers to revenues, expenses, gains, and losses that, under generally accepted accounting principles (“GAAP”), are included in comprehensive income but excluded from net income. A reconciliation of net income to comprehensive income follows below (in thousands). For information on all of our derivative instruments, see Note 9 – Derivative Financial Instruments.


	Three Months Ended March 31,
	2007		2008
Net income	$	49,702	$	93,322
Change in fair value of cash flow hedges		2,943		(6,706	)
Amortization of net loss (gain) on cash flow hedges		53		(41	)
Amortization of prior service cost and net actuarial loss		384		377

Other comprehensive income (loss)		3,380		(6,370	)

Comprehensive income	$	53,082	$	86,952

4. Segment Disclosures

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

We believe that investors benefit from having access to the same financial measures being used by management. Operating margin, which is presented in the tables below, is an important measure used by management to evaluate the economic performance of our core operations. This measure forms the basis of our internal financial reporting and is used by management in deciding how to allocate capital resources between segments. Operating margin is not a 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 below. Operating profit includes expense items, such as depreciation and amortization and affiliate G&A expenses, that management does not consider when evaluating the core profitability of our operations.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


	Three Months Ended March 31, 2007
	(in thousands)
	Petroleum Products Pipeline System			Petroleum Products Terminals		Ammonia Pipeline System			Intersegment Eliminations			Total
Transportation and terminals revenues	$	107,311		$	31,749	$	4,915		$	(824	)	$	143,151
Product sales revenues		144,265			4,398		—			—			148,663
Affiliate management fee revenue		173			—		—			—			173

Total revenues		251,749			36,147		4,915			(824	)		291,987
Operating expenses		42,942			13,961		5,539			(1,467	)		60,975
Product purchases		131,426			2,682		—			(128	)		133,980
Equity earnings		(763	)		—		—			—			(763	)

Operating margin (loss)		78,144			19,504		(624	)		771			97,795
Depreciation and amortization		9,630			4,843		196			771			15,440
Affiliate G&A expenses		12,530			4,527		628			—			17,685

Operating profit (loss)	$	55,984		$	10,134	$	(1,448	)	$	—		$	64,670


	Three Months Ended March 31, 2008
	(in thousands)
	Petroleum Products Pipeline System			Petroleum Products Terminals		Ammonia Pipeline System			Intersegment Eliminations			Total
Transportation and terminals revenues	$	106,323		$	33,601	$	5,420		$	(752	)	$	144,592
Product sales revenues		192,897			8,821		—			—			201,718
Affiliate management fee revenue		183			—		—			—			183

Total revenues		299,403			42,422		5,420			(752	)		346,493
Operating expenses		42,260			12,529		2,254			(1,451	)		55,592
Product purchases		174,621			3,077		—			(130	)		177,568
Gain on assignment of supply agreement		(26,492	)		—		—			—			(26,492	)
Equity earnings		(405	)		—		—			—			(405	)

Operating margin		109,419			26,816		3,166			829			140,230
Depreciation and amortization		10,381			5,764		202			829			17,176
Affiliate G&A expenses		12,741			4,115		924			—			17,780

Operating profit	$	86,297		$	16,937	$	2,040		$	—		$	105,274

5. Related Party Disclosures

Affiliate Entity Transactions

We have a 50% ownership interest in a crude oil pipeline company and are paid a management fee for its operation. During both the three months ended March 31, 2007 and 2008, we received operating fees from this pipeline company of $0.2 million, which we reported as affiliate management fee revenue.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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


	Three Months Ended
	March 31,
	2007		2008
MGG GP—allocated operating expenses	$	19,203	$	20,920
MGG GP—allocated G&A expenses	$	10,351	$	11,873

Under our services agreement with MGG GP, we reimburse MGG GP for costs of employees necessary to conduct our operations. The affiliate payroll and benefits accruals associated with this agreement at December 31, 2007 and March 31, 2008 were $23.4 million and $13.2 million, respectively, and the long-term affiliate pension and benefits accruals associated with this agreement at December 31, 2007 and March 31, 2008 were $22.4 million and $24.5 million, respectively. We settle our affiliate payroll, payroll-related expenses and non-pension postretirement benefit costs with MGG GP on a monthly basis. We settle our long-term affiliate pension liabilities through payments to MGG when MGG makes contributions to MGG GP’s pension funds.

MGG has agreed to reimburse us for G&A expenses, excluding equity-based compensation, in excess of a G&A cap. The amount of G&A costs required to be reimbursed by MGG to us was $0.3 million and $0.4 million for the three months ended March 31, 2007 and 2008, respectively. We do not expect to receive reimbursements under this agreement beyond 2008.

Other Related Party Transactions

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

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


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

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

One of our general partner’s independent board members, John P. DesBarres, currently serves as a board member for American Electric Power Company, Inc. (“AEP”) of Columbus, Ohio. During both the three months ended March 31, 2007 and 2008, our operating expenses included $0.6 million of power costs incurred with Public Service Company of Oklahoma (“PSO”), which is a subsidiary of AEP. We had no amounts payable to or receivable from PSO or AEP at either December 31, 2007 or March 31, 2008.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Because our distributions have exceeded target levels as specified in our partnership agreement, our general partner receives approximately 50% of any incremental cash distributed per limited partner unit. As of March 31, 2008, our executive officers collectively owned approximately 5% of MGG MH, which owned approximately 14% of MGG, the owner of our general partner. Therefore, our executive officers also benefit from distributions to our general partner. Assuming we have sufficient available cash to continue to pay distributions on all of our outstanding units for four quarters at our current quarterly distribution level of $0.6725 per unit, our general partner would receive annual distributions of approximately $83.6 million on its combined general partner interest and incentive distribution rights.

6. Inventory

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


	December 31, 2007		March 31, 2008
Refined petroleum products	$	65,215	$	37,714
Transmix		32,824		37,073
Natural gas liquids		16,233		19,194
Additives		5,812		5,835
Other		378		379

Total inventory	$	120,462	$	100,195

The decrease in inventory between December 31, 2007 and March 31, 2008 was primarily attributable to the sale of refined petroleum products inventory in connection with the assignment of our product supply agreement to a third-party entity effective March 1, 2008.

7. Employee Benefit Plans

MGG GP sponsors two pension plans for union employees, a pension plan for non-union employees and a postretirement benefit plan for selected employees. The following table presents our consolidated net periodic benefit costs related to these plans during the three months ended March 31, 2007 and 2008 (in thousands):


	Three Months Ended					Three Months Ended
	March 31, 2007					March 31, 2008
	Pension Benefits			Other Post-Retirement Benefits		Pension Benefits			Other Post-Retirement Benefits
Components of net periodic benefit costs:
Service cost	$	1,474		$	124	$	1,413		$	141
Interest cost		634			225		654			278
Expected return on plan assets		(573	)		—		(619	)		—
Amortization of prior service cost		169			45		169			44
Amortization of actuarial loss		59			111		16			148

Net periodic benefit cost	$	1,763		$	505	$	1,633		$	611

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. Debt

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


	December 31, 2007		March 31, 2008
Revolving credit facility	$	163,500	$	197,000
6.45% Notes due 2014		249,634		249,645
5.65% Notes due 2016		252,494		256,615
6.40% Notes due 2037		248,908		248,911

Total debt	$	914,536	$	952,171

Our debt is non-recourse to our general partner.

Revolving Credit Facility. The total borrowing capacity under our revolving credit facility, which matures in September 2012, is $550.0 million. Borrowings under the facility are unsecured and bear interest at LIBOR plus a spread ranging from 0.3% to 0.8% based on our credit ratings and amounts outstanding under the facility. Additionally, a commitment fee is assessed at a rate from 0.05% to 0.125%, depending on our credit rating. As of March 31, 2008, $197.0 million was outstanding under this facility, and $3.3 million was obligated for letters of credit. Amounts obligated for letters of credit are not reflected as debt on our consolidated balance sheets. The weighted-average interest rate on borrowings outstanding under the facility at March 31, 2007 and 2008 was 5.8% and 3.1%, respectively.

6.45% Notes due 2014. In May 2004, we sold $250.0 million aggregate principal of 6.45% notes due 2014 in an underwritten public offering. The notes were issued for the discounted price of 99.8%, or $249.5 million, and the discount is being accreted over the life of the notes. Including the impact of amortizing the gains realized on the interest hedges associated with these notes (see Note 9–Derivative Financial Instruments), the effective interest rate of these notes is 6.3%.

5.65% Notes due 2016. In October 2004, we issued $250.0 million of senior notes due 2016 in an underwritten public offering. The notes were issued for the discounted price of 99.9%, or $249.7 million, and the discount is being accreted over the life of the notes. Including the impact of amortizing the losses realized on the hedges associated with these notes, and the interest rate swap which effectively converts $100.0 million of these notes from fixed-rate to floating-rate debt (see Note 9–Derivative Financial Instruments), the weighted-average interest rate of these notes at March 31, 2007 and 2008 was 6.1% and 4.9%, respectively. The outstanding principal amount of the notes was increased by $2.7 million and $6.9 million at December 31, 2007 and March 31, 2008, respectively, for the fair value of the associated hedge.

6.40% Notes due 2037. In April 2007, we issued $250.0 million of 6.4% notes due 2037 in an underwritten public offering. The notes were issued for the discounted price of 99.6%, or $248.9 million, and the discount is being accreted over the life of the notes. Including the impact of amortizing the gains realized on the interest hedges associated with these notes (see Note 9—Derivative Financial Instruments), the effective interest rate of these notes is 6.3%.

9. Derivative Financial Instruments

We use interest rate derivatives to help us manage interest rate risk. As of March 31, 2008, we were a party to the following interest rate swap agreements:

•

In October 2004, we entered into an interest rate swap agreement to hedge against changes in the fair value of a portion of the $250.0 million of senior notes due 2016, which were issued in October 2004. We have accounted for this agreement as a fair value hedge. The notional amount of this agreement is $100.0 million and effectively converts $100.0 million of our 5.65% fixed-rate senior notes issued in October 2004 to floating-rate debt. Under the terms of the agreement, we receive the 5.65% fixed rate of the notes and pay LIBOR plus 0.6%. The agreement began in October 2004 and terminates in October 2016, which is the maturity date of the related notes. Payments settle in April and October each year with LIBOR set in arrears. During each period we record the impact of this swap based on the forward LIBOR curve. Any differences between actual LIBOR determined on the settlement date and our estimate of LIBOR results in an adjustment to our interest expense. A 0.25% change in LIBOR would result in an annual

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

adjustment to our interest expense of $0.3 million associated with this hedge. The fair value of this hedge at December 31, 2007 and March 31, 2008 was $2.7 million and $6.9 million, respectively, which was recorded to other noncurrent assets and long-term debt.

•

In January 2008, we entered into a total of $200.0 million of forward starting interest rate swap agreements to hedge against the variability of future interest payments on debt that we anticipated issuing no later than June 2008. Proceeds of the anticipated debt issuance were expected to be used to refinance borrowings on our revolving credit facility. The interest rate swap agreements had a 10-year term and an effective date of June 30, 2008. We have accounted for these interest rate swap agreements as cash flow hedges. The fair value of these hedges at March 31, 2008 was $(6.7) million, which was recorded to other deferred liabilities and OCL. See Note 16—Subsequent Events for additional information related to these interest rate swap agreements.

The following is a summary of our derivatives as of March 31, 2008 (in thousands):


					Effective Portion of Gains and Losses
Hedge	Balance Sheet Location	Fair Value			Unamortized Amount Recognized in OCI (OCL)			Amount Reclassified to Earnings from Accumulated OCL (OCI) During the Three Months Ended March 31, 2008
Cash flow hedges (date executed):
Interest rate swaps (January 2008)	Other deferred liabilities	$	(6,706	)	$	(6,706	)	$	—
Interest rate swaps (April 2007)			N/A			5,088			(44	)
Interest rate swaps (October 2004)			N/A			(4,469	)		131
Interest rate swaps and treasury lock (May 2004)			N/A			3,157			(128	)

Total cash flow hedges			(6,706	)		(2,930	)		(41	)

Fair value hedges:
Interest rate swap ($100.0 million of 5.65% notes due 2016)	Other noncurrent assets		6,850			—			—

Total		$	144		$	(2,930	)	$	(41	)

There was no ineffectiveness recognized on the financial instruments disclosed in the above table during the current period.

10. Commitments and Contingencies

Environmental Liabilities. Liabilities recognized for estimated environmental costs were $57.8 million and $57.7 million at December 31, 2007 and March 31, 2008, respectively. Environmental liabilities have been classified as current or noncurrent based on management’s estimates regarding the timing of actual payments. Management estimates that expenditures associated with these environmental liabilities will be paid over the next ten years.

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

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

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

additional costs associated with these releases if the EPA were to successfully seek and obtain injunctive relief. We responded to the March 2004 information request in a timely manner and have entered into an agreement that provides both parties an opportunity to negotiate a settlement prior to initiating litigation. We have accrued an amount for this matter based on our best estimates that is less than $22.0 million. Most of the amount we have accrued was included as part of the environmental indemnification settlement we reached with our former affiliate (see Indemnification Settlement description below). The DOJ and EPA have added to their original demand a release that occurred in the second quarter of 2005 from our petroleum products pipeline near our Kansas City, Kansas terminal and a release that occurred in the first quarter of 2006 from our petroleum products pipeline near Independence, Kansas. Our accrual includes these additional releases. We are in ongoing negotiations with the EPA; however, we are unable to determine what our ultimate liability could be for these matters. Adjustments to our recorded liability, which could occur in the near term, could be material to our results of operations and cash flows.

Ammonia EPA Issue. In February 2007, we received notice from the DOJ that the EPA had requested the DOJ to initiate a lawsuit alleging violations of Sections 301 and 311 of the Act with respect to two releases of anhydrous ammonia from the ammonia pipeline owned by us and operated by a third party. The DOJ stated that the maximum statutory penalty for alleged violations of the Act for both releases combined was approximately $13.2 million. The DOJ also alleged that the third-party operator of our ammonia pipeline was liable for penalties pursuant to Section 103 of the Comprehensive Environmental Response, Compensation and Liability Act for failure to report the releases on a timely basis, with the statutory maximum for those penalties as high as $4.2 million for which the third-party operator has requested indemnification. In March 2007, we also received a demand from the third-party operator for defense and indemnification in regards to a DOJ criminal investigation regarding whether certain actions or omissions of the third-party operator constituted violations of federal criminal statutes. The third-party operator has subsequently settled this criminal investigation with the DOJ by paying a $1.0 million fine. We believe that we do not have an obligation to indemnify or defend the third-party operator for the DOJ criminal fine settlement. The DOJ stated in its notice to us that it does not expect us or the third-party operator to pay the penalties at the statutory maximum; however, it may seek injunctive relief if the parties cannot agree on any necessary corrective actions. We have accrued an amount for these matters based on our best estimates that is less than the maximum statutory penalties. We are currently in discussions with the EPA, DOJ and the third-party operator regarding these two releases; however, we are unable to determine what our ultimate liability could be for these matters. Adjustments to our recorded liability, which could occur in the near term, could be material to our results of operations and cash flows.

PCB Impacts. We have identified polychlorinated biphenyls (“PCB”) impacts at two of our petroleum products terminals that we are in the process of assessing. It is possible that in the near term the PCB contamination levels could require corrective actions. We are unable at this time to determine what the corrective actions and associated costs might be. The costs of any corrective actions associated with these PCB impacts could be material to our results of operations and cash flows.

Indemnification Settlement. Prior to May 2004, a former affiliate had agreed to indemnify us against, among other things, certain environmental losses associated with assets contributed to us at the time of our initial public offering or which we subsequently acquired from this former affiliate. In May 2004, our general partner entered into an agreement under which our former affiliate agreed to pay us $117.5 million to release it from these indemnifications. We received the final installment payment associated with this agreement in 2007. At December 31, 2007 and March 31, 2008, known liabilities that would have been covered by this indemnity agreement were $42.9 million and $42.4 million, respectively. Through March 31, 2008, we have spent $47.7 million of the $117.5 million indemnification settlement amount for indemnified matters, including $20.4 million of capital costs. The cash we have received from the indemnity settlement is not reserved and has been used for our various other cash needs, including expansion capital spending.

Environmental Receivables. Receivables from insurance carriers and other entities related to environmental matters were $6.9 million and $5.7 million at December 31, 2007 and March 31, 2008, respectively.

Unrecognized Product Gains. Our petroleum products terminals operations generate product overages and shortages. When our petroleum products terminals experience net product shortages, we recognize expense for those losses in the periods in which they occur. When our petroleum products terminals experience net product overages, we have product on hand for which we have no cost basis. Therefore, these net overages are not recognized in our financial statements until the associated barrels are either sold or used to offset product losses. The net unrecognized product overages for our petroleum products terminals operations had a market value of approximately $10.0 million as of March 31, 2008. However, the actual amounts we will recognize in future periods will depend on product prices at the time the associated barrels are either sold or used to offset future product losses.

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

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. Long-Term Incentive Plan

We have a long-term incentive plan (“LTIP”) for certain MGG GP employees who perform services for us and for directors of our general partner. The LTIP primarily consists of phantom units and permits the grant of awards covering an aggregate of 3.2 million limited partner units. The compensation committee of our general partner’s board of directors (the “Compensation Committee”) administers the LTIP and has approved the unit awards discussed below.

The incentive awards discussed below are subject to forfeiture if employment is terminated for any reason other than retirement, death or disability prior to the vesting date. If an award recipient retires, dies or becomes disabled prior to the end of the vesting period, the recipient’s award grant is prorated based upon the completed months of employment during the vesting period and the award is settled at the end of the vesting period. The award grants do not have an early vesting feature except under certain circumstances following a change in control of our general partner.

The table below summarizes the unit awards granted by the Compensation Committee that have not vested as of March 31, 2008. There was no impact to our cash flows associated with these award grants for the periods presented in this report.


Grant Date	Unit Awards Granted	Estimated Forfeitures	Adjustment to Unit Awards in Anticipation of Achieving Above- Target Financial Results	Total Unit Awards Being Accrued	Vesting Date	Unrecognized Compensation Expense (Millions)		Period Over Which the Unrecognized Expense Will Be Recognized	Intrinsic Value of Unvested Awards at March 31, 2008 (Millions)
February 2006	168,105	12,607	139,948	295,446	12/31/08	$	2.1	Next 9 months	$	12.0
Various 2006	9,201	3,132	5,462	11,531	12/31/08		0.1	Next 9 months		0.5
March 2007	2,640	—	—	2,640	12/31/08		0.1	Next 9 months		0.1
Various 2007:
– Tranche 1	53,230	2,396	50,834	101,668	12/31/09		2.1	Next 21 months		4.1
– Tranche 2	53,230	2,396	—	50,834	12/31/09		1.7	Next 21 months		2.1
– Tranche 3	53,230	—	—	—	12/31/09		—	—		—
January 2008	184,340	8,295	—	176,045	12/31/10		5.5	Next 33 months		7.1
Various 2008	2,890	—	—	2,890	12/31/10		0.1	Next 33 months		0.1

Total	526,866	28,826	196,244	641,054		$	11.7		$	26.0

2008 Activity

We settled 2005 award grants in January 2008 by issuing 196,856 limited partner units and distributing those units to the participants. The difference between the limited partner units issued to the participants and the total accrued units represented the minimum tax withholdings associated with this award settlement. We paid associated tax withholdings and employer taxes totaling $5.1 million in January 2008.

The unit awards approved during 2007, except the March 2007 unit awards, are broken into three equal tranches, with each tranche vesting on December 31, 2009. We began accruing for the second tranche of the 2007 awards in the first quarter of 2008, when the Compensation Committee established the performance metrics associated with this tranche, and will recognize compensation expense associated with that tranche over a two-year period. 80% of these unit awards are based on the attainment of performance metrics and are being accounted for as equity and 20% of these unit awards are based on personal performance in addition to the company’s performance metrics and are being accounted for as liabilities.

The unit awards approved in January 2008 will vest on December 31, 2010. 80% of these unit awards are based on the attainment of performance metrics and are being accounted for as equity and 20% of these unit awards are based on personal performance in addition to the company’s performance metrics and are being accounted for as liabilities.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Weighted Average Fair Value

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


	Grant Date Fair Value of Equity Awards		March 31, 2008 Fair Value of Liability Awards
2006 Awards	$	24.67	$	38.45
2007 Awards	$	34.12	$	35.55
2008 Awards	$	33.40	$	31.66

Compensation Expense Summary

Our equity-based incentive compensation expense for the three months ended March 31, 2007 and 2008 is summarized as follows (in thousands):


	Three Months Ended March 31, 2007								Three Months Ended March 31, 2008
	Equity Method		Liability Method		Employer Taxes Paid		Total		Equity Method		Liability Method		Employer Taxes Paid		Total
2004 awards	$	—	$	—	$	519	$	519	$	—	$	—	$	—	$	—
2005 awards		—		2,290		—		2,290		—		26		580		606
2006 awards		467		276		—		743		475		175		—		650
2007 awards		70		28		—		98		376		80		—		456
2008 awards		—		—		—		—		288		64		—		352

Total	$	537	$	2,594	$	519	$	3,650	$	1,139	$	345	$	580	$	2,064

12. Distributions

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


Date Cash Distribution Paid	Per Unit Cash Distribution Amount		Common Units		General Partner		Total Cash Distribution
02/14/07	$	0.60250	$	40,094	$	16,197	$	56,291
05/15/07		0.61625		41,009		17,112		58,121
08/14/07		0.63000		41,924		18,027		59,951
11/14/07		0.64375		42,839		18,942		61,781

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


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

Total	$	1.33000	$	88,769	$	40,819	$	129,588

(a)	Our general partner declared this cash distribution in April 2008 to be paid on May 15, 2008 to unitholders of record at the close of business on May 6, 2008.

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13. Net Income Per Unit

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


	For The Three Months Ended March 31, 2007
	Income (Numerator)		Units (Denominator)	Per Unit Amount
Basic net income per limited partner unit	$	36,851	66,538	$	0.55
Effect of dilutive restricted unit grants		—	8		—

Diluted net income per limited partner unit	$	36,851	66,546	$	0.55


	For The Three Months Ended March 31, 2008
	Income (Numerator)		Units (Denominator)	Per Unit Amount
Basic net income per limited partner unit	$	59,620	66,772	$	0.89
Effect of dilutive restricted unit grants		—	—		—

Diluted net income per limited partner unit	$	59,620	66,772	$	0.89

The weighted average number of basic and dilutive units outstanding for net income per unit calculations is higher than the actual number of units outstanding because of units awarded under our LTIP that have already met the established performance metrics and deferred phantom units granted to certain independent members of our general partner’s board of directors.

14. Assignment of Supply Agreement

As part of our acquisition of a pipeline system in October 2004, we assumed a third-party supply agreement. Under this agreement, we were obligated to supply petroleum products to one of our customers until 2018. At that time, we believed that the profits we would receive from the supply agreement would not exceed the fair value of our tariff-based shipments on this pipeline and therefore we established a liability for the expected shortfall. On March 1, 2008, we assigned this supply agreement and sold related inventory to a third-party entity. Further, we returned our former customer’s cash deposit, which was $16.5 million at the time of the assignment. During the current quarter, we obtained a full release from our supply customer; therefore, we have no future obligation to perform under this supply agreement, even in the event the third-party assignee is unable to perform its obligations under the agreement. We will continue to earn transportation revenues for the product we ship related to this supply agreement but will no longer hold related inventories or recognize associated product sales and purchases. As part of this assignment, we agreed with the assignee that if the pricing under the supply agreement they assumed does not exceed our full tariff charge, then we will share in 50% of any shortfall versus our full tariff and similarly, we will be entitled to 50% of any excess above a certain threshold, which includes our tariff charge. All adjustments resulting from this agreement will be reflected in transportation and terminals revenues.

Excluding transportation revenues for products shipped under this product supply agreement, we recognized operating profit of $12.4 million in 2007 and $0.6 million and $2.9 million during first quarter 2007 and 2008, respectively, related to the supply agreement. In addition, upon assignment of the agreement on March 1, 2008, the remaining balance of the liability we had recorded upon assumption of the agreement in October 2004 was reduced to zero and we recognized a gain of $26.5 million.

15. Recent Accounting Standard

MAGELLAN MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

purposes of calculating earnings per unit, our current accounting practice is to allocate net income to the general partner based on the general partner’s share of total or theoretical distributions, as appropriate, including incentive distribution rights. The effect of adopting this EITF will be: (i) for periods when net income exceeds distributions, our reported earnings per limited partner unit will be higher than under our current accounting practice and (ii) for periods when distributions exceed net income, our reported earnings per limited partner unit will be lower than under our current accounting practice. These differences will be material for those periods where there are material differences between our net income and the distributions we pay. For example, had we applied EITF 07-4 to the current reporting period, basic and diluted earnings per limited partner unit would have increased from $0.89 to $1.10. This EITF is effective beginning January 1, 2009, including all interim periods after that date. Early application is not permitted. We intend to adopt this EITF in January 2009 for purposes of both calculating earnings per unit and determining the capital balances of our general and limited partners. This EITF is required to be applied retrospectively; therefore, we will restate prior period earnings per limited partner unit in all published financial reports after January 1, 2009, as applicable.

16. Subsequent Events

In April 2008, we terminated $200.0 million of forward starting interest rate swap agreements which were entered into in January 2008 (see Note 9—Derivatives). We received $0.2 million in connection with the termination.

In April 2008, our general partner declared a quarterly distribution of $0.6725 per unit to be paid on May 15, 2008 to unitholders of record at the close of business on May 6, 2008. Total distributions to be paid under this declaration are approximately $65.8 million.

ITEM 2.

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

Introduction

We are a publicly traded limited partnership formed to own, operate and acquire a diversified portfolio of complementary energy assets. We are principally engaged in the transportation, storage and distribution of refined petroleum products. As of March 31, 2008, our three operating segments include:

•

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

•

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

•

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

The following discussion provides an analysis of the results for each of our operating segments, an overview of our liquidity and capital resources and other items related to our partnership. The following discussion and analysis should be read in conjunction with (i) our accompanying interim consolidated financial statements and related notes and (ii) our consolidated financial statements, related notes and management’s discussion and analysis of financial condition and results of operations included in our Annual Report on Form 10-K for the year ended December 31, 2007.

Recent Developments

Distribution. During April 2008, the board of directors of our general partner declared a quarterly cash distribution of $0.6725 per unit for the period of January 1 through March 31, 2008, representing the twenty-eighth consecutive distribution increase since our initial public offering in February 2001. This quarterly distribution will be paid on May 15, 2008 to unitholders of record on May 6, 2008.

Unitholder vote results. During April 2008, we held our annual unitholder meeting. Proxy statements were mailed in advance to unitholders of record on February 25, 2008. Our unitholders elected James R. Montague and Don R. Wellendorf to continue serving as members of our general partner’s board of directors until our 2011 annual meeting. No other matters requiring a unitholder vote were presented.

Significant Events

Assignment of supply agreement. As part of our acquisition of a pipeline system in October 2004, we assumed a third-party supply agreement. Under this agreement, we were obligated to supply petroleum products to one of our customers until 2018. At that time, we believed that the profits we would receive from the supply agreement would not exceed the fair value of our tariff-based shipments on this pipeline and therefore we established a liability for the expected shortfall. On March 1, 2008, we assigned this supply agreement and sold related inventory to a third-party entity. Further, we returned our former customer’s cash deposit, which was $16.5 million at the time of the assignment. During the current quarter, we obtained a full release from our supply customer; therefore, we have no future obligation to perform under this agreement, even in the event the third-party assignee is unable to perform its obligations under the agreement. We will continue to earn transportation revenues for the product we ship related to this supply agreement but will no longer hold related inventories or recognize associated product sales and purchases. As part of this assignment, we agreed with the assignee that if the pricing under the supply agreement they assumed does not exceed our full tariff charge, then we will share in 50% of any shortfall versus our full tariff and similarly, we will be entitled to 50% of any excess above a certain threshold, which includes our tariff charge. All adjustments resulting from this agreement will be reflected in transportation and terminals revenues.

Results of Operations

We believe that investors benefit from having access to the same financial measures being utilized by management. Operating margin, which is presented in the table below, is an important measure used by management to evaluate the economic performance of our core operations. This measure forms the basis of our internal financial reporting and is used by management in deciding how to allocate capital resources between segments. Operating margin is not a generally accepted accounting principles (“GAAP”) measure, but the components of operating margin are computed 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 table below. Operating profit includes expense items, such as depreciation and amortization and affiliate general and administrative (“G&A”) costs, that management does not consider when evaluating the core profitability of our operations.

Three Months Ended March 31, 2007 Compared to Three Months Ended March 31, 2008


	Three Months Ended						Variance
	March 31,						Favorable (Unfavorable)
	2007			2008			$ Change			% Change
Financial Highlights ($ in millions, except operating statistics)

Revenues:
Transportation and terminals revenues:
Petroleum products pipeline system	$	107.3		$	106.3		$	(1.0	)	(1	)
Petroleum products terminals		31.7			33.6			1.9		6
Ammonia pipeline system		4.9			5.4			0.5		10
Intersegment eliminations		(0.8	)		(0.7	)		0.1		13

Total transportation and terminals revenues		143.1			144.6			1.5		1
Product sales		148.7			201.7			53.0		36
Affiliate management fees		0.2			0.2			—		—

Total revenues		292.0			346.5			54.5		19
Operating expenses:
Petroleum products pipeline system		42.9			42.3			0.6		1
Petroleum products terminals		14.0			12.5			1.5		11
Ammonia pipeline system		5.5			2.3			3.2		58
Intersegment eliminations		(1.4	)		(1.5	)		0.1		7

Total operating expenses		61.0			55.6			5.4		9
Product purchases		134.0			177.6			(43.6	)	(33	)
Gain on assignment of supply agreement		—			(26.5	)		26.5		N/A
Equity earnings		(0.8	)		(0.4	)		(0.4	)	(50	)

Operating margin		97.8			140.2			42.4		43
Depreciation and amortization		15.4			17.1			(1.7	)	(11	)
Affiliate G&A expense		17.7			17.8			(0.1	)	(1	)

Operating profit	$	64.7		$	105.3		$	40.6		63


Operating Statistics
Petroleum products pipeline system:
Transportation revenue per barrel shipped	$	1.152		$	1.153
Volume shipped (million barrels)		71.3			68.9
Petroleum products terminals:
Marine terminal average storage utilized (million barrels per month)		21.7			22.6
Inland terminal throughput (million barrels)		28.2			27.1
Ammonia pipeline system:
Volume shipped (thousand tons)		214			220

Transportation and terminals revenues increased by $1.5 million as shown below:

•

a decrease in petroleum products pipeline system revenues of $1.0 million primarily attributable to lower volumes, partially offset by higher fees for leased storage and additional demand for our renewable fuels services. Lower volumes resulted from reduced shipments of diesel fuel reflecting unfavorable farming conditions in first quarter 2008 and lower gasoline shipments reflecting higher product prices and increased competition created by regional product pricing anomalies;

•

an increase in petroleum products terminals revenues of $1.9 million due to higher revenues at both our marine and inland terminals. Marine revenues increased primarily due to operating results from expansion projects, such as additional storage tanks at our Galena Park, Texas facility that were placed into service throughout 2007. Inland revenues benefitted from higher additive fees that offset lower throughput volumes; and

•

an increase in ammonia pipeline system revenues of $0.5 million due to higher average tariffs and additional shipments.

Operating expenses decreased by $5.4 million resulting from lower expenses for each of our business segments as described below:

•

a decrease in petroleum products pipeline system expenses of $0.6 million primarily due to lower property taxes in the current period, as well as more favorable product overages, which reduce operating expenses, partially offset by higher maintenance spending and additional personnel costs in first quarter 2008;

•

a decrease in petroleum products terminals expenses of $1.5 million primarily related to gains recognized from insurance proceeds received in first quarter 2008 associated with hurricane damages sustained during 2005 and higher first quarter 2007 expenses due to product downgrade charges resulting from the accidental blending of a small amount of product. Higher personnel costs and maintenance expenses in the current period partially offset these favorable variances; and

•

a decrease in ammonia pipeline system expenses of $3.2 million primarily due to lower environmental and maintenance costs. The 2007 period was negatively impacted by environmental charges related to a 2004 pipeline release and higher system integrity costs associated with high consequence area testing procedures.

Product sales revenues primarily resulted from a third-party product supply agreement, our petroleum products blending operation, terminal product gains and transmix fractionation. Revenues from product sales were $201.7 million for the three months ended March 31, 2008 while product purchases were $177.6 million, resulting in gross margin from these transactions of $24.1 million. The gross margin resulting from product sales and purchases for the 2008 period increased $9.4 million compared to gross margin for the 2007 period of $14.7 million, resulting from product sales for the three months ended March 31, 2007 of $148.7 million and product purchases of $134.0 million. The increase in 2008 margins was primarily attributable to higher product prices and the sale of additional product overages by our petroleum products terminal segment during the current period. Please read Significant Events above for discussion of our recent assignment of the third-party supply agreement effective March 2008.

The 2008 period benefited from a $26.5 million gain on the assignment of our third-party supply agreement. Please read Significant Events above for further discussion of this assignment.

Operating margin increased $42.4 million, primarily due to the gain on assignment of our third-party supply agreement, higher gross margin from product sales as well as higher revenues and lower expenses related to each of our business segments.

Depreciation and amortization increased by $1.7 million related to expansion capital projects over the past year.

Interest expense, net of interest capitalized and interest income, was $11.3 million for the three months ended March 31, 2008 compared to $13.6 million for the three months ended March 31, 2007. Our average debt outstanding, excluding fair value adjustments for interest rate hedges, increased to $960.0 million during first quarter 2008 from $857.4 million during first quarter 2007 due to borrowings for capital expenditures in the current quarter. However, the weighted-average interest rate on our borrowings, after giving effect to the impact of associated fair value hedges, decreased to 5.3% for the 2008 period from 7.0% for the 2007 period primarily due to the refinancing of our pipeline notes during second quarter 2007 at a lower interest rate and because of lower variable rates on our revolving credit facility during first quarter 2008. Further, the amount of interest capitalized increased due to our higher level of capital spending over the last year.

Net income was $93.3 million for the three months ended March 31, 2008 compared to $49.7 million for the three months ended March 31, 2007, an increase of $43.6 million, or 88%.

Liquidity and Capital Resources

Cash Flows and Capital Expenditures

Net cash provided by operating activities was $95.9 million and $32.4 million for the three months ended March 31, 2008 and 2007, respectively. The $63.5 million increase from 2007 to 2008 was primarily attributable to:

•

an increase in net income of $17.1 million, excluding the $26.5 million non-cash gain on assignment of the supply agreement;

•

an $8.5 million decrease in accounts receivable and other accounts receivable in 2008 versus an $8.6 million increase in 2007 due primarily to the timing of payments received from our customers;

•

a $20.3 million decrease in inventories in 2008 versus an $11.9 million decrease in inventories in 2007. The decrease in inventories during 2008 is principally due to the sale of petroleum products inventory we maintained prior to the assignment of our product supply agreement to a third party in March 2008;

•

a $6.3 million decrease in accounts payable in 2008 versus a $16.8 million decrease in accounts payable in 2007 due primarily to the timing of invoices received from our vendors and suppliers; and

•

a $6.6 million increase in accrued product purchases in 2008 versus a $17.3 million decrease in accrued product purchases in 2007 due primarily to the timing of invoices received from our vendors and suppliers.

•

These increases were partially offset by a decrease in the supply agreement deposit in 2008 of $18.5 million as a result of the assignment of our product supply agreement to a third party in March 2008.

Net cash used by investing activities for the three months ended March 31, 2008 and 2007 was $70.5 million and $49.9 million, respectively. During 2008, we spent $54.9 million for capital expenditures, which included $7.8 million for maintenance capital and $47.1 million for expansion capital. Additionally, we acquired a petroleum products terminal in Bettendorf, Iowa for $12.0 million in first quarter 2008. During 2007, we spent $39.4 million for capital expenditures, which included $6.3 million for maintenance capital and $33.1 million for expansion capital.

Net cash provided (used) by financing activities for the three months ended March 31, 2008 and 2007 was $(25.4) million and $11.2 million, respectively. During 2008, we paid distributions of $63.8 million to our unitholders and general partner while net borrowings on our revolving credit facility primarily to finance capital expansion projects and acquisitions were $33.5 million. During 2007, net borrowings on our revolving credit facility were $66.8 million, which were mostly offset by distributions of $56.3 million paid to our unitholders and general partner.

During first quarter 2008, we paid $63.8 million in cash distributions to our unitholders and general partner. Based on the declared quarterly distribution of $0.6725 per unit associated with the first quarter of 2008, we will pay $65.8 million in distributions during second quarter 2008. If we continue to pay cash distributions at this level and the number of outstanding units remains the same, total cash distributions of $263.2 million would be paid on an annual basis. Of this amount, $83.6 million, or 32%, would be paid to our general partner on its approximate 2% ownership interest and incentive distribution rights.

Capital Requirements

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

•

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

•

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

During first quarter 2008, our maintenance capital spending was $7.5 million, excluding $0.3 million of spending that would have been covered by indemnifications settled in May 2004. We have received the entire $117.5 million under our indemnification settlement agreement. Please see Environmental below for additional description of this agreement.

For 2008, we expect to incur maintenance capital expenditures for our existing businesses of approximately $35.0 million, excluding $10.0 million of maintenance capital that has already been reimbursed to us through our indemnification settlement and third-party reimbursements.

In addition to maintenance capital expenditures, we also incur expansion capital expenditures at our existing facilities. During first quarter 2008, we spent cash of approximately $47.1 million for organic growth projects and $12.0 million to acquire a petroleum products terminal already connected to our petroleum products pipeline system. Based on the progress of expansion projects already underway, we expect to spend approximately $250 million of growth capital during 2008, with an additional $20 million thereafter to complete these projects. The 2008 estimate includes $10.0 million we plan to spend to acquire a petroleum products terminal already connected to our pipeline system in Wrenshall, Minnesota, which is expected to close by August 1, 2008, subject to regulatory approval.

Liquidity

As of March 31, 2008, total debt reported on our consolidated balance sheet was $952.2 million. The difference between this amount and the $947.0 million face value of our outstanding debt results from adjustments related to fair value hedges and unamortized discounts on debt issuances.

Revolving credit facility. Our current revolving credit facility has a total borrowing capacity of $550.0 million and a maturity date of September 2012. Borrowings under the facility are unsecured and incur interest at LIBOR plus a spread that ranges from 0.3% to 0.8% based on our credit ratings and on amounts outstanding under the facility. Additionally, a commitment fee is assessed at a rate from 0.05% to 0.125%, depending on our credit rating. As of March 31, 2008, $197.0 million was outstanding under this facility, and $3.3 million of the facility was obligated for letters of credit. The obligations for letters of credit are not reflected as debt on our consolidated balance sheets. As of March 31, 2008, the weighted-average interest rate on borrowings outstanding under this facility was 3.1%.

6.45% notes due 2014. In May 2004, we sold $250.0 million of 6.45% notes due 2014 in an underwritten public offering at 99.8% of par. Including the impact of amortizing the gains realized on pre-issuance hedges associated with these notes, the effective interest rate of these notes is 6.3%.

5.65% notes due 2016. In October 2004, we sold $250.0 million of 5.65% notes due 2016 in an underwritten public offering. The notes were issued at 99.9% of par. Including the impact of amortizing the losses realized on pre-issuance hedges associated with these notes and the interest rate swap which effectively converts $100.0 million of these notes from fixed-rate to floating-rate debt, the weighted-average interest rate on the notes at March 31, 2008 was 4.9%.

6.40% notes due 2037. In April 2007, we sold $250.0 million of 6.40% notes due 2037 in an underwritten public offering at 99.6% of par to refinance outstanding pipeline notes. Including the impact of amortizing the gains realized on pre-issuance hedges associated with these notes, the effective interest rate on these notes is 6.3%.

Interest rate derivatives. We utilize interest rate derivatives to help us manage interest rate risk. We were engaged in the following interest rate derivative transactions as of March 31, 2008:

•

In October 2004, we entered into a $100.0 million interest rate swap agreement to hedge against changes in the fair value of a portion of our 5.65% notes due 2016. This agreement effectively changes the interest rate on $100.0 million of those notes to a floating rate of six-month LIBOR plus 0.6%, with LIBOR set in arrears. This swap agreement expires on October 15, 2016, the maturity date of the 5.65% notes; and

•

In January 2008, we entered into a total of $200.0 million of forward starting interest rate swap agreements to hedge against variability of future interest payments on debt that we anticipated issuing no later than June 2008. Proceeds of the anticipated debt issuance were expected to be used to refinance borrowings on our revolving credit facility. The interest rate swap agreements had a 10-year term, and the effective date of the agreements was June 30, 2008. As a result of changes in market conditions, we terminated these agreements in April 2008 and received $0.2 million in connection with the termination.

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

Off-Balance Sheet Arrangements

None.

Environmental

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

Indemnification settlement. Prior to May 2004, a former affiliate provided indemnifications to us for assets we had acquired from it. In May 2004, we entered into an agreement with our former affiliate under which our former affiliate agreed to pay us $117.5 million to release it from those indemnification obligations, which we have collected. As of March 31, 2008, known liabilities that would have been covered by these indemnifications were $42.4 million. Through March 31, 2008, we have spent $47.7 million of the indemnification settlement proceeds for indemnified matters, including $20.4 million of capital costs. We have not reserved the cash received from this indemnity settlement but have used it for our various other cash needs, including expansion capital spending.

Petroleum products EPA issue. In July 2001, the EPA, pursuant to Section 308 of the Clean Water Act (the “Act”), served an information request to a former affiliate with regard to petroleum discharges from its pipeline operations. That inquiry primarily focused on the petroleum products pipeline system that we subsequently acquired. The response to the EPA’s information request was submitted during November 2001. In March 2004, we received an additional information request from the EPA and notice from the U.S. Department of Justice (“DOJ”) that the EPA had requested the DOJ to initiate a lawsuit alleging violations of Section 311(b) of the Act in regards to 32 releases. The DOJ stated that the maximum statutory penalty for the releases was in excess of $22.0 million, which assumed that all releases are violations of the Act and that the EPA would impose the maximum penalty. The EPA further indicated that some of those releases may have also violated the Spill Prevention Control and Countermeasure requirements of Section 311(j) of the Act and that additional penalties may be assessed. In addition, we may incur additional costs associated with these releases if the EPA were to successfully seek and obtain injunctive relief. We responded to the March 2004 information request in a timely manner and have entered into an agreement that provides both parties an opportunity to negotiate a settlement prior to initiating litigation. We have accrued an amount for this matter based on our best estimates that is less than $22.0 million. Most of the amount we have accrued was included as part of the environmental indemnification settlement we reached with our former affiliate (see Indemnification Settlement description above). The DOJ and EPA have added to their original demand a release that occurred in the second quarter of 2005 from our petroleum products pipeline near our Kansas City, Kansas terminal and a release that occurred in the first quarter of 2006 from our petroleum products pipeline near Independence, Kansas. Our accrual includes these additional releases. We are in ongoing negotiations with the EPA; however, we are unable to determine what our ultimate liability could be for these matters. Adjustments to our recorded liability, which could occur in the near term, could be material to our results of operations and cash flows.

Ammonia EPA issue. In February 2007, we received notice from the DOJ that the EPA had requested the DOJ to initiate a lawsuit alleging violations of Sections 301 and 311 of the Act with respect to two releases of anhydrous ammonia from the ammonia pipeline owned by us and operated by a third party. The DOJ stated that the maximum statutory penalty for alleged violations of the Act for both releases combined was approximately $13.2 million. The DOJ also alleged that the third-party operator of our ammonia pipeline was liable for penalties pursuant to Section 103 of the Comprehensive Environmental Response, Compensation and Liability Act for failure to report the releases on a timely basis, with the statutory maximum for those penalties as high as $4.2 million for which the third-party operator has requested indemnification. In March 2007, we also received a demand from the third-party operator for defense and indemnification in regards to a DOJ criminal investigation regarding whether certain actions or omissions of the third-party operator constituted violations of federal criminal statutes. The third-party operator has subsequently settled this criminal investigation with the DOJ by paying a $1.0 million fine. We believe that we do not have an obligation to indemnify or defend the third-party operator against the DOJ criminal investigations. The DOJ stated in its notice to us that it does not expect us or the third-party operator to pay the penalties at the statutory maximum; however, it may seek injunctive relief if the parties cannot agree on any necessary corrective actions. We have accrued an amount for these matters based on our best estimates that is less than the maximum statutory penalties. We are currently in discussions with the EPA, DOJ and the third-party operator regarding these two releases; however, we are unable to determine what our ultimate liability could be for these matters. Adjustments to our recorded liability, which could occur in the near term, could be material to our results of operations and cash flows.

PCB impacts. We have identified polychlorinated biphenyls (“PCB”) impacts at two of our petroleum products terminals that we are in the process of assessing. It is possible that in the near term the PCB contamination levels could require corrective actions. We are unable at this time to determine what these corrective actions and associated costs might be. The costs of any corrective actions associated with these PCB impacts could be material to our results of operations and cash flows.

Floating Roof Emissions. Operational needs require us, at various times, to empty our tanks. When our tanks with internal floating roofs are emptied, the tanks emit petroleum vapors. Historically, these emissions were not reported or addressed in facility air permits because the EPA had no approved method to quantify the emissions event. However, the EPA adopted the American Petroleum Institute's methodology for calculating these particular emissions as their approved standard in 2006. We have evaluated these emission standards and have concluded that they will not have a material impact on our current operational practices, emission control and reporting requirements, emission fees and existing air permits.

Other Items

Pipeline tariff increase. The Federal Energy Regulatory Commission regulates the rates charged on interstate common carrier pipeline operations primarily through an index methodology, which establishes the maximum amount by which tariffs can be adjusted. The current approved methodology is the annual change in the producer price index for finished goods (“PPI-FG”) plus 1.3%. Based on an actual change in PPI-FG of approximately 3.0% during 2006, we increased virtually all of our published tariffs by the allowed adjustment of approximately 4.3% effective July 1, 2007. The preliminary estimate for the change in PPI-FG for 2007 is approximately 3.9%. Once PPI-FG is finalized, we expect to increase virtually all of our tariffs by the resulting PPI-FG plus 1.3% on July 1, 2008.

Ammonia operating agreement. A third-party pipeline company currently provides the operating services and a portion of the G&A services for our ammonia pipeline system under an operating agreement with us. This pipeline company has provided notice to us that it will not renew its operating agreement with us upon its scheduled expiration date of June 30, 2008. We plan to assume operating responsibility of our ammonia pipeline at that time. We do not expect these incremental costs will have a material impact on our financial results.

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

Unrecognized product gains. Our petroleum products terminals operations generate product overages and shortages. When our petroleum products terminals experience net product shortages, we recognize expense for those losses in the periods in which they occur. When our petroleum products terminals experience net product overages, we have product on hand for which we have no cost basis. Therefore, these net overages are not recognized in our financial statements until the associated barrels are either sold or used to offset product losses. The combined net unrecognized product overages for our petroleum products terminals operations had a market value of approximately $10.0 million as of March 31, 2008. However, the actual amounts we will recognize in future periods will depend on product prices at the time the associated barrels are either sold or used to offset future product losses.

Affiliate transactions. Since December 2005, the general partner of Magellan Midstream Holdings, L.P. (“MGG”) has provided the employees necessary to conduct our business operations and we reimburse it for these costs. In addition, MGG has agreed to reimburse us for G&A expenses, excluding equity-based compensation, in excess of a defined G&A cap. For the three months ended March 31, 2008, we were allocated operating expenses from MGG’s general partner of $20.9 million and G&A expenses of $11.9 million. For the three months ended March 31, 2007, we were allocated operating expenses from MGG’s general partner of $19.2 million and G&A expenses of $10.4 million. MGG reimbursed us G&A costs in excess of the defined G&A cap of $0.4 million for the three months ended March 31, 2008 and $0.3 million for the three months ended March 31, 2007. We do not expect to receive reimbursement for excess G&A expenses beyond 2008.

We own a 50% interest in a crude oil pipeline company. We earn a fee to operate this pipeline which was $0.2 million for both the three months ended March 31, 2008 and 2007. We report these fees as affiliate management fee revenue on our consolidated statements of income.

Because our distributions have exceeded target levels as specified in our partnership agreement, MGG indirectly receives approximately 50% of any incremental cash distributed per limited partner unit. As of March 31, 2008, the executive officers of our general partner collectively own approximately 5% of MGG Midstream Holdings, L.P., which currently owns 14% of MGG, and therefore also indirectly benefit from these distributions. Assuming we have sufficient available cash to continue to pay distributions on our outstanding units for four quarters at our current quarterly distribution level of $0.6725 per unit, MGG would receive annual distributions of approximately $83.6 million on its combined 2% general partner interest and incentive distribution rights.

New Accounting Pronouncements

On March 26, 2008, the Financial Accounting Standards Board (“FASB”) ratified Emerging Issues Task Force (“EITF”) Issue No. 07-4, Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships. Under EITF No. 07-4, the excess of distributions over earnings and/or excess of earnings over distributions for each period are required to be allocated to the entities’ general partner based solely on the general partner’s ownership interest at the time. For purposes of calculating earnings per unit, our current accounting practice is to allocate net income to the general partner based on the general partner’s share of total or theoretical distributions, as appropriate, including incentive distribution rights. The effect of adopting this EITF will be: (i) for periods when net income exceeds distributions, our reported earnings per limited partner unit will be higher than under our current accounting practice and (ii) for periods when distributions exceed net income, our reported earnings per limited partner unit will be lower than under our current accounting practice. These differences will be material for those periods where there are material differences between our net income and the distributions we pay. For example, had we applied EITF 07-4 to the current reporting period, basic and diluted earnings per limited partner unit would have increased from $0.89 to $1.10. This EITF is effective beginning January 1, 2009, including all interim periods after that date. Early application is not permitted. We intend to adopt this EITF in January 2009 for purposes of both calculating earnings per unit and determining the capital balances of our general and limited partners. This EITF is required to be applied retrospectively; therefore, we will restate prior period earnings per limited partner unit in all published financial reports after January 1, 2009, as applicable.

On March 19, 2008, the FASB issued Statement of Financial Accounting Standard (“SFAS”) No. 161, Disclosures about Derivative Instruments and Hedging Activities. SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, established, among other things, the disclosure requirements for derivative instruments and for hedging activities. SFAS No. 161 amends SFAS No. 133, requiring qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts and gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008.

On February 14, 2008, the FASB issued FASB Staff Position (“FSP”) No. 157-1, Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13. FSP No. 157-1 amends SFAS No. 157, Fair Value Measurements, to exclude SFAS No. 13, Accounting for Leases, and other accounting pronouncements that address fair value measurements for purposes of lease classification or measurement under Statement 13. However, this scope exception does not apply to assets acquired and liabilities assumed in a business combination that are required to be measured at fair value under SFAS No. 141, Business Combinations, or SFAS No. 141 (revised 2007), Business Combinations, regardless of whether those assets and liabilities are related to leases. This FSP is effective with the initial adoption of SFAS No. 157, which we adopted on January 1, 2007. The adoption of this FSP did not have a material effect on our results of operations, financial position or cash flows.

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

As of March 31, 2008, we had $197.0 million outstanding on our variable rate revolving credit facility. We had no other variable rate debt outstanding; however, because of an interest rate swap agreement discussed below, we are exposed to interest rate market risk on an additional $100.0 million of our debt. Considering this swap agreement and our variable-rate revolving credit facility, our annual interest expense would change by $0.4 million if LIBOR were to change by 0.125%.

In January 2008, we entered into a total of $200.0 million of forward starting interest rate swap agreements effective June 30, 2008 to hedge against the variability of future interest payments on debt that we anticipated issuing no later than June 2008.

During October 2004, we entered into an interest rate swap agreement to hedge against changes in the fair value of a portion of the $250.0 million of senior notes due 2016. We have accounted for this interest rate hedge as a fair value hedge. The notional amount of the interest rate swap agreement is $100.0 million. Under the terms of the agreement, we receive 5.65% (the interest rate of the $250.0 million senior notes) and pay LIBOR plus 0.6%. This hedge effectively converts $100.0 million of our 5.65% fixed-rate debt to floating-rate debt. The interest rate swap agreement began on October 15, 2004 and expires on October 15, 2016. Payments settle in April and October of each year with LIBOR set in arrears. We recognized an other non-current asset of $6.9 million at March 31, 2008 for the fair value of this agreement.

We also 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, 2008, we had commitments under forward purchase contracts for product purchases that will be accounted for as normal purchases totaling approximately $68.4 million, and we had commitments under forward sales contracts for product sales that will be accounted for as normal sales totaling approximately $106.4 million.

ITEM 4.

CONTROLS AND PROCEDURES

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

Forward-Looking Statements

Certain matters discussed in this Quarterly Report on Form 10-Q include forward-looking statements that discuss our expected future results based on current and pending business operations.

Forward-looking statements can be identified by words such as “anticipates,” “believes,” “expects,” “estimates,” “forecasts,” “projects” and other similar expressions. Although we believe our forward-looking statements are based on reasonable assumptions, statements made regarding future results are not guarantees of future performance and are subject to numerous assumptions, uncertainties and risks that may cause future results to be materially different from the results stated or implied in such forward-looking statements included in this report.

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

•

price fluctuations for natural gas liquids and refined petroleum products;

•

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

•

weather patterns materially different than historical trends;

•

development of alternative energy sources;

•

increased use of biofuels such as ethanol and biodiesel;

•

changes in demand for storage in our petroleum products terminals;

•

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

•

our ability to manage interest rate and commodity price exposures;

•

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

•

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

•

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

•

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

•

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

•

an increase in the competition our operations encounter;

•

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

•

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

•

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

•

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

•

changes in general economic conditions in the United States;

•

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

•

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

•

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

•

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

•

the condition of the capital markets in the United States;

•

the effect of changes in accounting policies;

•

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

•

the ability of third parties to pay the amounts owed to us;

•

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

•

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

•

supply disruption; and

•

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

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

PART II

OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

In July 2001, the Environmental Protection Agency (“EPA”), pursuant to Section 308 of the Clean Water Act (the “Act”), served an information request to a former affiliate with regard to petroleum discharges from its pipeline operations. That inquiry primarily focused on the petroleum products pipeline system that we subsequently acquired. The response to the EPA’s information request was submitted during November 2001. In March 2004, we received an additional information request from the EPA and notice from the U.S. Department of Justice (“DOJ”) that the EPA had requested the DOJ to initiate a lawsuit alleging violations of Section 311(b) of the Act in regards to 32 releases. The DOJ stated that the maximum statutory penalty for the releases was in excess of $22.0 million, which assumed that all releases are violations of the Act and that the EPA would impose the maximum penalty. The EPA further indicated that some of those releases may have also violated the Spill Prevention Control and Countermeasure requirements of Section 311(j) of the Act and that additional penalties may be assessed. In addition, we may incur additional costs associated with these releases if the EPA were to successfully seek and obtain injunctive relief. We responded to the March 2004 information request in a timely manner and have entered into an agreement that provides both parties an opportunity to negotiate a settlement prior to initiating litigation. We have accrued an amount for this matter based on our best estimates that is less than $22.0 million. Most of the amount we have accrued was included as part of the environmental indemnification settlement we reached with our former affiliate. The DOJ and EPA have added to their original demand a release that occurred in the second quarter of 2005 from our petroleum products pipeline near our Kansas City, Kansas terminal and a release that occurred in the first quarter of 2006 from our petroleum products pipeline near Independence, Kansas. Our accrual includes these additional releases. We are in ongoing negotiations with the EPA; however, we are unable to determine what our ultimate liability could be for these matters. Adjustments to our recorded liability, which could occur in the near term, could be material to our results of operations and cash flows.

In February 2007, we received notice from the DOJ that the EPA had requested the DOJ to initiate a lawsuit alleging violations of Sections 301 and 311 of the Act with respect to two releases of anhydrous ammonia from the ammonia pipeline owned by us and operated by a third party. The DOJ stated that the maximum statutory penalty for alleged violations of the Act for both releases combined was approximately $13.2 million. The DOJ also alleged that the third party operator of our ammonia pipeline was liable for penalties pursuant to Section 103 of the Comprehensive Environmental Response, Compensation and Liability Act for failure to report the releases on a timely basis, with the statutory maximum for those penalties as high as $4.2 million. In March 2007, we received a demand from the third party operator for defense and indemnification in regards to a DOJ criminal investigation regarding whether certain actions or omissions of the third party operator constituted violations of federal criminal statutes. We do not believe we have an obligation to indemnify or defend the third party operator against the DOJ criminal investigations. The DOJ stated in its notice to us that it does not expect us or the third party operator to pay the penalties at the statutory maximum; however, it may seek injunctive relief if the parties cannot agree on any necessary corrective actions. We have accrued an amount for this matter based on our best estimates that is less than the maximum statutory penalties. We are currently in discussions with the EPA, DOJ and third-party operator regarding these two releases; however, we are unable to determine what our ultimate liability could be for this matter.

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

ITEM 1A.

RISK FACTORS

In addition to the information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2007, which could materially affect our business, financial condition or future results. The risks described 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.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

ITEM 5.

OTHER INFORMATION

None.

ITEM 6.

EXHIBITS



Exhibit 12.1	–	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 6, 2008.


MAGELLAN MIDSTREAM PARTNERS, L.P.

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

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

INDEX TO EXHIBITS


EXHIBIT NUMBER		DESCRIPTION
12.1		Ratio of earnings to fixed charges.

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

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

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

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

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